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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, 1995
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)
270 Peachtree Street, N.W.
Atlanta, Georgia 30303
(770) 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 classes or series of securities registered pursuant to
Section 12(b) of the Act is registered on the New York Stock Exchange.
Title of each class Registrant
------------------- ----------
Common Stock, $5 par value The Southern Company
-------------------------------------------------
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
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
Subsidiary obligated mandatorily redeemable
preferred securities, $25 stated value*
9% Monthly Income Preferred Securities, Series A
First mortgage bonds
6 1/8% Series due 1999 6 7/8% Series due 2002
----------------------------------------------------
Depositary preferred shares, each representing Mississippi Power Company
one-fourth of a share of preferred stock,
cumulative, $100 par value
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
*Issued by Georgia Power Capital, L.P., and guaranteed to the extent Georgia
Power Capital has funds by Georgia Power Company.
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Securities registered pursuant to Section 12(g) of the Act:
Title of each class Registrant
------------------- ----------
Preferred stock, cumulative, $100 par value Alabama Power Company
4.20% Series 4.64% Series 5.96% Series
4.52% Series 4.72% Series 6.88% Series
4.60% Series 4.92% 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 $4.72 Series $5.64 Series
$4.60 Series (1962) $4.92 Series $6.48 Series
$4.60 Series (1963) $4.96 Series $6.60 Series
$4.60 Series (1964) $5.00 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
Class A preferred, cumulative, $10 par, $25 stated capital
6.72% Series 7.00% Series 7.30% 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. (X)
Aggregate market value of voting stock held by non-affiliates of The
Southern Company at February 29, 1996: $16.0 billion. Each of such other
registrants is a wholly-owned subsidiary of The Southern Company and has no
voting stock other than its common stock. A description of registrants' common
stock follows:
Documents incorporated by reference: specified portions of The Southern
Company's Proxy Statement relating to the 1996 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-8
Competition................................................ I-12
Regulation................................................. I-13
Rate Matters............................................... I-15
Employee Relations......................................... I-17
Item 2 Properties................................................... I-18
Item 3 Legal Proceedings............................................ I-23
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 Matters........................................ II-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
i
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
Communications............... Southern Communications Services, Inc.
Dalton....................... City of Dalton, Georgia
DOE.......................... United States Department of Energy
Edelnor...................... Empresa 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
IRS.......................... Internal Revenue Service
JEA.......................... Jacksonville Electric Authority
MEAG......................... Municipal Electric Authority of Georgia
MISSISSIPPI.................. Mississippi Power Company
Mobile Energy................ Mobile Energy Services Company, L.L.C.
NRC.......................... Nuclear Regulatory Commission
OPC.......................... Oglethorpe Power Corporation
operating affiliates......... ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH
PSC.......................... Public Service Commission
RUS.......................... Rural Utility Service (formerly Rural
Electrification Administration)
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 Development......... The Southern Development and Investment Group,
Inc.
Southern Nuclear............. Southern Nuclear Operating Company, Inc.
SOUTHERN system.............. SOUTHERN, the operating affiliates, SEGCO, SEI,
Southern Nuclear, SCS, Communications,
Southern Development and other subsidiaries
SWEB......................... South Western Electricity plc (United Kingdom)
TVA.......................... Tennessee Valley Authority
ii
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 the State 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, Communications,
Southern Nuclear, SCS (the system service company), Southern Development and
other direct and indirect subsidiaries. SEI designs, builds, owns and operates
power production and delivery 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 under "New Business Development."
Communications provides digital wireless communications services to SOUTHERN's
operating affiliates and also markets these services to the public within the
Southeast. Southern Nuclear provides services to the Southern electric system's
nuclear plants. Southern Development explores, develops and markets energy
management services and other business lines relating to SOUTHERN's core
business of generating and distributing energy.
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.
I-1
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 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 SOUTHERN, 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, 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. SEI, Southern
Development and Communications have also secured from the operating affiliates
certain services which are furnished at cost.
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, if approved, 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 subsidiaries.
SEI's primary business focus is international and domestic cogeneration, the
independent power market, and the privatization and development of generation,
transmission and distribution facilities in the international market. During
1995, SEI also entered the business of power marketing.
Reference is made to Note 15 to the financial statements of SOUTHERN in Item
8 herein for additional information regarding SOUTHERN's business segments and
geographic areas.
In September 1995, SOUTHERN acquired SWEB, one of the United Kingdom's 12
regional electric distribution companies, for approximately $1.8 billion. SWEB's
main business is the distribution of electricity to customers in the Southwest
of England. Based in Bristol, SWEB serves approximately 1.3 million customers in
an area roughly the size of Connecticut, with almost 2 million residents. SWEB
is also a supplier of electricity to franchise customers in its authorized area
and to customers in the competitive second-tier market. Through its 7.7% equity
investment in Teesside Power Limited, a combined cycle gas turbine plant with a
capacity of 1,875 megawatts, SWEB is involved in power generation. In addition,
SWEB is involved in certain non-regulated activities which include gas supply
and telecommunications. For additional information regarding the acquisition of
SWEB, reference is made to Note 14 to SOUTHERN's financial statements in Item 8
herein.
I-2
See Item 2 - PROPERTIES - "Other Electric Generation Facilities" herein for
additional information regarding SEI projects.
SEI and Southern Development render consulting services and market SOUTHERN
system expertise in the United States and throughout the world. They contract
with other public utilities, commercial concerns and government agencies for the
rendition of services and the licensing of intellectual property. More
specifically, Southern Development is focusing on new and existing programs to
enhance customer satisfaction and efficiency and stockholder value, such as:
Good Cents, an energy efficiency program for electric utility customers;
EnerLink, a group of energy management products and services for large
commercial and industrial electricity users; Flywheel, an energy storage device;
PowerCall Security, a home security system; other energy management programs
under development; and telecommunications operations related to energy
management programs.
By the end of 1995, the construction of Communications' wireless
communications system was essentially complete, and Communications began serving
SOUTHERN's operating affiliates and marketing its services to non-affiliates
within the Southeast. The system covers 122,000 square miles and combines the
functions of two-way radio dispatch, cellular phone, short text and numeric
messaging and wireless data transfer.
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, these activities also involve a higher degree of risk.
SOUTHERN expects to make substantial investments over the period 1996-1998 in
these and other new businesses.
Certain Factors Affecting the Industry
Various factors are currently affecting the electric utility industry in
general, including increasing competition and the regulatory changes related
thereto, costs required to comply with environmental regulations, and the
potential for new business opportunities (with their associated risks) outside
of traditional rate-regulated operations. The effects of these and other factors
on the SOUTHERN system are described herein; particular reference is made to
Item 1 - BUSINESS - "New Business Development," "Competition" and "Environmental
Regulation."
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 1996 through
1998 by the operating affiliates, SEGCO, SCS, Southern Nuclear, Communications
and SEI are estimated as follows: (in millions)
---------------------------------------------------------
1996 1997 1998
-------- --------- ---------
ALABAMA $ 491 $ 446 $ 479
GEORGIA 530 537 529
GULF 71 67 71
MISSISSIPPI 67 62 53
SAVANNAH 33 30 23
SEGCO 13 6 7
SCS 29 16 10
Southern Nuclear 1 1 1
Communications 26 48 6
SEI* 213 218 123
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SOUTHERN system $1,474 $1,431 $1,302
========================================================
*These construction estimates do not include amounts which may be expended
by SEI on future power production projects or by any subsidiaries created to
effect such future projects.
Reference is made to Note 4 to the financial statements of each registrant
(except GULF) in Item 8 herein for the amounts of AFUDC included in the above
estimates. GULF's estimates include AFUDC of $75,000 in 1996 and no AFUDC in
1997 and 1998. (See also Item 1 - BUSINESS - "Financing Programs" herein.)
I-3
*Communications, SCS and Southern Nuclear plan capital additions to general
plant in 1996 of $26 million, $29 million and $1 million, respectively, while
SEGCO plans capital additions of $13 million to generating facilities. SEI plans
capital additions of $106 million to generating facilities and $107 million to
distribution facilities. These estimates do not reflect the possibility of SEI's
securing a contract(s) to buy or build additional generating facilities.
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
projections; 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.
The operating affiliates do not have any new baseload generating plants
under construction. However, within the service area, the construction of
combustion turbine peaking units with an aggregate capacity of approximately 600
megawatts is planned to be completed by 1998. In addition, significant
construction related to transmission and distribution facilities and the
upgrading and extension of the useful lives of generating plants will continue.
In 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 Plant
For information regarding GEORGIA's Rocky Mountain Plant, including a joint
ownership agreement with OPC and the uncertain recovery of GEORGIA's costs in
this plant, reference is made to Note 3 to SOUTHERN's and to GEORGIA's financial
statements in Item 8 herein.
I-4
Financing Programs
SOUTHERN may require additional equity capital in 1996. The amount and timing of
additional equity capital to be raised in 1996, as well as subsequent years,
will be contingent on SOUTHERN's investment opportunities, primarily through
SEI. Equity capital can be provided from any combination of public offerings,
private placements, or SOUTHERN's stock plans. The operating affiliates'
construction programs are expected to be financed primarily from internal
sources. Short-term debt will be utilized as appropriate at SOUTHERN and the
operating affiliates. 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 if market conditions permit.
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. The ability to issue securities in the future will depend on
coverages at that time. Currently each of the operating affiliates expects to
have adequate coverage ratios for anticipated requirements through at least
1998.
The amounts of securities representing short-term unsecured indebtedness
allowable under the respective charters, and the maximum amounts of short-term
or term-loan indebtedness authorized by the appropriate regulatory authorities,
are shown in the following table:
======================================================
Short-Term Unsecured Indebtedness
------------------------------------------------------
Allowable
Under Charter
at December 31, 1995
Percent of
Secured
Indebtedness
and Other
Amount Capital (2)
------------- -------------------
(Millions)
ALABAMA $ 1,123 20%
GEORGIA 1,677 20
GULF 88 10
MISSISSIPPI 149 20
SAVANNAH 68 20
SOUTHERN (1) (1)
------------------------------------------------------
======================================================
Short-Term or Term-Loan Indebtedness
------------------------------------------------------
Maximum Regulatory
Authorization
Outstanding at
Amount December 31, 1995
------------ ---------------------
(Millions)
ALABAMA $ 750 (3) $390
GEORGIA 1,700 (4) 400
GULF 150 (3) 118
MISSISSIPPI 350 (3) 55
SAVANNAH 90 (4) 4
SOUTHERN 2,000 (3) 619
--------------------------------------------------------
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 increased from 10% of secured indebtedness
and other capital to 20% thereof. These approved increases are reflected in the
above table.
I-5
(3) ALABAMA's authority is based on authorization received from the Alabama
PSC, which expires December 31, 1998. No SEC authorization is required for
ALABAMA. GULF, MISSISSIPPI 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 December 31, 1996, December 31,
2002 and March 31, 2001, respectively.
(4) GEORGIA and SAVANNAH have received SEC authorization to issue from time
to time short-term and term-loan notes to banks and commercial paper to dealers
in the amounts shown through December 31, 2002. Authorization for term-loan
indebtedness is also required by and has been received from the Georgia PSC.
Currently, GEORGIA and SAVANNAH have remaining authority from the Georgia PSC of
$809 million and $40 million expiring December 31, 1996 and June 30, 1996,
respectively.
Reference is made to Note 5 to the financial statements for SOUTHERN,
ALABAMA, GULF, MISSISSIPPI and SAVANNAH and Note 9 to the financial statements
for GEORGIA in Item 8 herein for information regarding the registrants' credit
arrangements.
I-6
Fuel Supply
The operating affiliates' and SEGCO's supply of electricity is derived
predominantly from coal. The sources of generation for the years 1993 through
1995 and the estimates for 1996 are shown below:
Oil and
ALABAMA Coal Nuclear Hydro Gas
----------------------------------------
1993 70% 22% 8% *%
1994 68 23 9 *
1995 73 19 8 *
1996 73 20 7 *
GEORGIA
1993 77 20 3 *
1994 75 22 3 *
1995 74 22 3 1
1996 76 21 2 1
GULF
1993 99 ** ** 1
1994 100 ** ** *
1995 99 ** ** 1
1996 99 ** ** 1
MISSISSIPPI
1993 90 ** ** 10
1994 85 ** ** 15
1995 79 ** ** 21
1996 81 ** ** 19
SAVANNAH
1993 83 ** ** 17
1994 91 ** ** 9
1995 80 ** ** 20
1996 83 ** ** 17
SEGCO
1993 100 ** ** *
1994 100 ** ** *
1995 100 ** ** *
1996 100 ** ** *
SOUTHERN system***
1993 78 17 4 1
1994 75 19 5 1
1995 77 17 4 2
1996 78 17 4 1
---------------------------------------------------------
*Less than 0.5%.
**Not applicable.
***Amounts shown for the SOUTHERN system are weighted
averages of the operating affiliates and SEGCO.
The average costs of fuel in cents per net kilowatt-hour generated for 1993
through 1995 are shown below:
Oil and Weighted
ALABAMA Coal Nuclear Gas Average
----------------------------------------------
1993 2.11 0.51 * 1.73
1994 1.92 0.49 * 1.56
1995 1.71 0.50 * 1.48
GEORGIA
1993 1.75 0.58 * 1.52
1994 1.67 0.63 * 1.44
1995 1.67 0.60 * 1.44
GULF
1993 2.03 ** 4.50 2.05
1994 2.00 ** * 2.01
1995 2.08 ** 3.56 2.09
MISSISSIPPI
1993 1.66 ** 2.97 1.71
1994 1.67 ** 2.60 1.71
1995 1.58 ** 2.33 1.64
SAVANNAH
1993 2.02 ** 4.70 2.49
1994 2.19 ** 4.72 2.42
1995 1.77 ** 3.80 2.18
SEGCO
1993 1.80 ** * 1.81
1994 1.83 ** * 1.83
1995 1.87 ** * 1.87
SOUTHERN system***
1993 1.90 0.54 4.34 1.67
1994 1.80 0.56 3.99 1.56
1995 1.73 0.56 3.37 1.53
---------------------------------------------------------------
*Not meaningful because of minimal generation from fuel
source.
**Not applicable.
***Amounts shown for the SOUTHERN system are weighted
averages of the operating affiliates and SEGCO.
See SELECTED FINANCIAL DATA in Item 6 herein for each registrant's source
of energy supply.
I-7
As of February 23, 1996, the operating affiliates and SEGCO had stockpiles
of coal on hand at their respective coal-fired plants which represented an
estimated 29 days of recoverable supply for bituminous coal and 32 days for
sub-bituminous coal. It is estimated that approximately 58.2 million tons of
coal will be consumed in 1996 by the operating affiliates and SEGCO (including
those units GEORGIA owns jointly with OPC, MEAG and Dalton and operates for FP&L
and JEA and the units ALABAMA owns jointly with AEC). The operating affiliates
and SEGCO currently have 38 coal contracts. These contracts cover remaining
terms of up to 17 years. Approximately 20% of 1996 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 30% of the SOUTHERN system's coal supply. Additionally, it has been
determined that approximately 34 days of recoverable supply is the appropriate
level for coal stockpiles. During 1995, the operating affiliates' and SEGCO's
average price of coal delivered was approximately $40 per ton.
The typical sulfur content of coal purchased under contracts ranges from
approximately 0.49% to 2.76% 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" herein.
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 agreements with
non-affiliated industrial and mining firms to mine coal from ALABAMA's reserves,
as well as their own reserves, for supply to ALABAMA's generating units.
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 GULF and
MISSISSIPPI in Item 8 herein.
ALABAMA and GEORGIA have numerous contracts covering a portion of their
nuclear fuel needs for uranium, conversion services, enrichment services and
fuel fabrication. These contracts have varying expiration dates and most are
short to medium term (less than 10 years). Management believes that sufficient
capacity for nuclear fuel supplies and processing exists to preclude the
impairment of normal operations of the SOUTHERN system's nuclear generating
units.
ALABAMA and GEORGIA have contracts with the DOE that provide for the
permanent disposal of spent nuclear fuel. Although disposal was scheduled to
begin in 1998, 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.
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,
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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 some of 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, 48 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, six rural electric distribution cooperative
associations and one generating and transmitting cooperative.
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.
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,
1995, the registrants derived their respective industrial revenues as shown in
the following table.
I-9
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. On January 12, 1996, ALABAMA, GEORGIA and MISSISSIPPI filed a
lawsuit against TVA for violation of this Act. See Item 3 - LEGAL PROCEEDINGS
herein for additional information.
The RUS 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 71 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 840 megawatts of nameplate capacity, including an undivided
ownership interest in ALABAMA's Plant Miller Units 1 and 2. AEC's facilities
were financed with RUS 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 RUS, 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 joint-ownership with
AEC of a portion of Plant Miller.
Another of the 71 electric cooperatives is SMEPA, also a generating and
transmitting cooperative. SMEPA 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. During 1994 and 1995, OPC gave GEORGIA notice of its
intent to decrease its purchases of capacity by 250 megawatts in September 1996
and an additional 250 megawatts in September 1997.
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
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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. See
Note 7 to ALABAMA's financial statements in Item 8 herein for further
information on these contracts.
Forty-seven 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. One municipally-owned electric
distribution system is still served on a full requirements wholesale basis 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 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 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
of at least 900 kilowatts may receive electric service from the supplier of its
choice. (See also Item 1 - BUSINESS - "Competition" herein.)
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. (See also Item 1 - BUSINESS - "Competition"
herein.)
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 300,000 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
I-11
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.
Long-Term Power Sales Agreements
Reference is made to Note 7 to the financial statements for SOUTHERN, ALABAMA,
GEORGIA, GULF and MISSISSIPPI and Note 6 to the financial statements for
SAVANNAH in Item 8 herein for information regarding contracts for the sales of
capacity and energy to non-territorial customers.
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 has experienced 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.
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 1995, ALABAMA purchased approximately 115
million kilowatt-hours from such companies at a cost of $1.8 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 1995, GEORGIA purchased 4 million
kilowatt-hours from such companies at a cost of $78,000. GEORGIA has entered
into a 30-year purchase power agreement, scheduled to begin in June 1998, for
electricity during peaking periods from a planned 300-megawatt cogeneration
facility. Payments are subject to reductions for failure to meet minimum
capacity output.
GULF currently has cogeneration agreements for "as available" energy in
effect with two industrial customers. During 1995, GULF purchased 214 million
kilowatt-hours from such companies for $3.6 million.
SAVANNAH currently has cogeneration contracts in effect with four industrial
customers. Under the terms of these contracts, SAVANNAH purchases excess
generation of such companies. During 1995, SAVANNAH purchased 1.5 million
kilowatt-hours from such companies at a cost of $34,000.
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, regulatory, 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.)
I-12
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 or, conversely,
prove to be beneficial. New federal legislation is being discussed, and
legislation allowing customer choice has been introduced in Alabama, Florida and
Georgia. Some form of retail wheeling has been mandated in states such as
California and Michigan. Any form of retail wheeling which may be adopted would
need to address a variety of complex issues, including stranded investments and
the utility's obligation to serve a particular customer or customers. Reference
is made to each registrant's "Management's Discussion and Analysis - Future
Earnings Potential" in Item 7 herein for further discussion of competition.
In order to adapt to the increasingly competitive environment in which they
operate, SOUTHERN and the operating affiliates will evaluate and consider a wide
array of potential business strategies. These may include business combinations
or acquisitions involving other utility or non-utility businesses or properties,
internal restructurings or reorganizations involving SOUTHERN, the operating
affiliates or some combination thereof or dispositions of currently owned
properties or currently operated business units. In addition, SOUTHERN and the
operating affiliates may engage in new business ventures, such as power
marketing, which arise from competitive and regulatory changes in the utility
industry. Pursuit of any of the above strategies, or any combination thereof,
may significantly affect the business operations and financial condition of
SOUTHERN and the operating affiliates.
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.
In June 1995, the Division of Investment Management of the SEC issued a
report on its study of the regulation of public-utility holding companies.
Concluding that significant changes in the current regulatory system are needed,
the report offers various legislative and administrative recommendations for
reform. The legislative option preferred by the Division in the report is repeal
of the Holding Company Act coupled with new provisions for state access to books
and records of holding company system companies and for federal audit authority
and oversight of intrasystem transactions. However, the prospects for further
legislative reform of the Holding Company Act are uncertain at this time.
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 18 existing GEORGIA
generating stations having an aggregate installed capacity of 1,074,696
kilowatts.
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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, totaling 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 on January 1, 2024. The
North Georgia project is operating on an annual license under the same terms and
conditions as its original license. Additionally, the FERC has issued an order
granting a combined, 40-year license for the Yates and Thurlow projects. 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 megawatts.
In August 1995, GEORGIA filed with the FERC its application for a new
license for its Sinclair Project which has 45,000 kilowatts of capacity.
GEORGIA's current license for this project expires September 1, 1997. Certain
environmental issues raised during the licensing process may result in the FERC
including license terms and conditions that could have a substantial effect on
the peaking capability of the project.
In July 1994, flooding of the Flint River in and around Albany, Georgia and
the Flint River Project (5,400 kilowatts of capacity) resulted in substantial
damage to the dam and power house. Under the FERC oversight, GEORGIA has made
repairs to the facilities. In the event GEORGIA elects to file for a new license
for the Flint River Project, it is required to file a notice of intent with the
FERC by September 1996. GEORGIA will then be required to file an application for
a new license for such project by September 1999.
GEORGIA and OPC also have a license, expiring in 2027, for the Rocky
Mountain Plant, a pure pumped storage facility of 847,800 kilowatt capacity
which began commercial operation in 1995. (See Item 2 - PROPERTIES -
"Jointly-Owned Facilities" herein and Note 3 to SOUTHERN's and GEORGIA's
financial statements in Item 8 herein for additional information.)
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 2005-2020
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 5 to GEORGIA's financial statements in Item 8 herein
for information on nuclear decommissioning costs and nuclear insurance.
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
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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 facilities for the years 1996, 1997 and 1998 are
as follows: (in millions)
-------------------------------------------------------
1996 1997 1998
-----------------------------------
ALABAMA $29.8 $31.0 $30.3
GEORGIA 19.4 21.9 25.4
GULF 1.9 5.8 4.1
MISSISSIPPI 1.1 1.5 2.7
SAVANNAH 2.1 0.8 1.3
SEGCO 8.5 1.0 -
-----------------------------------
SOUTHERN
system $62.8 $62.0 $63.8
=======================================================
*The foregoing estimates are included in the current construction programs.
(See Item 1 - BUSINESS - "Construction Programs" herein.)
Additionally, each operating affiliate and SEGCO have incurred costs for
environmental remediation of various sites. Reference is made to each
registrant's "Management's Discussion and Analysis" in Item 7 herein for
information regarding the registrants' environmental remediation efforts. Also,
see Note 3 to SOUTHERN's and GEORGIA's financial statements in Item 8 herein for
information regarding the identification of sites that may require environmental
remediation by GEORGIA and Note 3 to MISSISSIPPI's financial statements in Item
8 herein for information regarding a site that may require environmental
remediation by MISSISSIPPI.
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
including those with special features to encourage off-peak usage. Additionally,
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the operating affiliates are allowed by their respective PSCs to negotiate the
terms and compensation of service to large customers. Such terms and
compensation of service, however, are subject to final PSC approval. With
respect to 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 clause. GULF recovers from retail customers fuel
and net purchased power costs through provisions which are adjusted to reflect
increases or decreases in such costs. 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 fuel costs is based upon a projection for six-months;
any over/under recovery during such period is reflected in a subsequent
six-month period with interest. GULF's recovery of purchased power capacity
costs is based upon an annual projection; any over/under recovery during such
period is reflected in a subsequent annual period with interest. 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.
Rate Proceedings
Reference is made to Note 3 to each registrant's financial statements in Item 8
herein for a discussion of rate matters. For each registrant (except SAVANNAH),
such Note 3 includes a discussion of proceedings initiated 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.
In 1995, GULF filed a petition with the Florida PSC seeking approval for an
optional rate rider, which would be applicable to GULF's largest and most
at-risk customers. For additional information, reference is made to GULF's
"Management's Discussion and Analysis - Future Earnings Potential" in Item 7
herein.
Integrated Resource Planning
In 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 intends 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.
By orders issued in 1992 and by amended orders issued in 1995, the Georgia
PSC approved Integrated Resource Plans for both GEORGIA and SAVANNAH. (See Note
3 to SOUTHERN's and GEORGIA's financial statements in Item 8 herein for
information regarding GEORGIA's demand-side option programs and Note 3 to
SAVANNAH's financial statements for information regarding SAVANNAH's demand-side
option programs.)
The Florida PSC has set energy conservation goals for GULF, which became
effective in 1995, that require programs to reduce 154 megawatts of summer peak
demand and 65,000 kilowatt-hours of sales by the year 2004. For additional
information, reference is made to GULF's "Management's Discussion and Analysis -
Future Earnings Potential" in Item 7 herein.
Environmental Cost Recovery Plans
GULF and MISSISSIPPI both have retail rate mechanisms that provide for recovery
of environmental compliance costs. For a description of these plans, see Note 3
to GULF's and MISSISSIPPI's financial statements in Item 8 herein.
I-16
Employee Relations
The companies of the SOUTHERN system had a total of 31,882 employees on their
payrolls at December 31, 1995.
-------------------------------------------------
Employees
at
December 31, 1995
-----------------------
ALABAMA 7,261
GEORGIA 11,061
GULF 1,501
MISSISSIPPI 1,421
SAVANNAH 584
SCS 3,207
Southern Nuclear 1,298
Communications 78
Southern Development 41
SEI* 5,430
-------------------------------------------------
Total 31,882
=================================================
*Includes 4,977 employees on international payrolls.
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, 1998. 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, and is currently in
negotiations with respect to such agreement. GEORGIA also has a contract with
the United Plant Guard Workers of America with respect to Plant Hatch which
extends through September 30, 1998.
GULF has an agreement with the IBEW on a three-year contract extending to
August 15, 1998.
In July 1995, MISSISSIPPI and the IBEW began negotiating changes to the
contract which extended to August 16, 1995. Due to ongoing negotiations, the
parties agreed to extend the contract beyond August 16, 1995. Discussions
continued into 1996, with union ratification in March.
Southern Nuclear has an agreement with the IBEW on a three-year contract
extending to August 15, 1998. 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 16, 1996 and
December 1, 1996, respectively. SAVANNAH is currently in negotiations with the
IBEW.
SEI has agreements with local unions of the IBEW and the United Paperworkers
International Union which covers employees of Mobile Energy. These agreements
extend to May 31, 1997.
I-17
Item 2. PROPERTIES
Electric Properties
The operating affiliates and SEGCO, at December 31, 1995, operated 33
hydroelectric generating stations, 32 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 (1)
------------------------------------------------------------
(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 (2)
Gaston Unit 5 Wilsonville, AL 880,000
Miller Birmingham, AL 2,532,288 (3)
---------
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 750,924 (4)
Wansley Carrollton, GA 925,550 (5)
Yates Newnan, GA 1,250,000
---------
GEORGIA Total 9,541,174
---------
Crist Pensacola, FL 1,045,000
Lansing Smith Panama City, FL 305,000
Scholz Chattahoochee, FL 80,000
Daniel Pascagoula, MS 500,000 (6)
Scherer Unit 3 Macon, GA 204,500 (4)
---------
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 (6)
Greene County Demopolis, AL 200,000 (2)
-----------
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 (7)
------------
Total Fossil Steam 21,700,243
------------
Nuclear Steam
Farley Dothan, AL
(ALABAMA) 1,720,000
------------
Hatch Baxley, GA 816,630 (8)
Vogtle Augusta, GA 1,060,240 (9)
------------
GEORGIA Total 1,876,870
------------
Total Nuclear Steam 3,596,870
------------
Combustion Turbines
Greene County Demopolis, AL
(ALABAMA) 400,000
-----------
Arkwright Macon, GA 30,580
Atkinson Atlanta, GA 78,720
Bowen Cartersville, GA 39,400
McDonough Atlanta, GA 78,800
McIntosh
Units 1,2,3,4,7,8 Effingham County, GA 480,000
McManus Brunswick, GA 481,700
Mitchell Albany, GA 118,200
Robins Warner Robins, GA 160,000
Wilson Augusta, GA 354,100
Wansley Carrollton, GA 26,322 (5)
-----------
GEORGIA Total 1,847,822
-----------
Lansing Smith
Unit A (GULF) Panama City, FL 39,400
Chevron Cogenerating
Station Pascagoula, MS 147,292 (10)
Sweatt Meridian, MS 39,400
Watson Gulfport, MS 39,360
-----------
MISSISSIPPI Total 226,052
-----------
Boulevard Savannah, GA 59,100
Kraft Port Wentworth, GA 22,000
McIntosh
Units 5&6 Effingham County, GA 160,000
-----------
SAVANNAH Total 241,100
-----------
----------------------------------------------------------------
I-18
----------------------------------------------------------------
Nameplate
Generating Station Location Capacity
----------------------------------------------------------------
(Kilowatts)
Gaston (SEGCO) Wilsonville, AL 19,680 (7)
-----------
Total Combustion Turbines 2,774,054
-----------
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
Rocky Mountain Rome, GA 215,256 (11)
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 1,077,736
-----------
Total Hydroelectric Facilities 2,660,461
-----------
Total Generating Capacity 30,731,628
===========
---------------------------------------------------------------
Notes:
(1) For additional information regarding facilities jointly-owned with
non-affiliated parties, see Item 2 - PROPERTIES - "Jointly-Owned
Facilities" herein.
(2) Owned by ALABAMA and MISSISSIPPI as tenants in common in the
proportions of 60% and 40%, respectively.
(3) Excludes the capacity owned by AEC.
(4) Capacity shown for GEORGIA is 8.4% of Units 1 and 2 and 75% of Unit 3.
Capacity shown for GULF is 25% of Unit 3.
(5) Capacity shown is GEORGIA's portion (53.5%) of total plant capacity.
(6) Represents 50% of the plant which is owned as tenants in common by
GULF and MISSISSIPPI.
(7) SEGCO is jointly-owned by ALABAMA and GEORGIA. (See Item 1 - BUSINESS
herein.)
(8) Capacity shown is GEORGIA's portion (50.1%) of total plant capacity.
(9) Capacity shown is GEORGIA's portion (45.7%) of total plant capacity.
(10) Generation is dedicated to a single industrial customer.
(11) Capacity shown is GEORGIA's portion (25.4%) of total plant capacity.
OPC operates the plant.
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 27,419,700 kilowatts
and occurred in August 1995. This amount excludes demand served by capacity
retained by MEAG and Dalton and excludes demand associated with power purchased
from OPC and SEPA by its preference customers. At that time, 29,596,100
kilowatts were supplied by SOUTHERN system generation and 2,176,400 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 9.4%. For
additional information on peak demands, reference is made to Item 6 SELECTED
FINANCIAL DATA herein.
I-19
ALABAMA and GEORGIA will incur significant costs in decommissioning their
nuclear units at the end of their useful lives. (See Item 1 - BUSINESS
"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 interests in or operates
independent power production facilities and foreign utility companies. The
generating capacity of these utilities (or facilities) at December 31, 1995, was
as follows:
I-20
Jointly-Owned Facilities
ALABAMA and GEORGIA have sold and GEORGIA has purchased undivided interests in
certain generating plants and other related facilities to or from non-affiliated
parties. The percentages of ownership resulting from these transactions are as
follows:
ALABAMA and GEORGIA have contracted to operate and maintain the respective
units in which each has an interest (other than Rocky Mountain and Intercession
City, as described below) as agent for the joint owners.
In connection with the joint ownership arrangements for Plant Vogtle,
GEORGIA has remaining commitments to purchase declining fractions of MEAG's
capacity and energy until December 1996 for Unit 2 and, with regard to a portion
of a 5% interest 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 from non-affiliates in GEORGIA's Statements of
Income in Item 8 herein.
In December 1988, GEORGIA and OPC entered into a joint ownership agreement
for the Rocky Mountain plant under which GEORGIA agreed to retain its present
investment in the project and OPC agreed to finance, complete and operate the
facility. The plant went into commercial operation in 1995. GEORGIA's net
investment in the plant is approximately $190 million, and GEORGIA's ownership
is 25.4 percent. Reference is made to Note 3 to SOUTHERN's and GEORGIA's
financial statements in Item 8 herein for additional information regarding the
Rocky Mountain plant.
In 1994, GEORGIA and FPC entered into a joint ownership agreement regarding
the Intercession City combustion turbine unit. The unit is scheduled to be in
commercial operation by the end of 1996, and will be constructed, operated, and
maintained by FPC. GEORGIA will have a one-third interest in the 150-megawatt
unit, with use of 100% of the capacity from June through September. FPC will
have the capacity the remainder of the year. GEORGIA's investment in the unit at
completion is estimated to be $14 million. Also, GEORGIA entered into a separate
four-year purchase power contract with FPC. Beginning in 1996, GEORGIA will
purchase 400 megawatts of capacity. In 1998, this amount will decline to 200
megawatts for the remaining two years.
Sale of Property
Reference is made to Note 6 to SOUTHERN's and GEORGIA's financial statements in
Item 8 herein for information regarding the sale completed in 1995 of GEORGIA's
remaining ownership interest in Plant Scherer Unit 4.
I-21
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, 1991 to December 31, 1995, the operating
affiliates, SEGCO, SCS, Southern Nuclear, Communications and SEI recorded gross
property additions and retirements as follows:
==================================================
Gross Property
Additions Retirements
--------------- -------------
(in millions)
ALABAMA (1) $2,290 $ 357
GEORGIA (2) 2,850 1,864
GULF 350 125
MISSISSIPPI 433 82
SAVANNAH 179 16
SEGCO 60 14
SCS 111 122
Southern Nuclear 17 4
Communications 162 -
SEI 154 6
--------------------------------------------------
SOUTHERN system $6,606 $2,590
==================================================
Notes:
(1) Includes approximately $62 million attributable to sale of 8.2%
interest in Plant Miller Units 1 and 2 to AEC in 1992.
(2) Includes approximately $691 million attributable to 1991 through 1995
sales of Plant Scherer Unit 4 to FP&L and JEA.
I-22
Item 3. LEGAL PROCEEDINGS
(1) Stepak v. certain SOUTHERN officials
(U.S. District Court for the Southern District of Georgia)
Reference is made to Note 3 to SOUTHERN's financial statements in Item 8
herein under the caption "Stockholder Suit."
(2) SOUTHERN and Subsidiaries v. Commissioner of the IRS
(U.S. Tax Court)
In June 1994, a tax deficiency notice was received from the IRS for the
years 1984 through 1987 with regard to the tax accounting by GEORGIA for
the sale in 1984 of an interest in Plant Vogtle and related capacity and
energy buyback commitments. The potential tax deficiency and interest
arising from this issue currently amount to approximately $25 million and
$31 million, respectively. The tax deficiency relates to a timing issue
as to when taxes are paid; therefore, only the interest portion could
affect future income. Management believes that the IRS position is
incorrect, and GEORGIA has filed a petition with the U.S. Tax Court
challenging the IRS's position. In order to minimize additional interest
charges should the IRS's position prevail, GEORGIA made a payment to the
IRS related to the potential tax deficiency in September 1994.
(3) ALABAMA, GEORGIA and MISSISSIPPI v. TVA, et al.
(U.S. District Court for the Northern District of Alabama)
On January 12, 1996, ALABAMA, GEORGIA and MISSISSIPPI filed an action
seeking to enjoin the TVA from violating a 1959 act which prohibits the
TVA from selling power outside the area that was being served by it in
1957. LG&E Power Marketing, Inc. (LPM), also a defendant, has entered
into an agreement with TVA for the sale of power purchased by LPM from
TVA to organizations outside the TVA's statutorily defined service
territory, which the plaintiffs contend is in violation of the 1959 act.
(4) GEORGIA has been designated as a potentially responsible party under the
Comprehensive Environmental Response, Compensation and Liability Act with
respect to a site in Brunswick, Georgia.
Reference is made to Note 3 to SOUTHERN's and GEORGIA's financial
statements in Item 8 herein under the captions "Georgia Power Potentially
Responsible Party Status" and "Certain Environmental Contingencies,"
respectively.
See Item 1 - BUSINESS - "Construction Programs," "Fuel Supply," "Regulation
- Federal Power Act" and "Rate Matters" as well as Note 3 to each registrant's
financial statements in Item 8 herein for a description of certain other
administrative and legal proceedings discussed therein.
Additionally, each of the operating affiliates, SEI, SCS, Southern Nuclear,
Southern Development and Communications 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.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
I-23
EXECUTIVE OFFICERS OF SOUTHERN
(Identification of executive officers of SOUTHERN is inserted in Part I in
accordance with Regulation S-K, Item 401(b), Instruction 3.) The ages of the
officers set forth below are as of December 31, 1995.
A. W. Dahlberg
Chairman, President and Chief Executive Officer
Age 55
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. He was elected
Chairman and Chief Executive Officer effective March 1995.
Paul J. DeNicola
Executive Vice President and Director
Age 47
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 51
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 Chief Executive Officer of GEORGIA effective January 1994.
Elmer B. Harris
Executive Vice President and Director
Age 56
Elected in 1989; President and Chief Executive Officer of ALABAMA since 1989
and, beginning 1991, Executive Vice President of SOUTHERN.
David M. Ratcliffe
Senior Vice President
Age 47
Elected in 1995; President and Chief Executive Officer of MISSISSIPPI from 1991
to 1995. He also serves as Executive Vice President of SCS beginning in 1995 and
previously held that position from 1989 to 1991.
W. L. Westbrook
Financial Vice President, Chief Financial Officer and Treasurer
Age 56
Elected in 1986; responsible primarily for all aspects of financing for
SOUTHERN. He has served as Executive Vice President of SCS since 1986.
Thomas G. Boren
Vice President
Age 46
Elected in 1995; President and Chief Executive Officer of SEI since 1992. He
previously served as Senior Vice President of GEORGIA from 1989 to 1992.
Bill M. Guthrie
Vice President
Age 62
Elected in 1991; serves as Chief Production Officer for the SOUTHERN system.
Senior Executive Vice President of SCS effective January 1994 and Executive Vice
President of ALABAMA since 1988. He also serves as Executive Vice President of
GEORGIA and Vice President of GULF, MISSISSIPPI and SAVANNAH.
W. G. Hairston, III
Age 51
President and Chief Executive Officer of Southern Nuclear since 1993. He has
also served as Executive Vice President of GEORGIA since 1989.
Each of the above is currently an officer of SOUTHERN, except Mr. Hairston,
serving a term running from the last annual meeting of the directors (July 17,
1995) for one year until the next annual meeting or until his successor is
elected and qualified.
I-24
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
----------- --------
1995
First Quarter $21-1/2 $19-3/8
Second Quarter 22-7/8 20-1/8
Third Quarter 24 21-1/8
Fourth Quarter 25 22-3/4
1994
First Quarter $22 $18-1/2
Second Quarter 20-1/2 17-3/4
Third Quarter 20 17
Fourth Quarter 21 18-1/4
-------------------------------------------
There is no market for the other registrants' common stock, all of
which is owned by SOUTHERN. On February 29, 1996, the closing price
of SOUTHERN's common stock was $23-7/8.
(b) Number of SOUTHERN's common stockholders at December 31, 1995:
225,739
Each of the other registrants have one common stockholder, SOUTHERN.
(c) Dividends on each registrant's common stock are payable at the
discretion of their respective board of directors. The dividends on
common stock paid and/or declared by SOUTHERN and the operating
affiliates to their stockholder(s) for the past two years were as
follows: (in thousands)
----------------------------------------------------
Registrant Quarter 1995 1994
----------------------------------------------------
SOUTHERN First $201,866 $191,262
Second 203,060 191,262
Third 203,061 191,475
Fourth 203,178 192,758
ALABAMA First 71,900 66,500
Second 69,500 67,000
Third 69,300 66,900
Fourth 74,300 67,600
GEORGIA First 113,900 106,600
Second 110,200 107,200
Third 109,700 107,200
Fourth 117,700 108,300
GULF First 11,700 10,900
Second 11,300 11,000
Third 11,300 11,000
Fourth 12,100 11,100
MISSISSIPPI First 9,900 8,500
Second 9,600 8,500
Third 9,600 8,500
Fourth 10,300 8,600
SAVANNAH First 4,400 4,100
Second 4,300 4,100
Third 4,300 4,100
Fourth 4,600 4,000
----------------------------------------------------
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
The dividend paid per share by SOUTHERN was 29.5(cent) for each quarter of
1994 and 30.5(cent) for each quarter of 1995. The dividend paid on SOUTHERN's
common stock for the first quarter of 1996 was raised to 31.5(cent) per share.
The amount of dividends on their common stock 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, 1995, were as follows:
---------------------------------------------
Retained Restricted
Earnings Amount
--------------------------
(in millions)
ALABAMA $1,161 $ 807
GEORGIA 1,570 897
GULF 180 101
MISSISSIPPI 157 118
SAVANNAH 105 62
Consolidated 3,483 1,990
---------------------------------------------
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-39
through II-50.
ALABAMA. Reference is made to information under the heading "Selected
Financial and Operating Data," contained herein at pages II-79 through II-92.
GEORGIA. Reference is made to information under the heading "Selected
Financial and Operating Data," contained herein at pages II-126 through II-140.
GULF. Reference is made to information under the heading "Selected
Financial and Operating Data," contained herein at pages II-170 through II-183.
MISSISSIPPI. Reference is made to information under the heading "Selected
Financial and Operating Data," contained herein at pages II-210 through II-223.
SAVANNAH. Reference is made to information under the heading "Selected
Financial and Operating Data," contained herein at pages II-246 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-54 through II-60.
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-96 through II-103.
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-144 through II-151.
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-187 through II-193.
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-227 through II-232.
II-2
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO 1995 FINANCIAL STATEMENTS
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
II-4
THE SOUTHERN COMPANY
AND SUBSIDIARY COMPANIES
FINANCIAL SECTION
II-5
MANAGEMENT'S REPORT
The Southern Company and Subsidiary Companies 1995 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 five 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 subsidiary companies in
conformity with generally accepted accounting principles.
/s/ A. W. Dahlberg
A. W. Dahlberg
Chairman, President, and Chief Executive Officer
/s/ W. L. Westbrook
W. L. Westbrook
Financial Vice President, Chief Financial Officer, and Treasurer
February 21, 1996
II-6
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 subsidiary companies as of December 31, 1995 and 1994, 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, 1995. These
financial statements are the responsibility of the company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements (pages II-16 through II-38)
referred to above present fairly, in all material respects, the financial
position of The Southern Company and subsidiary companies as of December 31,
1995 and 1994, and the results of their operations and their cash flows for the
periods stated, in conformity with generally accepted accounting principles.
/s/ Arthur Andersen LLP
Atlanta, Georgia
February 21, 1996
II-7
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
The Southern Company and Subsidiary Companies 1995 Annual Report
RESULTS OF OPERATIONS
Earnings and Dividends
This year's financial performance continues to support The Southern Company's
goal to become America's Best Diversified Utility. The core business of selling
electricity in the Southeast remained strong, while the non-core business
expanded both internationally and domestically. The financial results for 1995
demonstrate a very successful year with several records being set. Net income of
$1.1 billion and earnings per share of $1.66 for 1995 both established record
highs. Southern Company common stock reached an all-time high closing price of
24 5/8, surpassing the previous record of 23 3/8 set in 1993. Continued cost
controls and the strong demand for electricity were the dominant forces that
favorably affected earnings in 1995.
Costs related to the work force reduction programs implemented in 1995 and
1994 decreased earnings by 2 cents and 9 cents per share, respectively. These
costs are expected to be recovered through future savings in approximately two
years following each program's implementation. Additional non-operating or
non-recurring items affected earnings in 1995 and 1994. After excluding these
items in both years, 1995 earnings from operations were $1.1 billion -- or $1.71
per share -- an increase of $108 million compared with 1994. The non-operating
items that affected earnings were as follows:
Consolidated Earnings
Net Income Per Share
--------------- ----------------
1995 1994 1995 1994
--------------- ----------------
(in millions)
Earnings as reported $1,103 $ 989 $1.66 $1.52
---------------------------------------------------------------------
Work force reduction
programs 17 61 .02 .09
Sale of facilities (12) (28) (.02) (.04)
Demand-side costs 17 - .03 -
Environmental
cleanup 5 5 .01 .01
Miscellaneous 5 - .01 -
---------------------------------------------------------------------
Total non-operating 32 38 .05 .06
---------------------------------------------------------------------
Earnings from
operations $1,135 $1,027 $1.71 $1.58
=====================================================================
Amount and
percent change $108 10.6% $0.13 8.2%
---------------------------------------------------------------------
In 1995, non-operating items -- both positive and negative -- had an impact
on earnings, which resulted in a net reduction of $32 million. These items were:
(1) Costs associated with work force reduction programs implemented primarily in
1995 decreased earnings. (2) The last in a series of four separate transactions
to sell Plant Scherer Unit 4 to two Florida utilities increased earnings. (3)
Georgia Power's demand-side conservation costs that were not recovered from
customers decreased earnings. (4) Environmental-cleanup costs decreased
earnings.
In 1994, earnings were $989 million or $1.52 per share -- down 5 cents from
the per share amount reported in 1993. Earnings in 1994 were significantly
affected by costs related to work force reduction programs and milder than
normal temperatures.
Dividends paid on common stock during 1995 were $1.22 per share or 30 1/2
cents per quarter. During 1994 and 1993, dividends paid per share were $1.18 and
$1.14, respectively. In January 1996, The Southern Company board of directors
raised the quarterly dividend to 31 1/2 cents per share or an annual rate of
$1.26 per share.
Acquisitions
Southern Electric International (Southern Electric) owns and manages
international and domestic non-core businesses for The Southern Company.
Southern Electric acquired several businesses in late 1994 and in 1995. These
businesses have been included in the consolidated statements of income since the
date of acquisition and not reflected in prior periods. These acquisitions
account for a significant portion of the amount of change in revenues and
certain expenses from year to year. Therefore to facilitate discussing the
results of operations, Southern Electric's 1995 variances are shown separately.
These variances are predominantly acquisition related and require no further
explanation.
II-8
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
The Southern Company and Subsidiary Companies 1995 Annual Report
Revenues
Operating revenues increased in 1995 and decreased in 1994 as a result of the
following factors:
Increase (Decrease)
From Prior Year
------------------------------
1995 1994 1993
------------------------------
Retail -- (in millions)
Change in base rates $ - $ 3 $ 3
Sales growth 177 153 104
Weather 143 (177) 198
Fuel cost recovery and
other 134 (107) 199
-------------------------------------------------------------
Total retail 454 (128) 504
-------------------------------------------------------------
Sales for resale --
Within service area 39 (87) 38
Outside service area (90) (108) (184)
-------------------------------------------------------------
Total sales for resale (51) (195) (146)
Southern Electric 458 131 54
Other operating revenues 22 - 4
-------------------------------------------------------------
Total operating revenues $883 $(192) $ 416
=============================================================
Percent change 10.6% (2.3)% 5.2%
-------------------------------------------------------------
Retail revenues of $7.6 billion in 1995 increased 6.4 percent from last
year, compared with a decrease of 1.8 percent in 1994. 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 $399 million in 1995,
up 11 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 $360 million in
1994, down 19 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.
1995 1994 1993
---------------------------------
(in millions)
Capacity $237 $276 $350
Energy 151 176 230
------------------------------------------------------
Total $388 $452 $580
======================================================
Capacity revenues decreased in 1995 and 1994 because the amount of capacity
under contract declined, as scheduled, by some 100 megawatts and 400 megawatts,
respectively. Additional declines in capacity are not scheduled until after
1999.
Changes in revenues are influenced heavily by the amount of energy sold each
year. Kilowatt-hour sales for 1995 and the percent change by year were as
follows:
Percent Change
----------------------------
(billions of Amount
kilowatt-hours) 1995 1995 1994 1993
------------- ----------------------------
Residential 39.1 9.2% (2.6)% 9.5%
Commercial 35.9 5.5 3.8 5.9
Industrial 51.7 2.7 3.2 1.9
Other 0.9 2.1 3.8 4.6
-----------
Total retail 127.6 5.4 1.6 5.3
Sales for resale --
Within service area 9.5 16.2 (38.5) 9.5
Outside service area 9.1 (15.1) (13.5) (25.2)
-----------
Total 146.2 4.4 (3.4) 2.1
===================================================================
The rate of increase in 1995 retail energy sales was fostered by the impact
of weather. Residential energy sales surged upward as a result of
hotter-than-normal summer weather in 1995, compared with the extremely mild
summer of 1994. Commercial and industrial sales continue to show moderate gains
in excess of the national average. This reflects the strength of business and
economic conditions in The Southern Company's service area. Energy sales to
retail customers are projected to increase at an average annual rate of 1.9
percent during the period 1996 through 2006.
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 continued to decrease
in 1995 and 1994, primarily as a result of the scheduled decline in megawatts of
capacity under contract.
II-9
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
The Southern Company and Subsidiary Companies 1995 Annual Report
Expenses
Total operating expenses of $7.3 billion for 1995 increased $712 million
compared with the prior year. Core business expenses increased $322 million, and
Southern Electric comprised the remainder. The costs to produce and deliver
electricity for the core business in 1995 increased by $120 million to meet
higher energy demands. Depreciation expenses and property taxes increased by $78
million as a result of additional utility plant being placed into service. The
amortization of deferred expenses related to Plant Vogtle increased by $49
million in 1995 when compared with the prior year. For additional information
concerning Plant Vogtle, see Note 1 to the financial statements under "Plant
Vogtle Phase-In Plans."
In 1994, operating expenses of $6.6 billion declined 2.1 percent compared
with 1993. The decrease was attributable to less energy being sold. Total
production costs were down $297 million. However, costs related to the 1994 work
force reduction programs increased operating expenses by $100 million. Also, a
$39 million increase in the amortization of deferred Plant Vogtle expenses
compared with the amount in 1993 contributed to offset the decrease in operating
expenses.
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 -- within the core business service
area -- were as follows:
1995 1994 1993
---------------------------
Total generation
(billions of kilowatt-hours) 147 142 144
Sources of generation
(percent) --
Coal 77 75 78
Nuclear 17 19 17
Hydro 4 5 4
Oil and gas 2 1 1
Average cost of fuel per net
kilowatt-hour generated
(cents) --
Coal 1.73 1.80 1.90
Nuclear 0.56 0.56 0.54
Oil and gas 3.37 3.99 4.34
Total 1.53 1.56 1.67
--------------------------------------------------------------
Fuel and purchased power costs of $2.6 billion in 1995 increased $282 million
compared with 1994. Core business increased $73 million and Southern Electric
increased $209 million. The operating companies' customer demand for electricity
rose by 4.7 billion kilowatt-hours more than in 1994. The additional cost to
meet the demand was offset slightly by a lower average cost of fuel per net
kilowatt-hour generated. Fuel and purchased power expenses of $2.3 billion in
1994 decreased 10 percent compared with the prior year because of lower energy
demands and a lower average cost of fuel per net kilowatt-hour generated.
For 1995, income taxes increased $84 million compared with the prior year.
Core business income taxes increased $65 million, and Southern Electric
accounted for the remainder. The increase was attributable to additional taxable
income from operations. For 1994, income taxes rose $8 million or 1.3 percent
above the amount reported for 1993. The increase resulted primarily from the
sale of interests in generating plant facilities.
Total gross interest charges and preferred stock dividends increased $39
million from amounts reported in the previous year. These costs for core
business continued to decline by $12 million, but Southern Electric interest
charges increased by $51 million. The decline is attributable to lower interest
rates and continued refinancing activities in 1995. In 1994, these costs were
$765 million -- down $66 million or 8.0 percent. As a result of favorable market
conditions, $1.1 billion in 1995, $1.0 billion in 1994, and $3.0 billion in 1993
of senior securities were issued for the primary purpose of retiring higher-cost
securities.
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.
II-10
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
The Southern Company and Subsidiary Companies 1995 Annual Report
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 energy sales growth to a less regulated more
competitive environment, with non-core business becoming more significant.
Work force reduction programs were implemented in 1995 and 1994 that reduced
earnings by $17 million and $61 million, respectively. These actions will assist
in efforts to control growth in future operating expenses.
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 weather, competition, changes in contracts with neighboring utilities,
energy conservation practiced by customers, the elasticity of demand, and the
rate of economic growth in the company's service area. However, the Energy
Policy Act of 1992 (Energy Act) is beginning to have a dramatic 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 Southern Company is positioning the business to meet the
challenge of this major change in the traditional practice 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. This enhances 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. Also, electricity sales for resale rates are
being driven down by wholesale transmission access and numerous potential new
energy suppliers, including power marketers and brokers. The Southern Company is
aggressively working to maintain and expand its share of wholesale sales in the
Southeastern power markets.
Although the Energy Act does not require transmission access to retail
customers, retail wheeling initiatives are rapidly evolving and becoming very
prominent issues in several states. New federal legislation is being discussed,
and legislation allowing customer choice has already been introduced in Florida
and Georgia. In order to address these initiatives, numerous questions must be
resolved, with the most complex ones relating to transmission pricing and
recovery of stranded investments. As the initiatives become a reality, the
structure of the utility industry could radically change. Therefore, unless The
Southern Company remains a low-cost producer and provides quality service, the
company's retail energy sales growth could be limited, and this could
significantly erode earnings. Conversely, being the low-cost producer could
provide significant opportunities to increase market share and profitability by
seeking new markets that evolve with the changing regulation.
The Energy Act amended the Public Utility Holding Company Act of 1935
(PUHCA). The amendment allows holding companies to form exempt wholesale
generators and foreign utility companies to sell power largely free of
regulation under PUHCA. These 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 -- founded in 1981 -- is focusing on
international and domestic cogeneration, the independent power market, and the
privatization of generating and distribution facilities in the international
market. In late 1995, South Western Electricity (SWEB) was acquired for
approximately $1.8 billion. For additional information on this acquisition, see
Note 14 to the financial statements. This British electric distribution utility
and other investments made by Southern Electric should increase the
opportunities for future earnings growth. At December 31, 1995, Southern
Electric's total assets amounted to $5.0 billion.
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 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. Besides promoting energy efficiency,
another benefit of these programs could be the ability to defer the need to
construct costly baseload generating facilities further into the future.
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 retail and wholesale regulatory matters.
II-11
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
The Southern Company and Subsidiary Companies 1995 Annual Report
The staff of the Securities and Exchange Commission has questioned certain of
the current accounting practices of the electric utility industry -- including
The Southern Company's -- regarding the recognition, measurement, and
classification of decommissioning costs for nuclear generating facilities in the
financial statements. In response to these questions, the Financial Accounting
Standards Board (FASB) has decided to review the accounting for liabilities
related to closure and removal of long-lived assets, including nuclear
decommissioning. If the FASB issues new accounting rules, the estimated costs of
closing and removing The Southern Company's nuclear and other facilities may be
required to be recorded as liabilities in the Consolidated Balance Sheets. Also,
the annual provisions for such costs could increase. Because of the company's
current ability to recover closure and removal costs through rates, these
changes would not have a significant adverse effect on results of operations.
See Note 1 to the financial statements under "Depreciation and Nuclear
Decommissioning" for additional information.
The Southern Company is involved in various matters being litigated. See Note
3 to the financial statements for information regarding material issues that
could possibly affect future earnings.
Compliance costs related to the Clean Air Act Amendments of 1990 (Clean Air
Act) could affect earnings if such costs are not fully recovered. The Clean Air
Act and other important environmental items are discussed later under
"Environmental Matters."
The operating companies are subject to the provisions of FASB Statement No.
71, Accounting for the Effects of Certain Types of Regulation. In the event that
a portion of a company's operations is no longer subject to these provisions,
the company would be required to write off related regulatory assets and
liabilities, and determine if any other assets have been impaired. See Note 1 to
the financial statements under "Regulatory Assets and Liabilities" for
additional information.
New Accounting Standards
The FASB has issued Statement No. 121, Accounting for the Impairment of
Long-Lived Assets and Long-Lived Assets to be Disposed of. This statement
requires that long-lived assets be reviewed for impairment whenever events or
changes in circumstances indicate that the carrying amount for an asset may not
be recoverable. This statement also imposes stricter criteria for regulatory
assets by requiring that such assets be probable of future recovery at each
balance sheet date. The Southern Company adopted the new rules January 1, 1996,
with no material effect on the financial statements. However, this conclusion
may change in the future as competitive factors influence wholesale and retail
pricing in the utility industry.
The FASB has issued Statement No. 123, Accounting for Stock-Based
Compensation. This statement establishes a fair value based method of accounting
for employee stock options. This method provides for a compensation cost to be
charged to results of operations at the grant date. However, the statement
allows companies to continue following the accounting prescribed by Accounting
Principles Bulletin Opinion No. 25. Opinion No. 25 generally requires
compensation cost to be recognized only for the excess of the quoted market
price at the grant date over the price that an employee must pay to acquire the
stock. The Southern Company has elected to continue with Opinion No. 25.
FINANCIAL CONDITION
Overview
The Southern Company's financial condition continues to remain strong. Both
earnings per share and market price per share set new record levels in 1995.
Earnings from operations continued to increase in 1995 and exceeded $1.1
billion. Based on this performance, in January 1996, The Southern Company board
of directors increased the common stock dividend for the fifth consecutive year.
In 1995, Southern Electric acquired SWEB for approximately $1.8 billion. For
more information on the purchase of this British electric distribution utility,
see Note 14 to the financial statements.
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 1992 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.
The Southern Company has a policy that financial derivatives are to be used
only to mitigate business risks and not for speculative purposes. Derivatives
have been used by the company on a very limited basis. At December 31, 1995, the
credit risk for derivatives outstanding was not material. See Note 1 to the
financial statements under "Financial Instruments" for additional information.
II-12
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
The Southern Company and Subsidiary Companies 1995 Annual Report
Capital Structure
The Southern Company achieved a ratio of common equity to total capitalization
-- including short-term debt -- of 42.4 percent in 1995, compared with 44.4
percent in 1994, and 43.8 percent in 1993. The company's goal is to maintain
the common equity ratio generally within a range of 40 percent to 45 percent.
During 1995, the subsidiary companies sold $375 million of first mortgage
bonds and, through public authorities, $732 million of pollution control revenue
bonds. The companies continued to reduce financing costs by retiring higher-cost
bonds. Retirements, including maturities, of bonds totaled $1.3 billion during
1995, $973 million during 1994, and $2.5 billion during 1993. Retirements of
preferred stock totaled $1 million a year during 1995 and 1994 and $516 million
during 1993. As a result, the composite interest rate on long-term debt
decreased from 8.2 percent at December 31, 1992, to 7.1 percent at December 31,
1995. During this same period, the composite dividend rate on preferred stock
declined from 7.3 percent to 6.5 percent.
In 1995, The Southern Company raised $174 million from the issuance of new
common stock under the company's various stock plans. An additional $103 million
of new common stock was issued through a public offering in early 1995. At the
close of 1995, the company's common stock had a market value of 24 5/8 per
share, compared with a book value of $13.10 per share. The market-to-book value
ratio was 188 percent at the end of 1995, compared with 160 percent at year-end
1994 and 184 percent at year-end 1993.
Capital Requirements for Construction
The construction program of The Southern Company is budgeted at $1.5 billion for
1996, $1.4 billion for 1997, and $1.3 billion for 1998. The total is $4.2
billion for the three years. Actual construction costs may vary from this
estimate because of changes in such factors as: business conditions;
environmental regulations; nuclear plant regulations; load projections;
the cost and efficiency of construction labor, equipment, and materials; and the
cost of capital. In addition, there can be no assurance that costs related to
capital expenditures for the operating companies will be fully recovered.
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 service
area, the construction of combustion turbine peaking units of approximately 600
megawatts of capacity is planned to be completed by 1998 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 $996
million will be required by the end of 1998 for present sinking fund
requirements and maturities of long-term debt. Also, the subsidiaries will
continue to retire higher-cost debt and preferred stock and replace these
obligations with lower-cost capital if market conditions permit.
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 -- has significantly
impacted The Southern Company. Specific reductions in sulfur dioxide and
nitrogen oxide emissions from fossil-fired generating plants are required in two
phases. Phase I compliance began in 1995 and initially affected 28 generating
units of The Southern Company. As a result of the company's compliance strategy,
an additional 22 generating units were brought into compliance with Phase I
requirements. Phase II compliance is required in 2000, and all fossil-fired
generating plants will be affected.
In 1995, the Environmental Protection Agency (EPA) began issuing annual
sulfur dioxide emission allowances through the allowance trading program. An
emission allowance is the authority to emit one ton of sulfur dioxide during a
calendar year. The method for issuing 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 Southern Company's sulfur dioxide compliance strategy is
designed to use allowances as a compliance option.
II-13
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
The Southern Company and Subsidiary Companies 1995 Annual Report
The Southern Company achieved Phase I sulfur dioxide compliance at the
affected plants by switching to low-sulfur coal, which required some equipment
upgrades. This compliance strategy resulted in unused emission allowances being
banked for later use. Compliance with nitrogen oxide emission limits was
achieved by the installation of new control equipment at 22 of the original 28
affected generating units. Construction expenditures for Phase I compliance
totaled approximately $320 million through 1995.
For Phase II 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 units as required to meet Phase II limits.
Therefore, during the period 1996 to 2000, current compliance strategy could
require total estimated construction expenditures of approximately $150 million.
However, the full impact of Phase II compliance cannot now be determined with
certainty, pending the continuing 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 1 percent in revenue requirements from
customers could be necessary to fully recover the cost of compliance for both
Phase I and Phase II of Title IV of the Clean Air Act. Compliance costs include
construction expenditures, increased costs for switching to low-sulfur coal, and
costs related to emission allowances.
A significant portion of costs related to the acid rain provision of the
Clean Air Act is expected to be recovered through existing ratemaking
provisions. However, 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
-- affecting sources of nitrogen oxides and volatile organic compounds -- to
achieve attainment by 1999. As the required first step, the state 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
required nitrogen oxide controls, above Title IV requirements, on some Georgia
Power plants. The EPA along with 37 states is conducting studies to evaluate the
benefits of regional controls in meeting the ozone standards. Final attainment
rules, based on modeling studies, could require installation of additional
controls for nitrogen oxide emissions to meet the 1999 deadline in Atlanta or as
part of any regional controls if enacted. A decision on new requirements is
expected in 1997. Compliance with any new rules could result in significant
additional costs. The actual 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 EPA is scheduled to submit a
report to Congress on the results of this study during 1996. The report will
include 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 is evaluating the need to revise the ambient air quality standards
for particulate matter 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 1996, the EPA may 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 subsidiaries could incur substantial costs to
clean up properties. The subsidiaries conduct studies to determine the extent of
II-14
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
The Southern Company and Subsidiary Companies 1995 Annual Report
any required cleanup costs and have recognized in their respective financial
statements costs to clean up known sites. These costs for The Southern Company
amounted to $8 million, $8 million, and $41 million in 1995, 1994, and 1993,
respectively. Additional sites may require environmental remediation for which
the subsidiaries may be liable for a portion or all required cleanup costs. See
Note 3 to the financial statements for information regarding Georgia Power's
potentially responsible party status at a site in Bruswick, Georgia.
Several major pieces of environmental legislation are being considered for
reauthorization or amendment by Congress. These include: the Clean Air Act; the
Clean Water Act; the Comprehensive Environmental Response, Compensation, and
Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances
Control Act; and the Endangered Species 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 additional 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 exists for liability as the
result of lawsuits alleging damages caused by electromagnetic fields.
Sources of Capital
The Southern Company may require additional equity capital in 1996. The amount
and timing of additional equity capital to be raised in 1996 -- 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 1996 for the company's 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 companies plan to obtain the funds required for construction
and other purposes from sources similar to those used in the past, which was
primarily from internal sources. However, the type and timing of any financings
-- if needed -- will depend on market conditions and regulatory approval.
To meet short-term cash needs and contingencies, The Southern Company had
approximately $772 million of cash and cash equivalents and $2.8 billion of
unused credit arrangements with banks at the beginning of 1996.
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. Currently, each
of the operating companies expects to have adequate coverage ratios for
anticipated requirements through at least 1998.
II-15
II-16
II-17
II-18
II-19
II-20
II-21
NOTES TO FINANCIAL STATEMENTS
The Southern Company and Subsidiary Companies 1995 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 Communications Services (Southern Communications),
Southern Electric International (Southern Electric), Southern Nuclear Operating
Company (Southern Nuclear), The Southern Development and Investment Group
(Southern Development), and other direct and indirect subsidiaries. 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 subsidiary companies.
Southern Communications provides digital wireless communications services to the
operating companies and also markets these services to the public within the
Southeast. Southern Electric designs, builds, owns, and operates power
production and delivery 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. Southern Development develops new business
opportunities related to energy products and services.
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. The preparation of financial
statements in conformity with generally accepted accounting principles requires
the use of estimates, and the actual results may differ from those estimates.
All material intercompany items have been eliminated in consolidation.
Certain prior years' data presented in the consolidated financial statements
have been reclassified to conform with current year presentation.
Regulatory Assets and Liabilities
The operating companies are subject to the provisions of Financial Accounting
Standards Board (FASB) Statement No. 71, Accounting for the Effects of Certain
Types of Regulation. Regulatory assets represent probable future revenues to the
operating companies associated with certain costs that are expected to be
recovered from customers through the ratemaking process. Regulatory liabilities
represent probable future reductions in revenues associated with amounts that
are to be credited to customers through the ratemaking process. Regulatory
assets and (liabilities) reflected in the Consolidated Balance Sheets at
December 31 relate to:
1995 1994
------------------------
(in millions)
Deferred income taxes $1,386 $1,454
Deferred Plant Vogtle costs 308 432
Premium on reacquired debt 295 298
Demand-side programs 79 97
Department of Energy assessments 73 79
Vacation pay 74 70
Deferred fuel charges 49 51
Postretirement benefits 53 41
Work force reduction costs 56 15
Deferred income tax credits (936) (987)
Storm damage reserves (23) (53)
Other, net 98 108
-----------------------------------------------------------------
Total $1,512 $1,605
=================================================================
In the event that a portion of the operating companies' operations is no
longer subject to the provisions of Statement No. 71, the companies would be
required to write off related regulatory assets and liabilities. In addition,
the operating companies would be required to determine any impairment to other
assets, including plant, and write down the assets, if impaired, to their fair
value.
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.
The company has a diversified base of customers. No single customer or
industry comprises 10 percent or more of revenues. In 1995, uncollectible
accounts continued to average less than 1 percent of revenues.
II-22
NOTES (continued)
The Southern Company and Subsidiary Companies 1995 Annual Report
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 $140
million in 1995, $152 million in 1994, and $137 million in 1993. 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. Although disposal was
scheduled to begin in 1998, 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. Alabama Power and
Georgia Power -- based on its ownership interests -- estimate their respective
remaining liability at December 31, 1995, under this law to be approximately $40
million and $31 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 1995, 3.2 percent in 1994, and 3.3 percent in 1993. 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 and removal of other facilities.
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. Alabama
Power and Georgia Power have external trust funds to comply with the NRC's
regulations. Amounts previously recorded in internal reserves are being
transferred into the external trust funds over set periods of time as approved
by the respective state public service commissions. 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.
Site study cost is the estimate to decommission a specific facility as of
the site study year, and ultimate cost is the estimate to decommission a
specific facility as of retirement date. The estimated costs of decommissioning
-- both site study costs and ultimate costs -- at December 31, 1995, for Alabama
Power's Plant Farley and Georgia Power's ownership interests in plants Hatch and
Vogtle were as follows:
Plant Plant Plant
Farley Hatch Vogtle
-------------------------------
Site study basis (year) 1993 1994 1994
Decommissioning periods:
Beginning year 2017 2014 2027
Completion year 2029 2027 2038
--------------------------------------------------------------------
(in millions)
Site study costs:
Radiated structures $489 $294 $233
Non-radiated structures 89 41 52
--------------------------------------------------------------------
Total $578 $335 $285
====================================================================
(in millions)
Ultimate costs:
Radiated structures $1,504 $781 $1,018
Non-radiated structures 274 111 230
--------------------------------------------------------------------
Total $1,778 $892 $1,248
====================================================================
II-23
NOTES (continued)
The Southern Company and Subsidiary Companies 1995 Annual Report
Plant Plant Plant
Farley Hatch Vogtle
----------------------------
(in millions)
Amount expensed in 1995 $18 $11 $9
Accumulated provisions:
Balance in external trust
funds $108 $56 $36
Balance in internal reserves 49 30 13
-----------------------------------------------------------------
Total $157 $86 $49
=================================================================
Significant assumptions:
Inflation rate 4.5% 4.4% 4.4%
Trust earning rate 7.0 6.0 6.0
-----------------------------------------------------------------
Annual provisions for nuclear decommissioning are based on an annuity --
sinking fund -- method as approved by the respective state public service
commissions. All of Alabama Power's decommissioning costs are approved for
ratemaking. For Georgia Power, only the costs to decommission the radioactive
portion of the plants are included in cost of service. Alabama Power and Georgia
Power expect their respective state public service commission to periodically
review and adjust, if necessary, the amounts collected in rates for the
anticipated cost of decommissioning.
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 changes in the assumed date of
decommissioning, changes in NRC requirements, or changes in the assumptions used
in making estimates.
Income Taxes
The Southern Company uses the liability method of accounting for deferred income
taxes and 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.
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 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. 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. Each GPSC order called for recovery of deferred costs within 10 years.
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:
1995 1994 1993
------------------------------
(in millions)
Deferred capacity buybacks $ - $ 10 $ 38
Amortization of
deferred costs (124) (85) (74)
-----------------------------------------------------------------
Net amortization (124) (75) (36)
Effect of adoption of FASB
Statement No. 109 - - 160
Deferred costs
at beginning of year 432 507 383
-----------------------------------------------------------------
Deferred costs
at end of year $308 $432 $507
=================================================================
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. In 1995 and 1994, the amount deferred was
exceeded by the amortization of amounts previously deferred by $50 million and
$1 million, respectively. The projected net amortization of the deferred expense
is $62 million in 1996 and $57 million in 1997.
II-24
NOTES (continued)
The Southern Company and Subsidiary Companies 1995 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 operating companies to
calculate AFUDC during the years 1993 through 1995 ranged from a
before-income-tax rate of 3.6 percent to 9.8 percent. AFUDC, net of income tax,
as a percent of consolidated net income was 1.6 percent in 1995, 2.3 percent in
1994, and 1.7 percent in 1993.
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
Derivative financial instruments are used by The Southern Company to manage its
interest rate and foreign currency exposures. Gains and losses arising from
effective hedges of existing assets, liabilities, or firm commitments are
deferred and recognized when the offsetting gains and losses are recognized on
the related hedged items. Losses realized on termination of interest rate swap
contracts are deferred and amortized over the terms of the related new debt
agreements. At December 31, 1995, the credit risk for derivatives outstanding
was not material.
The Southern Company hedges its exposure to fluctuations in interest rates
by entering into swap agreements that allow the company to effectively convert
its outstanding variable-rate debt into fixed rates. During 1995, the company
terminated the swap contracts in place at December 31, 1994, incurring a loss on
termination of approximately $32 million, which is being amortized over the life
of the related new fixed-rate debt agreements. At December 31, 1995, six
interest rate swap agreements were in place.
The Southern Company hedges its net investment in South Western Electricity
(SWEB) through forward contracts involving Pounds Sterling. The company
regularly monitors its foreign currency exposure, and ensures that hedge
contract amounts do not exceed the amount of the underlying exposure. At
December 31, 1995, the status of outstanding derivative contracts was as
follows:
Year Of
Maturity or Notional Unrealized
Type Termination Amount Gain (Loss)
--------------------- -------------- ---------------------------
(in millions)
Interest rate
swaps 1999-2006 $308 $(9)
Foreign currency
forwards 1996 389 -
-----------------------------------------------------------------------
In accordance with FASB Statement No. 107, Disclosure About Fair Value of
Financial Instruments, The Southern Company's financial instruments that the
carrying amount did not approximate fair value at December 31 were as follows:
Carrying Fair
Amount Value
--------------------------
(in millions)
Long-term debt:
At December 31, 1995 $8,668 $8,935
At December 31, 1994 7,674 7,373
Preferred securities:
At December 31, 1995 100 114
-----------------------------------------------------------------
The fair value for long-term debt and preferred securities were based on
either closing market price or closing price of comparable instruments.
II-25
NOTES (continued)
The Southern Company and Subsidiary Companies 1995 Annual Report
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 Plan
The system companies have defined benefit, trusteed, pension plans that cover
substantially all regular employees. Benefits are based on one of the following
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 trusts 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
In the United States, The Southern Company provides certain medical care and
life insurance benefits for retired employees. Substantially all employees may
become eligible for these benefits when they retire. Trusts are funded to the
extent deductible under federal income tax regulations or to the extent required
by the operating companies' respective regulatory commissions.
Amounts funded are primarily invested in debt and equity securities.
FASB Statement No. 106, Employers' Accounting for Postretirement Benefits
Other Than Pensions, 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 was expensed
in 1993 and the remaining costs were deferred. An additional one-fifth of the
costs is being 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. For the other
operating companies, the cost of postretirement benefits is reflected in rates
on a current basis.
Funded Status and Cost of Benefits
The following tables show actuarial results and assumptions for pension and
postretirement insurance benefits as computed under the requirements of FASB
Statement Nos. 87 and 106, respectively. The funded status of the plans at
December 31 was as follows:
Pension
-----------------------
1995 1994
-----------------------
(in millions)
Actuarial present value of
benefit obligation:
Vested benefits $2,643 $1,593
Non-vested benefits 97 68
------------------------------------------------------------------
Accumulated benefit obligation 2,740 1,661
Additional amounts related to
projected salary increases 705 638
------------------------------------------------------------------
Projected benefit obligation 3,445 2,299
Less:
Fair value of plan assets 4,725 3,171
Unrecognized net gain (1,025) (789)
Unrecognized prior service cost 60 64
Unrecognized transition asset (126) (139)
------------------------------------------------------------------
Prepaid asset recognized in the
Consolidated Balance Sheets $ 189 $ 8
==================================================================
Postretirement Benefits
----------------------------
1995 1994
----------------------------
(in millions)
Actuarial present value of
benefit obligation:
Retirees and dependents $394 $375
Employees eligible to retire 63 40
Other employees 392 459
------------------------------------------------------------------
Accumulated benefit obligation 849 874
Less:
Fair value of plan assets 205 140
Unrecognized net loss (gain) 85 3
Unrecognized prior service cost (4) -
Unrecognized transition
obligation 292 500
------------------------------------------------------------------
Accrued liability recognized in the
Consolidated Balance Sheets $271 $231
==================================================================
In 1995, the system companies announced a cost sharing program for
postretirement benefits. The program establishes limits on amounts the companies
II-26
NOTES (continued)
The Southern Company and Subsidiary Companies 1995 Annual Report
will pay to provide future retiree postretirement benefits. This change reduced
the 1995 accumulated postretirement benefit obligation by approximately $186
million.
The weighted average rates assumed in the actuarial calculations were:
1995 1994 1993
--------------------------------
Discount 7.3% 8.0% 7.5%
Annual salary increase 4.8 5.5 5.0
Long-term return on
plan assets 8.5 8.5 8.5
---------------------------------------------------------------
An additional assumption used in measuring the accumulated postretirement
benefit obligation was a weighted average medical care cost trend rate of 9.8
percent for 1995, decreasing gradually to 5.3 percent through the year 2005 and
remaining at that level thereafter. An annual increase in the assumed medical
care cost trend rate of 1 percent would increase the accumulated benefit
obligation at December 31, 1995, by $73 million and the aggregate of the service
and interest cost components of the net retiree cost by $16 million.
Components of the plans' net costs are shown below:
Pension
-----------------------------
1995 1994 1993
-----------------------------
(in millions)
Benefits earned during the year $ 79 $ 77 $ 76
Interest cost on projected
benefit obligation 193 160 156
Actual (return) loss on plan assets (730) 75 (432)
Net amortization and deferral 412 (351) 186
--------------------------------------------------------------------
Net pension cost (income) $ (46) $(39) $(14)
====================================================================
Of the above net pension income, $30 million in 1995, $29 million in 1994,
and $9 million in 1993 were recorded in operating expenses, and the remainder
was recorded in construction and other accounts.
Postretirement Benefits
---------------------------
1995 1994 1993
---------------------------
(in millions)
Benefits earned during the year $ 28 $ 31 $ 27
Interest cost on accumulated
benefit obligation 67 64 56
Amortization of transition
obligation 27 27 28
Actual (return) loss on plan
assets
assets (23) 2 (12)
Net amortization and deferral 12 (10) 5
------------------------------------------------------------------
Net postretirement costs $111 $114 $104
==================================================================
Of the above net postretirement costs, $78 million in 1995, $77 million in
1994, and $64 million in 1993 were charged to operating expenses. In addition,
$11 million in 1995, $18 million in 1994, and $21 million in 1993 were deferred,
and the remainder was charged to construction and other accounts.
Work Force Reduction Programs
The system companies have incurred additional costs for work force reduction
programs. The costs related to these programs were $42 million, $112 million,
and $35 million for the years 1995, 1994, and 1993, respectively. In addition,
certain costs of these programs were deferred and are being amortized in
accordance with regulatory treatment. The unamortized balance of these costs was
$56 million at December 31, 1995.
3. LITIGATION AND REGULATORY MATTERS
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
II-27
NOTES (continued)
The Southern Company and Subsidiary Companies 1995 Annual Report
adequately their allegation that The Southern Company board of directors'
refusal of an earlier demand by the plaintiffs was wrongful. In April 1994, the
U.S. Court of Appeals for the 11th Circuit reversed the dismissal and remanded
the case to the trial court, finding that allegations by the plaintiffs created
a reasonable doubt that the board validly exercised its business judgment in
refusing the earlier demand. In June 1995, for the second time, the trial court
dismissed the suit. The plaintiffs once again have filed an appeal. This action
is still pending.
Georgia Power Potentially Responsible Party Status
In January 1995, Georgia Power and four other unrelated entities were notified
by the Environmental Protection Agency (EPA) that they have been designated as
potentially responsible parties under the Comprehensive Environmental Response,
Compensation, and Liability Act with respect to a site in Brunswick, Georgia. As
of December 31, 1995, Georgia Power had recorded approximately $4 million in
expenses associated with the site. While Georgia Power believes that the total
amount of costs required for the cleanup of this site may be substantial, it is
unable at this time to estimate either such total or the portion for which
Georgia Power may be ultimately responsible. However, based on the nature and
extent of Georgia Power's activities relating to the site, management believes
that the company's portion of these costs should not be material.
Georgia Power Investment in Rocky Mountain
In its 1985 financing order, the GPSC concluded that completion of the Rocky
Mountain pumped storage hydroelectric plant in 1991 as then planned was not
economically justifiable and reasonable and withheld authorization for Georgia
Power to spend funds from approved securities issuances on that plant. 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 plant. However, full recovery of Georgia Power's costs depends
on the GPSC's treatment of the plant's costs and the disposition of the plant's
capacity output. In the event the GPSC does not allow full recovery of the plant
costs, then the portion not allowed may have to be written off. In 1995, the
plant went into commercial operation. At December 31, 1995, Georgia Power's net
investment in the plant was approximately $190 million.
The final outcome of this matter cannot now be determined. Accordingly, no
provision for any write-down of the investment in the plant has been made.
FERC Reviews Equity Returns
In May 1991, the FERC ordered that hearings be conducted concerning the
reasonableness of the operating companies' 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
change in the rate of return on common equity that may require refunds as a
result of this proceeding would be substantially for the period beginning in
July 1991 and ending in October 1992.
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.
In August 1994, the FERC instituted another proceeding based on
substantially the same issues as in the 1991 proceeding. The second period under
review for possible refunds was substantially from October 1994 through December
1995. In November 1995, a FERC administrative law judge issued an opinion that
the FERC staff failed to meet its burden of proof, and therefore, no change in
the equity return was necessary. The FERC staff has filed exceptions to the
administrative law judge's opinion, and the matter is pending before the FERC.
If the rates of return on common equity recommended by the FERC staff were
applied to all of the schedules and contracts involved in both proceedings, and
refunds were ordered, the amount of refunds could range up to approximately $120
million at December 31, 1995. However, management believes that rates are not
excessive and that refunds are not justified.
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.
II-28
NOTES (continued)
The Southern Company and Subsidiary Companies 1995 Annual Report
In June 1995, the APSC issued a rate order granting Alabama Power's request
for gradual adjustments to move toward parity among customer classes. This order
also calls for a moratorium on any periodic retail rate increases (but not
decreases) until July 2001.
In December 1995, the APSC issued an order authorizing Alabama Power to
reduce balance sheet items -- such as plant and deferred charges -- at any time
the company's actual base rate revenues exceed the budgeted revenues. In
accordance with this order, Alabama Power reduced the unamortized balance of
premium on reacquired debt by $10 million in 1995.
The ratemaking procedures will remain in effect until the APSC votes to
modify or discontinue them.
Georgia Power Retail Rate Plan
On February 16, 1996, the GPSC approved a rate plan recommended by the GPSC
staff that concludes the GPSC's review of Georgia Power's earnings initiated in
early 1995 and addressed the company's proposed alternative retail rate plan.
Under the three-year plan, effective January 1, 1996, Georgia Power's earnings
will be evaluated against a retail return on common equity range of 10 percent
to 12.5 percent. Earnings in excess of 12.5 percent will be used to accelerate
the amortization of regulatory assets or accelerate the depreciation of electric
plant. At its option, Georgia Power may also accelerate amortization or
depreciation of assets while within the allowed return on common equity range.
The company is required to absorb cost increases of approximately $29 million
annually during the plan's three-year operation, including $14 million annually
of accelerated depreciation of electric plant. During the plan's operation,
Georgia Power will not file for a general base rate increase unless its
projected retail return on equity falls below 10 percent. On July 1, 1998,
Georgia Power is required to file a general rate case. In response, the GPSC
would be expected to either continue the rate plan or adopt a different one.
Georgia Power 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, pending the resolution of the
recovery of such costs.
After the Georgia Court of Appeals upheld the legality of the rate riders,
Georgia Power resumed collection under the riders in December 1994. In August
1995, the GPSC ordered Georgia Power to discontinue the demand-side conservation
programs by the end of 1995. However, Georgia Power's rate riders will continue
in effect until costs deferred are collected. Under the new retail rate plan,
approved February 16, 1996, Georgia Power will expense approximately $29 million
of deferred program costs over a three-year period that will not be recovered
under the rate riders.
4. CONSTRUCTION PROGRAM
The system companies are engaged in continuous construction programs, currently
estimated to total some $1.5 billion in 1996, $1.4 billion in 1997, and $1.3
billion in 1998. These estimates include AFUDC of $22 million in 1996, $22
million in 1997, and $25 million in 1998. 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, 1995, 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 600 megawatts is planned to be completed by 1998. In addition,
significant construction will continue related to transmission and distribution
facilities and the upgrading and extension of the useful lives of generating
plants.
II-29
NOTES (continued)
The Southern Company and Subsidiary Companies 1995 Annual Report
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, INVESTMENTS, AND COMMITMENTS
General
The Southern Company may require additional equity capital in 1996. The amount
and timing of additional equity capital to be raised in 1996 -- 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.
The operating companies' construction programs are expected to be financed
primarily from internal sources. Short-term debt is often utilized and the
amounts available are discussed below. The companies may issue additional
long-term debt and preferred stock primarily for the purposes of debt maturities
and for redeeming higher-cost securities if market conditions permit.
Southern Electric Investments
Southern Electric has substantial investments in production and delivery
facilities in the United States and various international markets. The most
recent acquisition was SWEB, and for additional information see Note 14.
Southern Electric's total assets were $5.0 billion at December 31, 1995. The
consolidated financial statements reflect investments in majority-owned or
controlled subsidiaries on a consolidated basis and other investments on an
equity basis.
Bank Credit Arrangements
At the beginning of 1996, unused credit arrangements with banks totaled $2.8
billion, of which approximately $1.5 billion expires at various times during
1996 and 1997; $16 million expires in February 1998; $73 million expires in May
1998; $400 million expires in June 1998; $300 million expires in July 1998; $300
million expires in November 1998; and $56 million expires in December 1998.
Also, $136 million expires in the years 1999 through 2002.
Georgia Power's revolving credit agreements of $60 million, all of which
remained unused as of December 31, 1995, expire May 1, 1998. 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.
Gulf Power's revolving credit agreements of $20 million, of which $13
million remained unused as of December 31, 1995, expire May 31, 1998. These
agreements allow short-term and/or term borrowings with various terms and
conditions regarding repayment. In connection with these credit arrangements,
Gulf 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, 1998, is under revolving credit
arrangements with several banks that provide 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, $100 million, $135
million, and $165 million available credit are currently dedicated to the
exclusive use of The Southern Company, 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.
The Southern Company has $300 million of revolving credit agreements
expiring July 1, 1998, and $300 million of revolving credit agreements expiring
November 30, 1998, all of which remained unused at 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 Southern Company's option. In connection with these credit
arrangements, The Southern Company agrees to pay commitment fees based on the
unused portions of the commitments or to maintain compensating balances with the
banks.
II-30
NOTES (continued)
The Southern Company and Subsidiary Companies 1995 Annual Report
Mississippi Power's revolving credit agreements of $40 million, all of which
remained unused as of December 31, 1995, expire December 1, 1998. 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's revolving credit arrangements of $20 million, of which
$16 million remained unused as of December 31, 1995, expire December 31, 1998.
These agreements allow short-term borrowings to be converted into terms 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.
Southern Electric's revolving credit agreements of $212 million, of which
$151 million remained unused as of December 31, 1995, expire at various times
from 1998 through 2002. These agreements allow for short-term borrowings with
various terms and conditions. These agreements require payment of commitment
fees based on the unused portions of the commitments.
A portion of the $2.8 billion unused credit arrangements with banks --
discussed earlier -- is allocated to provide liquidity support to the companies'
variable rate pollution control bonds. At December 31, 1995, the amount of
credit lines allocated was $692 million.
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 The Southern Company, Alabama Power, and
Georgia Power, through commercial paper programs that have the liquidity support
of committed bank credit arrangements.
Assets Subject to Lien
Each of The Southern Company's subsidiaries is organized as a legal entity,
separate, and apart from The Southern Company and its other subsidiaries. The
subsidiary 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. There are no agreements or
other arrangements among the subsidiary companies under which the assets of one
company have been pledged or otherwise made available to satisfy obligations of
The Southern Company or any of its subsidiaries.
Fuel and Purchase Power Commitments
To supply a portion of the fuel requirements of the generating plants, The
Southern 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. Also, The Southern Company has entered into various long-term
commitments for the purchase of electricity. Total estimated long-term
obligations at December 31, 1995, were as follows:
Purchased
Year Fuel Power
----------- -----------------------------
(in millions)
1996 $ 1,914 $ 495
1997 1,656 427
1998 1,482 155
1999 1,093 161
2000 728 166
2001 and thereafter 6,078 1,943
-------------------------------------------------------------
Total commitments $12,951 $3,347
=============================================================
II-31
NOTES (continued)
The Southern Company and Subsidiary Companies 1995 Annual Report
Operating Leases
The Southern Company has operating lease agreements with various terms and
expiration dates. These expenses totaled $17 million, $15 million, and $11
million for 1995, 1994, and 1993, respectively. At December 31, 1995, estimated
minimum rental commitments for noncancelable operating leases were as follows:
Year Amounts
-------- ----------------
(in millions)
1996 $ 22
1997 20
1998 19
1999 19
2000 20
2001 and thereafter 252
---------------------------------------------------------------
Total minimum payments $352
===============================================================
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, and the
city of Dalton, Georgia. In addition, Georgia Power has joint ownership
agreements with OPC for the Rocky Mountain project and with Florida Power
Corporation (FPC) for a combustion turbine unit at Intercession City, Florida.
In 1995, Georgia Power completed the sale of Unit 4 of Plant Scherer to
Florida Power & Light Company (FP&L) and Jacksonville Electric Authority (JEA).
FP&L owns approximately 76.4 percent of the unit, with JEA owning the remainder.
Georgia Power operates and maintains the unit.
At December 31, 1995, 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
---------------- ------------------------------
Plant Vogtle (in millions)
(nuclear) 45.7% $3,295 $730
Plant Hatch
(nuclear) 50.1 842 394
Plant Miller
(coal)
Units 1 and 2 91.8 712 281
Plant Scherer
(coal)
Units 1 and 2 8.4 112 39
Plant Wansley
(coal) 53.5 297 132
Rocky Mountain
(pumped storage) 25.4 200 10
------------------------------------------------------------------
In 1994, Georgia Power and FPC entered into a joint ownership agreement
regarding the Intercession City combustion turbine unit. The unit is scheduled
to be in commercial operation by the end of 1996, and will be constructed,
operated, and maintained by FPC. Georgia Power will have an approximate interest
of 33 percent in the 150-megawatt unit, with retention of 100 percent of the
capacity from June through September. FPC will have the capacity the remainder
of the year. Georgia Power's investment in the unit at completion is estimated
to be $14 million.
Alabama Power and Georgia Power have contracted to operate and maintain the
jointly owned facilities -- except for the Rocky Mountain project and
Intercession City -- 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.
7. LONG-TERM POWER SALES AGREEMENTS
The operating companies have long-term contractual agreements for the sale of
capacity and energy to certain non-affiliated utilities located outside the
system's service area. The agreements for non-firm capacity expired in 1994.
Other agreements --expiring at various dates discussed below -- are firm and
pertain to capacity related to specific generating units. Because the energy is
II-32
NOTES (continued)
The Southern Company and Subsidiary Companies 1995 Annual Report
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)
1995 $237 $ - $237
1994 257 19 276
1993 312 38 350
In 1994, long-term non-firm power of 200 megawatts was sold to FPC under a
contract that expired at year-end. In January 1995, the amount of unit power
sales to FPC increased by 200 megawatts.
Unit power from specific generating plants is currently being sold to FP&L,
FPC, JEA, and the city of Tallahassee, Florida. Under these agreements,
approximately 1,600 megawatts of capacity is scheduled to be sold annually
through 1999. Thereafter, these sales will decline to some 1,500 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.
8. INCOME TAXES
Effective January 1, 1993, The Southern Company adopted FASB Statement No. 109,
Accounting for Income Taxes. The adoption resulted in the recording of
additional deferred income taxes and related regulatory assets and liabilities.
At December 31, 1995, the tax- related regulatory assets and liabilities were
$1.4 billion and $936 million, respectively. These assets are attributable to
tax benefits flowed through to customers in prior years and to taxes applicable
to capitalized AFUDC. These liabilities are attributable to deferred taxes
previously recognized at rates higher than current enacted tax law and to
unamortized investment tax credits.
Details of the federal and state income tax provisions are as follows:
1995 1994 1993
---------------------------
(in millions)
Total provision for income taxes:
Federal --
Currently payable $567 $598 $421
Deferred -- current year 184 67 224
-- reversal of
prior years (111) (75) (51)
Deferred investment tax
credits 1 - (20)
-------------------------------------------------------------------
641 590 574
-------------------------------------------------------------------
State --
Currently payable 90 86 64
Deferred -- current year 26 15 39
-- reversal of
prior years (12) (11) (3)
-------------------------------------------------------------------
104 90 100
-------------------------------------------------------------------
International 24 5 3
-------------------------------------------------------------------
Total 769 685 677
Less income taxes charged
(credited) to other income (36) (26) (57)
-------------------------------------------------------------------
Federal and state income
taxes charged to operations $805 $711 $734
===================================================================
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:
1995 1994
-----------------------
(in millions)
Deferred tax liabilities:
Accelerated depreciation $2,795 $2,637
Property basis differences 2,175 1,647
Deferred plant costs 100 141
Other 247 271
-------------------------------------------------------------------
Total 5,317 4,696
-------------------------------------------------------------------
Deferred tax assets:
Federal effect of state deferred taxes 107 104
Other property basis differences 273 278
Deferred costs 118 79
Pension and other benefits 66 63
Other 192 225
-------------------------------------------------------------------
Total 756 749
-------------------------------------------------------------------
Net deferred tax liabilities 4,561 3,947
Portion included in current assets, net 50 60
-------------------------------------------------------------------
Accumulated deferred income taxes
in the Consolidated Balance Sheet $4,611 $4,007
===================================================================
II-33
NOTES (continued)
The Southern Company and Subsidiary Companies 1995 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 $38 million in 1995, $42 million in 1994, and $36 million in
1993. At December 31, 1995, 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:
1995 1994 1993
------------------------------
Federal statutory rate 35.0% 35.0% 35.0%
State income tax,
net of federal deduction 3.4 3.3 3.7
Non-deductible book
depreciation 1.6 1.8 1.9
Difference in prior years'
deferred and current tax rate (1.1) (1.5) (1.3)
Other 0.3 0.3 (1.1)
----------------------------------------------------------------------
Effective income tax rate 39.2% 38.9% 38.2%
======================================================================
The Southern Company files a consolidated federal income tax return. Under a
joint consolidated income tax agreement, each subsidiary's current and deferred
tax expense is computed on a stand-alone basis. Tax benefits from losses of the
parent company are allocated to each subsidiary based on the ratio of taxable
income to total consolidated taxable income.
9. 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 reflect the stock distribution.
Shares Reserved
At December 31, 1995, a total of 69 million shares was reserved for issuance
pursuant to the Dividend Reinvestment and Stock Purchase Plan, the Employee
Savings Plan, the Outside Directors Stock 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. As of December 31, 1995, some 200 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 the date of grant. Options outstanding will
expire no later than 10 years after the date of grant, unless terminated earlier
by the board of directors in accordance with the plan.
Stock option activity in 1994 and 1995 is summarized below:
Shares Average
Subject Option Price
To Option Per Share
-----------------------------------
Balance at December 31, 1993 1,364,810 $16.77
Options granted 446,443 18.88
Options canceled -- --
Options exercised (74,649) 14.81
---------------------------------------------------------------------
Balance at December 31, 1994 1,736,604 17.39
Options granted 1,161,174 21.63
Options canceled (8,088) 21.63
Options exercised (413,391) 14.34
---------------------------------------------------------------------
Balance at December 31, 1995 2,476,299 $19.87
=====================================================================
Shares reserved for future grants:
At December 31, 1993 3,714,444
At December 31, 1994 3,268,001
At December 31, 1995 2,114,915
---------------------------------------------------------------------
Options exercisable:
At December 31, 1994 793,989
At December 31, 1995 831,227
---------------------------------------------------------------------
Common Stock Dividend Restrictions
The income of The Southern Company is derived primarily from equity in earnings
of its subsidiaries. At December 31, 1995, consolidated retained earnings
included $3.1 billion of undistributed retained earnings of the subsidiaries. Of
this amount, $2.0 billion was restricted against the payment by the subsidiary
companies of cash dividends on common stock under terms of bond indentures or
charters.
II-34
NOTES (continued)
The Southern Company and Subsidiary Companies 1995 Annual Report
10. PREFERRED SECURITIES
In December 1994, Georgia Power Capital, L.P., of which Georgia Power is the
sole general partner, issued $100 million of 9 percent mandatorily redeemable
preferred securities. The sole asset of Georgia Power Capital is $103 million
aggregate principal amount of Georgia Power's 9 percent Junior Subordinated
Deferrable Interest Debentures due December 19, 2024. Georgia Power considers
that the mechanisms and obligations relating to the preferred securities, taken
together, constitute a full and unconditional guarantee by Georgia Power of
Georgia Power Capital's payment obligations with respect to the preferred
securities.
11. OTHER LONG-TERM DEBT
Details of other long-term debt at December 31 are as follows:
1995 1994
--------------------
(in millions)
Obligations incurred in connection
with the sale by public authorities
of tax-exempt pollution control
revenue bonds:
Collateralized --
4.375% to 9.375% due
2000-2025 $1,466 $1,179
Variable rates (3.5% to 6.1%
at 1/1/96) due 2011-2025 639 412
Non-collateralized --
7.25% due 2003 1 1
6.75% to 10.6% due 2015-2020 277 828
5.8% due 2022 10 10
Variable rates (3.25% to 3.75%
at 1/1/96) due 2019-2022 132 85
----------------------------------------------------------------
2,525 2,515
----------------------------------------------------------------
Capitalized lease obligations 147 148
----------------------------------------------------------------
Notes payable:
4.15% to 13% due 1995-1998 107 179
6.31% to 11% due 1999-2008 404 170
Adjustable rates (4% to 7% at
1/1/96) due 1995-1998 129 119
Adjustable rates (7.5% to 9.18%
at 1/1/96) due 1999-2000 165 130
Adjustable rate (7.7 % at
1/1/96) due 2000 926 -
----------------------------------------------------------------
1,731 598
----------------------------------------------------- ----------
Total $4,403 $3,261
================================================================
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 $122 million and $126 million at
December 31, 1995 and 1994, respectively. At December 31, 1995, the composite
interest rates for buildings and other were 9.7 percent and 11.3 percent,
respectively. Sinking fund requirements and/or serial maturities through 2000
applicable to other long-term debt are as follows: $264 million in 1996; $99
million in 1997; $42 million in 1998; $23 million in 1999; and $56 million in
2000.
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 at December 31 is as follows:
1995 1994
-----------------
(in millions)
Bond improvement fund requirements $ 43 $ 48
Less:
Portion to be satisfied by certifying
property additions 18 46
Reacquired bonds - -
------------------------------------------------------------------
Cash sinking fund requirements 25 2
First mortgage bond maturities
and redemptions 220 130
Other long-term debt maturities
(Note 11) 264 97
------------------------------------------------------------------
Total $509 $229
==================================================================
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.
II-35
NOTES (continued)
The Southern Company and Subsidiary Companies 1995 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 provides funds up to
$8.9 billion for 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 $162 million, respectively, per incident but
not more than an aggregate of $20 million per company 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 assessment in the event that losses exceed
accumulated reserve funds. Alabama Power's and Georgia Power's maximum annual
assessments are limited to $10 million and $12 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.
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 $2.8 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 $21 million and $24
million, respectively. The maximum replacement power assessments are $8 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 approximately $6 million
each.
All retrospective assessments -- whether generated for liability, property,
or replacement power -- may be subject to applicable state premium taxes.
II-36
NOTES (continued)
The Southern Company and Subsidiary Companies 1995 Annual Report
14. ACQUISITION
In 1995, Southern Electric acquired SWEB for approximately $1.8 billion. This
British utility distributes electricity to some 1.3 million customers.
The acquisition has been accounted for under the purchase method of
accounting. The acquisition cost exceeded the preliminary estimate of the fair
market value of net assets by $333 million. This amount is considered goodwill
and will be amortized on a straight-line basis over 40 years. The preliminary
estimate of net assets may be revised in 1996.
SWEB has been included in the consolidated financial statements since
September 1995. The following unaudited pro forma results of operations for the
years 1995 and 1994 have been prepared assuming the acquisition of SWEB,
effective January 1994, and assuming 100 percent short-term debt financing.
Eventually, the short-term borrowings will be replaced by a combination of
long-term debt and equity. The pro forma results are not necessarily indicative
of the actual results that would have been realized had the acquisition occurred
on the assumed date, nor are they necessarily indicative of future results. Pro
forma operating results are for information purposes only and are as follows:
15. SEGMENT INFORMATION
The Southern Company's principal business segment -- or its core business -- is
the five electric utility operating companies, which provide electric service in
four Southeastern states. The other reportable business segment is Southern
Electric, which owns and operates power production and delivery facilities in
the United States and various international markets. Financial data for business
segments and geographic areas are as follows:
Business Segments
II-37
NOTES (continued)
The Southern Company and Subsidiary Companies 1995 Annual Report
Geographic Areas
II-38
II-39
II-40A
II-40B
II-41
II-42A
II-42B
II-43
II-44A
II-44B
II-44C
II-45
II-46A
II-46B
II-46C
II-47
II-48A
II-48B
II-48C
II-49
II-50A
II-50B
II-50C
ALABAMA POWER COMPANY
FINANCIAL SECTION
II-51
Management's Report
Alabama Power Company 1995 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, 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 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
Elmer B. Harris
President
and Chief Executive Officer
/s/ William B. Hutchins, III
William B. Hutchins, III
Executive Vice President
and Chief Financial Officer
February 21, 1996
II-52
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, 1995 and 1994, and the related
statements of income, retained earnings, and cash flows for each of the three
years in the period ended December 31, 1995. These financial statements are the
responsibility of the company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements (pages II-61 through II-78)
referred to above present fairly, in all material respects, the financial
position of Alabama Power Company as of December 31, 1995 and 1994, and the
results of its operations and its cash flows for the periods stated, in
conformity with generally accepted accounting principles.
/s/ Arthur Andersen LLP
Birmingham, Alabama
February 21, 1996
II-53
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Alabama Power Company 1995 Annual Report
RESULTS OF OPERATIONS
Earnings
Alabama Power Company's 1995 net income after dividends on preferred stock was
$361 million, representing a $4.6 million (1.3 percent) increase from the prior
year. This improvement can be attributed to an increase in retail energy sales
of 4.7 percent from 1994 levels. This was primarily due to the extreme summer
weather during 1995, especially when compared to the mild weather of 1994. This
improvement was partially offset by a 2.6 percent increase in operating costs.
In 1994, earnings were $356 million, representing a 2.8 percent increase
from the prior year. This increase was due to lower operating expenses which
decreased 3.0 percent from the previous year. This improvement was partially
offset by reduced capacity sales to nonterritorial utilities. Net income was
also impacted by the mild weather in 1994.
The return on average common equity for 1995 was 13.61 percent compared to
13.86 percent in 1994, and 13.94 percent in 1993.
Revenues
Total revenues for 1995 were $3.0 billion, reflecting a 3.1 percent increase
from 1994. The following table summarizes the principal factors that affected
operating revenues for the past three years:
Increase (Decrease)
From Prior Year
----------------------------------------
1995 1994 1993
------------- ------------ -------------
(in thousands)
Retail --
Change in
base rates $ 990 $ -- $ --
Unbilled
adjustment -- 28,000 --
Sales growth 18,174 45,304 24,960
Weather 54,888 (39,964) 58,536
Fuel cost recovery
and other 35,235 (84,344) 96,437
---------------------------------------------------------------
Total retail 109,287 (51,004) 179,933
---------------------------------------------------------------
Sales for Resale --
Non-affiliates 15,380 (9,345) (43,686)
Affiliates (37,032) (17,213) 23,887
---------------------------------------------------------------
Total sales for resale (21,652) (26,558) (19,799)
Other operating
revenues 1,997 5,095 635
---------------------------------------------------------------
Total operating
revenues $89,632 $(72,467) $160,769
---------------------------------------------------------------
Percent change 3.1% (2.4)% 5.6%
---------------------------------------------------------------
Retail revenues of $2.5 billion in 1995 increased $109 million (4.6 percent)
from the prior year, compared with a decrease of $51 million (2.1 percent) in
1994. The hot weather during the summer of 1995 and higher fuel cost recovery
were the primary reasons for the increase in retail revenues over 1994. The mild
weather during 1994 and lower fuel cost recovery contributed to the decrease in
retail revenues from 1993. Fuel revenues, which increased in 1995, generally
represent the direct recovery of fuel expense, including the fuel component of
purchased energy, and therefore have no effect on net income.
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
II-54
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 1995 Annual Report
contracts. Energy is generally sold at variable cost. These capacity and energy
components, as well as the components of the sales to affiliated companies,
were:
1995 1994 1993
-------------------------------------------
(in thousands)
Capacity $158,825 $165,063 $187,062
Energy 209,376 222,579 233,253
----------------------------------------------------------
Total $368,201 $387,642 $420,315
----------------------------------------------------------
Capacity revenues from non-affiliates remained relatively constant in 1995
and 1994. Capacity revenues from sales to affiliates decreased $22 million in
1994. Sales to affiliated companies within the Southern electric system will
vary from year to year depending on demand, the availability, and the variable
production cost of generating resources at each company.
Kilowatt-hour (KWH) sales for 1995 and the percent change by year were as
follows:
KWH Percent Change
-------------------------------------------
1995 1995 1994 1993
-------------------------------------------
(millions)
Residential 14,383 9.1% (1.7)% 9.2%
Commercial 10,043 4.1 3.4 6.4
Industrial 19,863 2.0 3.2 1.8
Other 187 0.5 1.1 2.8
----------
Total retail 44,476 4.7 3.3 5.1
Sales for resale -
Non-affiliates 8,046 18.8 (5.2) (14.8)
Affiliates 6,705 (20.5) 4.3 12.1
----------
Total 59,227 2.6% 2.4% 3.0%
-----------------------------------------------------------------
The rate of increase in 1995 retail energy sales was fostered by the impact
of weather. Residential energy sales surged upward as a result of
hotter-than-normal summer weather in 1995, compared with the mild summer of
1994. The gains in commercial and industrial sales reflect the strength of
business and economic conditions in the company's service area.
Expenses
Total operating expenses of $2.4 billion for 1995 were up $60 million or 2.6
percent compared with 1994. The major components of this increase include $27
million in purchased power, $43 million in other operation expenses, $11 million
in depreciation and amortization, and $7 million in income taxes offset by
decreases in fuel costs and maintenance expenses of $10 million and $19 million,
respectively.
Total operating expenses of $2.3 billion for 1994 were down 3.0 percent
compared with the prior year. The decrease was mainly due to less coal-fired
generation and a lower average cost of fuel consumed. Coal-fired generation
decreased because it was displaced with lower cost nuclear and hydro generation.
Fuel costs constitute 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. The amount and sources of generation and the average cost of
fuel per net kilowatt-hour generated were as follows:
--------------------------
1995 1994 1993
-------------------------
Total generation
(billions of kilowatt-hours) 58 57 55
Sources of generation
(percent) --
Coal 73 68 70
Nuclear 19 23 22
Hydro 8 9 8
Average cost of fuel per net
kilowatt-hour generated
(cents) --
Coal 1.71 1.92 2.11
Nuclear 0.50 0.49 0.51
Total 1.48 1.56 1.73
--------------------------------------------------------------
Note: Oil & Gas comprise less than 0.5% of generation.
Fuel expense decreased in 1995 by $10 million or 1.3 percent. This decrease
resulted from lower average cost of fuel consumed. Fuel expense decreased in
1994 by $75 million (8.6 percent) from the previous year. This decrease is
attributable to the increase in availability of nuclear and hydro generation and
a decrease in the cost of fuel.
The increase in purchased power is primarily attributable to the
exceptionally hot summer weather. Purchased power consists primarily of
purchases from the affiliates of the Southern electric system. Purchased power
II-55
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 1995 Annual Report
transactions among the company and its affiliates will vary from period to
period depending on demand, the availability, and the variable production cost
of generating resources at each company. KWH purchases from affiliates increased
18 percent from the prior year.
Other operation expenses increased 9.4 percent in 1995 following a 2.5
percent decrease in 1994. This increase over 1994 is primarily attributable to
the 1995 expenses not reflecting the positive impact of the amortization of the
Gulf States Utilities settlement which expired in 1994.
The decrease in maintenance expenses for 1995 reflects the establishment in
September 1994 of a Natural Disaster Reserve. This also caused the increase in
1994 maintenance expenses over 1993. See Note 1 to the financial statements
under "Natural Disaster Reserve" for additional information.
Depreciation and amortization expense increased 3.6 percent in 1995. This
increase reflects additions to utility plant. The amount for 1994 was virtually
unchanged from the previous year because of lower average depreciation rates
effective January 1994 and offsetting growth in depreciable plant in service.
Income tax expense increased 3.0 percent and 8.2 percent in 1995 and 1994,
respectively. These increases are primarily attributable to higher taxable
income.
The company contributed $11.5 million to the Alabama Power Foundation, Inc.
in 1995, which represents a decrease of $2.0 million from the previous year. The
Foundation makes distributions to qualified entities which are organized
exclusively for charitable, educational, literary, and scientific purposes.
Total net interest charges and preferred stock dividends rose in 1995 to
$265 million, an increase of 12.2 percent. This increase results from (i)
interest on interim obligations which rose due to higher average interest rates
on an increased average amount of short-term debt outstanding and (ii)
amortization of debt discount, premium, and expense, net pursuant to an APSC
order. See Note 3 to the financial statements under "Retail Rate Adjustment
Procedures" for additional details. The decline in net interest charges in 1994
by $23 million (9.0 percent) reflects the benefits from refinancing.
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 energy sales growth to a less regulated more
competitive environment.
Future earnings in the near term will depend upon growth in electric sales,
which are subject to a number of factors. Traditionally, these factors have
included weather, competition, changes in contracts with neighboring utilities,
energy conservation practiced by customers, the elasticity of demand, and the
rate of economic growth in the company's service area. However, the Energy
Policy Act of 1992 (Energy Act) is beginning to have a dramatic 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 positioning the business to meet the challenge of this
major change in the traditional practice 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. This enhances 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.
Also, electricity sales for resale rates are being driven down by wholesale
transmission access and numerous potential new energy suppliers, including power
II-56
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 1995 Annual Report
marketers and brokers. The company is aggressively working to maintain and
expand its share of wholesale sales in the Southeastern power markets.
Although the Energy Act does not require transmission access to retail
customers, retail wheeling initiatives are rapidly evolving and becoming very
prominent issues in several states. New federal legislation is being discussed,
and legislation allowing customer choice has already been introduced in Florida
and Georgia. In order to address these initiatives, numerous questions must be
resolved, with the most complex ones relating to transmission pricing and
recovery of stranded investments. As the initiatives become a reality, the
structure of the utility industry could radically change. Therefore, unless the
company remains a low-cost producer and provides quality service, the company's
retail energy sales growth could be limited, and this could significantly erode
earnings. Conversely, being the low-cost producer could provide significant
opportunities to increase market share and profitability by seeking new markets
that evolve with the changing regulation.
The addition of four combustion turbine generating units in 1996 will
increase related operation and maintenance expenses and depreciation expenses.
These additions are to ensure reliable service to its customers during critical
peak times.
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. In June 1995, the APSC issued an order granting
the company's request for gradual adjustments to move toward parity among
customer classes. This order also calls for a moratorium on any periodic retail
rate increases (but not decreases) until 2001.
In December 1995, the APSC issued an order authorizing the company to reduce
balance sheet items
-- such as plant and deferred charges -- at any time the company's actual base
rate revenues exceed the budgeted revenues. See Note 3 to the financial
statements for information about this and other regulatory matters.
The staff of the Securities and Exchange Commission has questioned certain
of the current accounting practices of the electric utility industry --
including the company -- regarding the recognition, measurement, and
classification of decommissioning costs for nuclear generating facilities in the
financial statements. In response to these questions, the Financial Accounting
Standards Board (FASB) has decided to review the accounting for liabilities
related to closure and removal of long-lived assets, including nuclear
decommissioning. If the FASB issues new accounting rules, the estimated costs of
closing and removing the company's nuclear and other facilities may be required
to be recorded as liabilities in the Balance Sheets. Also, the annual provisions
for such costs could increase. Because of the company's current ability to
recover closure and removal costs through rates, these changes should not have a
significant adverse effect on results of operations. See Note 1 to the financial
statements under "Depreciation and Nuclear Decommissioning" for additional
information.
Compliance costs related to the Clean Air Act Amendments of 1990 (Clean Air
Act) could affect earnings if such costs are not fully recovered. The Clean Air
Act and other important environmental items are discussed later under
"Environmental Matters."
The company is subject to the provisions of FASB Statement No. 71,
Accounting for the Effects of Certain Types of Regulation. In the event that a
portion of the company's operations is no longer subject to these provisions,
the company would be required to write off related regulatory assets and
liabilities, and determine if any other assets have been impaired. See Note 1 to
the financial statements under "Regulatory Assets and Liabilities" for
additional information.
New Accounting Standards
The FASB has issued Statement No. 121, Accounting for the Impairment of
Long-Lived Assets and Long-Lived Assets to be Disposed of. This statement
requires that long-lived assets be reviewed for impairment whenever events or
changes in circumstances indicate that the carrying amount for an asset may not
be recoverable. This statement also imposes stricter criteria for regulatory
assets by requiring that such assets be probable of future recovery at each
balance sheet date. The company adopted the new rules January 1, 1996, with no
material effect on the financial statements. However, this conclusion may change
in the future as competitive factors influence wholesale and retail pricing in
the utility industry.
II-57
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 1995 Annual Report
FINANCIAL CONDITION
Overview
The company's financial condition remained stable in 1995. This stability is the
continuation over recent years of growth in energy sales and cost control
measures 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.
The company had gross property additions of $552 million in 1995. The
majority of funds needed for gross property additions for the last several years
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.
Capital Structure
The company's ratio of common equity to total capitalization -- including
short-term debt -- was 45.0 percent in 1995, compared with 45.9 percent in 1994,
and 46.5 percent in 1993.
In 1995, the company issued through public authorities, $131.5 million of
pollution control revenue refunding bonds. Composite financing rates as of
year-end for 1993 through 1995 were as follows:
1995 1994 1993
--------------------------------
Composite interest rate on
long-term debt 7.02% 7.39% 7.35%
Composite dividend rate on
preferred stock 6.04% 6.23% 5.80%
----------------------------------------------------------------
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 $491 million for 1996, $446 million for
1997, and $479 million for 1998. The total is $1.4 billion for the three years.
Actual capital costs may vary from this estimate because of factors such as
changes in business conditions; revised load growth projections; changes in
environmental regulations; changes in the existing nuclear plant to meet new
regulatory requirements; increasing cost of labor, equipment, and materials; and
cost of capital. In addition, there can be no assurance that costs related to
capital expenditures will be fully recovered.
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 addition of combustion
turbine peaking units of approximately 320 megawatts of capacity is planned in
1996 to meet increased peak-hour demands. In addition, significant construction
of transmission and distribution facilities and upgrading of generating plants
will continue.
Other Capital Requirements
In addition to the funds needed for the capital budget, approximately $110
million will be required by the end of 1998 for maturities of first mortgage
bonds. Also, the company will continue to retire higher-cost debt and preferred
stock and replace these obligations with lower-cost capital if market conditions
permit.
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 -- has significantly
impacted the Southern electric system. Specific reductions in sulfur dioxide and
nitrogen oxide emissions from fossil-fired generating plants are required in two
phases. Phase I compliance began in 1995 and affected 28 generating units in the
Southern electric system. As a result of The Southern Company's compliance
strategy, an additional 22 generating units were brought into compliance with
Phase I requirements. Phase II compliance is required in 2000, and all
fossil-fired generating plants will be affected.
II-58
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 1995 Annual Report
In 1995, the Environmental Protection Agency (EPA) began issuing annual
sulfur dioxide emission allowances through the allowance trading program. An
emission allowance is the authority to emit one ton of sulfur dioxide during a
calendar year. The method for issuing 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 Southern Company's sulfur dioxide compliance strategy is
designed to use allowances as a compliance option.
The Southern Company achieved Phase I sulfur dioxide compliance at the
affected plants by switching to low-sulfur coal, which required some equipment
upgrades. This compliance strategy resulted in unused emission allowances being
banked for later use. Compliance with nitrogen oxide emission limits was
achieved by the installation of new control equipment at 22 of the original 28
affected generating units. Construction expenditures for Phase I compliance
totaled approximately $320 million through 1995 for The Southern Company, of
which the company's portion was approximately $32 million.
For Phase II 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 Phase II limits.
Therefore, during the period 1996 to 2000, current compliance strategy could
require total estimated construction expenditures of approximately $150 million
for The Southern Company, of which the company's portion is approximately $96
million. However, the full impact of Phase II compliance cannot now be
determined with certainty, pending the continuing 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 1 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 Title IV of the Clean Air Act. Compliance costs
include construction expenditures, increased costs for switching to low-sulfur
coal, and costs related to emission allowances.
A significant portion of costs related to the acid rain provision of the
Clean Air Act is expected to be recovered through existing ratemaking
provisions. However, 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 EPA is scheduled to submit a report
to Congress on the results of this study during 1996. The report will include 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 is evaluating the need to revise the ambient air quality standards
for particulate matter 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 1996, the EPA may 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
II-59
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 1995 Annual Report
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. The company
conducts studies to determine the extent of any required cleanup costs and has
recognized in the financial statements costs to clean up known sites.
Several major pieces of environmental legislation are being considered for
reauthorization or amendment by Congress. These include: the Clean Air Act; the
Clean Water Act; the Comprehensive Environmental Response, Compensation, and
Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances
Control Act; and the Endangered Species 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 additional 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 exists for
liability as the result of lawsuits alleging damages caused by electromagnetic
fields.
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. In 1994, the company also established an external trust fund for
postretirement benefits as ordered by the APSC. 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."
II-60
II-61
II-62
II-63
II-64
II-65
II-66
NOTES TO FINANCIAL STATEMENTS
Alabama Power Company 1995 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING
POLICIES
General
Alabama Power Company (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 Communications Services (Southern Communications),
Southern Electric International (Southern Electric), Southern Nuclear Operating
Company (Southern Nuclear), The Southern Development and Investment Group
(Southern Development), and other direct and indirect subsidiaries. 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 subsidiary companies. Southern
Communications provides digital wireless communications services to the
operating companies and also markets these services to the public within the
Southeast. Southern Electric designs, builds, owns and operates power production
and delivery 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. Southern Development develops new business
opportunities related to energy products and services.
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 Alabama Public Service
Commission (APSC). The company follows generally accepted accounting principles
and complies with the accounting policies and practices prescribed by the
respective regulatory commissions. The preparation of financial statements in
conformity with generally accepted accounting principles requires the use of
estimates, and the actual results may differ from those estimates.
Regulatory Assets and Liabilities
The company is subject to the provisions of Financial Accounting Standards Board
(FASB) Statement No. 71, Accounting for the Effects of Certain Types of
Regulation. Regulatory assets represent probable future revenues to the company
associated with certain costs that are expected to be recovered from customers
through the ratemaking process. Regulatory liabilities represent probable future
reductions in revenues associated with amounts that are to be credited to
customers through the ratemaking process. Regulatory assets and (liabilities)
reflected in the Balance Sheets at December 31 relate to:
1995 1994
-----------------------
(in thousands)
Deferred income taxes $436,837 $451,886
Premium on reacquired debt 89,967 101,620
Department of Energy assessments 40,282 42,996
Vacation pay 29,458 20,442
Work force reduction costs 48,402 3,664
Deferred income tax credits (386,038) (405,256)
Natural disaster reserve (17,959) (28,750)
Other, net 39,172 45,956
================================================================
Total $280,121 $232,558
================================================================
In the event that a portion of the company's operations is no longer subject
to the provisions of Statement No. 71, the company would be required to write
off related regulatory assets and liabilities. In addition, the company would be
required to determine any impairment to other assets, including plant, and write
down the assets, if impaired, to their fair value.
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.
II-67
NOTES (continued)
Alabama Power Company 1995 Annual Report
The company has a diversified base of customers. No single customer or
industry comprises 10 percent or more of revenues. In 1995, uncollectible
accounts continued to average less than 1 percent of revenues.
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 $54
million in 1995, $65 million in 1994, and $62 million in 1993. The company has a
contract with the U.S. Department of Energy (DOE) that provides for the
permanent disposal of spent nuclear fuel. Although disposal was scheduled to
begin in 1998, 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
estimates its remaining liability at December 31, 1995, under this law to be
approximately $40 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
3.2 percent in 1995 and 1994, and 3.3 percent in 1993. 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 and removal of other facilities.
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. The company
has established external trust funds to comply with the NRC's regulations.
Amounts previously recorded in internal reserves are being transferred into the
external trust funds over set periods of time as approved by the APSC. 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 amounts prescribed by the NRC.
Site study cost is the estimate to decommission the facility as of the
site study year, and ultimate cost is the estimate to decommission the facility
as of retirement date. The estimated costs of decommissioning -- both site study
costs and ultimate costs -- at December 31, 1995, for Plant Farley were as
follows:
Plant
Farley
----------------
Site study basis (year) 1993
Decommissioning periods:
Beginning year 2017
Completion year 2029
-----------------------------------------------------------
(in millions)
Site study costs:
Radiated structures $ 489
Non-radiated structures 89
===========================================================
Total $ 578
===========================================================
(in millions)
Ultimate costs:
Radiated structures $ 1,504
Non-radiated structures 274
===========================================================
Total $ 1,778
===========================================================
II-68
NOTES (continued)
Alabama Power Company 1995 Annual Report
(in millions)
Amount expensed in 1995 $ 18
-----------------------------------------------------------
Accumulated provisions:
Balance in external trust funds $108
Balance in internal reserves 49
===========================================================
Total $157
===========================================================
Assumed in ultimate costs:
Inflation rate 4.5%
Trust earning rate 7.0
-----------------------------------------------------------
Annual provisions for nuclear decommissioning are based on an annuity --
sinking fund -- method as approved by the APSC. The decommissioning costs
approved for ratemaking are $578 million for Plant Farley.
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 changes in the assumed date of
decommissioning, changes in NRC requirements, or changes in the assumptions used
in making estimates.
Income Taxes
The company uses the liability method of accounting for deferred income taxes
and 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.
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 was 7.1 percent in 1995, 7.9 percent in 1994, and 7.8 percent in 1993.
AFUDC, net of income tax, as a percent of net income after dividends on
preferred stock was 1.7 percent in 1995 and 1.5 percent in both 1994 and 1993.
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.
Financial Instruments
In accordance with FASB Statement No. 107, Disclosure About Fair Value of
Financial Instruments, the company's only financial instrument for which the
carrying amount did not approximate fair value at December 31 was as follows:
Long-Term Debt
-------------------------
Carrying Fair
Year Amount Value
----------- ----------
(in millions)
1995 $2,451 $2,577
1994 2,446 2,323
------------------------------------------------------------
The fair value for long-term debt was based on either closing market price
or closing price 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.
Natural Disaster Reserve
In September 1994, in response to a request by the company, the APSC issued an
order allowing the company to establish a Natural Disaster Reserve. As of
December 31, 1995, the accumulated provision amounted to $18.0 million. This
balance is down from the December 31, 1994 balance of $28.8 million, due to
charges related primarily to Hurricane Opal, somewhat offset by a $10 million
accrual to partially replenish the reserve. Regulatory treatment allows the
II-69
NOTES (continued)
Alabama Power Company 1995 Annual Report
company to accrue $250 thousand per month, until the maximum accumulated
provision of $32 million is attained. However, in December 1995, the APSC
approved higher accruals to restore the reserve to its authorized level whenever
the balance in the reserve declines below $22.4 million.
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 one of the
following formulas: years of service and final average pay or years of service
and a flat-dollar benefit. Primarily, 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 trusts 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. Amounts funded are primarily invested in debt and
equity securities. In December 1993, the APSC issued an accounting policy
statement which requires the company to externally fund net annual
postretirement benefits.
FASB Statement No. 106, Employers' Accounting for Postretirement Benefits
Other Than Pensions, 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."
Funded Status and Cost of Benefits
The following tables show actuarial results and assumptions for pension and
postretirement insurance benefits as computed under the requirements of
Statement Nos. 87 and 106, respectively. The funded status of the plans at
December 31 was as follows:
Pension
-----------------------
1995 1994
------------- ---------
(in millions)
Actuarial present value of
benefit obligations:
Vested benefits $ 604 $ 522
Non-vested benefits 25 18
------------------------------------------------------------------
Accumulated benefit obligation 629 540
Additional amounts related to
projected salary increases 173 174
------------------------------------------------------------------
Projected benefit obligation 802 714
Less:
Fair value of plan assets 1,256 1,059
Unrecognized net gain (331) (251)
Unrecognized prior service cost 21 23
Unrecognized transition asset (45) (51)
------------------------------------------------------------------
Prepaid asset recognized in the
Balance Sheets $ 99 $ 66
==================================================================
Postretirement
Benefits
----------------------
1995 1994
----------------------
(in millions)
Actuarial present value of
benefit obligation:
Retirees and dependents $ 103 $ 96
Employees eligible to retire 31 22
Other employees 104 119
-----------------------------------------------------------
Accumulated benefit obligation 238 237
Less:
Fair value of plan assets 89 61
Unrecognized net loss 23 -
Unrecognized transition
obligation 72 120
-----------------------------------------------------------
Accrued liability recognized
in the Balance Sheets $ 54 $ 56
===========================================================
In 1995, the system companies announced a cost sharing program for
postretirement benefits. The program establishes limits on amounts the company
will pay to provide future retiree postretirement benefits. This change reduced
the 1995 accumulated postretirement benefit obligation by approximately $41
million.
II-70
NOTES (continued)
Alabama Power Company 1995 Annual Report
The weighted average rates assumed in the actuarial calculations were:
1995 1994 1993
-------------------------------
Discount 7.3% 8.0% 7.5%
Annual salary increase 4.8 5.5 5.0
Long-term return on
plan assets 8.5 8.5 8.5
----------------------------------------------------------
An additional assumption used in measuring the accumulated postretirement
benefit obligation was a weighted average medical care cost trend rate of 9.8
percent for 1995, decreasing gradually to 5.3 percent through the year 2005 and
remaining at that level thereafter. An annual increase in the assumed medical
care cost trend rate of 1 percent would increase the accumulated benefit
obligation as of December 31, 1995, by $20 million and the aggregate of the
service and interest cost components of the net retiree cost by $4 million.
Components of the plans' net income are shown below:
Pension
--------------------------------------------------------------
1995 1994 1993
-----------------------------
(in millions)
Benefits earned during
the year $ 21.2 $ 20.8 $ 20.6
Interest cost on projected
benefit obligation 54.3 51.2 50.4
Actual (return) loss on plan
assets (236.3) 23.5 (146.3)
Net amortization and deferral 136.9 (116.2) 63.3
==============================================================
Net pension income $(23.9) $(20.7) $(12.0)
==============================================================
Of the above net pension income, $(17.1) million in 1995, $(15.7)
million in 1994, and $(8.9) million in 1993 were recorded in operating expenses,
and the remainder was recorded in construction and other accounts.
Postretirement
Benefits
--------------------
1995 1994 1993
--------------------
(in millions)
Benefits earned during the year $ 7 $ 8 $ 7
Interest cost on accumulated
benefit obligation 18 18 16
Amortization of transition
obligation 7 6 6
Actual (return) loss on plan
assets (10) 1 (5)
Net amortization and deferral 5 (4) 2
=============================================================
Net postretirement costs $ 27 $ 29 $ 26
=============================================================
Of the above net postretirement costs recorded, $22.7 million in 1995, $23
million in 1994, and $22 million in 1993 were charged to operating expenses and
the remainder was charged to construction and other accounts.
Work Force Reduction Programs
The company has incurred additional costs for work force reduction programs. The
costs related to these programs were $14.3 million, $8.2 million and $16.1
million for the years 1995, 1994 and 1993, respectively. In addition, certain
costs of these programs were deferred and are being amortized in accordance with
regulatory treatment. The unamortized balance of these costs was $48.4 million
at December 31, 1995.
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.
In June 1995, the APSC issued a rate order granting the company's request
for gradual adjustments to move toward parity among customer classes. This order
II-71
NOTES (continued)
Alabama Power Company 1995 Annual Report
also calls for a moratorium on any periodic retail rate increases (but not
decreases) until July 2001.
In December 1995, the APSC issued an order authorizing the company to reduce
balance sheet items -- such as plant and deferred charges -- at any time the
company's actual base rate revenues exceed the budgeted revenues. In accordance
with this order, the company reduced the unamortized balance of Premium on
reacquired debt by $10 million in 1995.
The ratemaking procedures will remain in effect until the APSC votes to
modify or discontinue them.
FERC Reviews Equity Returns
In May 1991, the FERC ordered that hearings be conducted concerning the
reasonableness of the operating companies' 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
change in the rate of return on common equity that may require refunds as a
result of this proceeding would be substantially for the period beginning in
July 1991 and ending in October 1992.
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.
In August 1994, the FERC instituted another proceeding based on
substantially the same issues as in the 1991 proceeding. The second period under
review for possible refunds was substantially from October 1994 through December
1995. In November 1995, a FERC administrative law judge issued an opinion that
the FERC staff failed to meet its burden of proof, and therefore, no change in
the equity return was necessary. The FERC staff has filed exceptions to the
administrative law judge's opinion, and the matter is pending before the FERC.
If the rates of return on common equity recommended by the FERC staff were
applied to all of the schedules and contracts involved in both proceedings, and
refunds were ordered, the amount of refunds could range up to approximately $120
million at December 31, 1995 for the Southern Company, of which the company's
portion would be approximately $53 million. However, management believes that
rates are not excessive, and that refunds are not justified.
4. CAPITAL BUDGET
The company's capital expenditures are currently estimated to total $491 million
in 1996, $446 million in 1997, and $479 million in 1998. The estimates include
AFUDC of $7 million in 1996, $6 million in 1997, and $9 million in 1998. 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, 1995, 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 320 megawatts is planned to be completed in 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 at
appropriate levels. The amounts available are discussed below. The company may
issue additional long-term debt and preferred stock for the purposes of debt
maturities, redeeming higher-cost securities, and meeting additional capital
requirements.
II-72
NOTES (continued)
Alabama Power Company 1995 Annual Report
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 company's primary sources of external financing are sales of first mortgage
bonds and preferred stock to the public and receipt of additional paid-in
capital from The Southern Company. 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. The company's
coverages are at a level that would permit any necessary amount of security
sales at current interest and dividend rates.
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, 1998. 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 require 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 $353.5 million which expire at various times during 1996 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.
At December 31, 1995, the company had regulatory approval to have
outstanding up to $530 million of short-term borrowings. In February 1996, such
regulatory approval was increased to $750 million.
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 at December 31, 1995, were as follows:
Year Amounts
---- --------------
(in millions)
1996 $ 866
1997 852
1998 853
1999 672
2000 402
2001 - 2013 3,790
=========================================================
Total commitments $7,435
=========================================================
Operating Leases
The company has entered into coal rail car rental agreements with various terms
and expiration dates. At December 31, 1995, estimated minimum rental commitments
for noncancellable operating leases were as follows:
II-73
NOTES (continued)
Alabama Power Company 1995 Annual Report
Year Amounts
---- --------------------
(in millions)
1996 $ 2.8
1997 2.8
1998 2.9
1999 2.9
2000 2.9
2001 and thereafter 56.5
===============================================================
Total minimum payments $70.8
===============================================================
6. 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 which, in
substance, requires payments sufficient to provide for the operating expenses,
taxes, interest expense and a return on equity, whether or not SEGCO has any
capacity and energy available. The company's share of expenses totaled $71
million in 1995, $74 million in 1994 and $86 million in 1993, and is included in
"Purchased power from affiliates" in the Statements of Income.
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, 1995, the capitalization of SEGCO consisted of $54 million
of equity and $78 million of long-term debt on which the annual interest
requirement is $5.0 million. SEGCO paid dividends totaling $7.6 million in 1995,
$11.6 million in 1994, and $11.3 million in 1993, of which one-half of each was
paid to the company. SEGCO's net income was $8.1 million, $7.2 million, and $8.3
million for 1995, 1994 and 1993, respectively.
The company's percentage ownership and investment in jointly-owned
generating plants at December 31, 1995, 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 Alabama Electric Cooperative, Inc.
Company Accumulated
Facility Investment Depreciation
--------------------- -------------- -----------------
(in millions)
Greene County $ 90 $ 41
Plant Miller
Units 1 and 2 712 281
-------------------------------------------------------------
7. LONG-TERM POWER SALES AGREEMENTS
General
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 area. The
agreements for non-firm capacity expired in 1994. Other agreements -- expiring
at various dates discussed below -- 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 capacity revenues have been as follows:
Unit Other
Year Power Long-Term Total
----------------------------------------------------------
(in millions)
1995 $ 157 $ - $ 157
1994 152 7 159
1993 144 15 159
----------------------------------------------------------
Unit power from Plant Miller is being sold to Florida Power Corporation
(FPC), Florida Power & Light Company (FP&L), Jacksonville Electric Authority
(JEA) and the City of Tallahassee, Florida. Under these agreements,
II-74
NOTES (continued)
Alabama Power Company 1995 Annual Report
approximately 1,200 megawatts of capacity is scheduled to be sold through 1999.
Thereafter, these sales will 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.
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,
1995, $137.5 million of such bonds was 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 resulted in the recording of
additional deferred income taxes and related regulatory assets and liabilities.
At December 31, 1995, the tax-related regulatory assets and liabilities were
$437 million and $386 million, respectively. These assets are attributable to
tax benefits flowed through to customers in prior years and to taxes applicable
to capitalized AFUDC. These liabilities are attributable to deferred taxes
previously recognized at rates higher than current enacted tax law and to
unamortized investment tax credits.
Details of the federal and state income tax provisions are as follows:
1995 1994 1993
--------------------------------
(in thousands)
Total provision for income taxes:
Federal --
Currently payable $166,105 $219,494 $149,680
Deferred --
current year 43,493 (48,153) 9,636
reversal of prior years (15,817) 15,932 19,653
Deferred investment tax
credits (75) (1) (2,106)
----------------------------------------------------------------
193,706 187,272 176,863
----------------------------------------------------------------
State --
Currently payable 18,108 20,565 14,297
Deferred --
current year 5,117 (4,067) 1,898
reversal of prior years (91) 3,676 3,913
----------------------------------------------------------------
23,134 20,174 20,108
----------------------------------------------------------------
Total 216,840 207,446 196,971
Less income taxes credited
to other income (14,142) (16,834) (10,239)
----------------------------------------------------------------
Federal and state income
taxes charged to operations $230,982 $224,280 $207,210
================================================================
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:
II-75
NOTES (continued)
Alabama Power Company 1995 Annual Report
1995 1994
--------------------------------------------------------------
(in millions)
Deferred tax liabilities:
Accelerated depreciation $ 780 $734
Property basis differences 491 513
Premium on reacquired debt 31 38
Fuel clause underrecovered 5 4
Other 37 26
--------------------------------------------------------------
Total 1,344 1,315
--------------------------------------------------------------
Deferred tax assets:
Capacity prepayments 35 36
Other deferred costs 26 27
Postretirement benefits 25 24
Accrued nuclear outage costs - 7
Unbilled revenue 13 13
Other 43 44
--------------------------------------------------------------
Total 142 151
--------------------------------------------------------------
Net deferred tax liabilities 1,202 1,164
Portion included in current assets
(liabilities), net (10) 17
--------------------------------------------------------------
Accumulated deferred income taxes
in the Balance Sheets $1,192 $1,181
==============================================================
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 $12 million in 1995 and $13 million in 1994 and 1993. At December
31, 1995, 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:
1995 1994 1993
--------------------------
Federal statutory rate 35.0% 35.0% 35.0%
State income tax,
net of federal deduction 2.5 2.2 2.3
Non-deductible book
depreciation 1.6 1.6 1.6
Differences in prior years'
deferred and current tax rates (1.8) (2.9) (1.6)
Other (1.4) (0.7) (2.9)
==============================================================
Effective income tax rate 35.9% 35.2% 34.4%
==============================================================
The Southern Company files a consolidated federal income tax return. Under a
joint consolidated income tax agreement, each subsidiary's current and deferred
tax expense is computed on a stand-alone basis. Tax benefits from losses of the
parent company are allocated to each subsidiary based on the ratio of taxable
income to total consolidated taxable income.
9. OTHER LONG-TERM DEBT
Details of other long-term debt at December 31 are as follows:
1995 1994
--------------------------
(in thousands)
Obligations incurred in
connection with the
sale of tax-exempt
pollution control revenue
bonds by public authorities-
Collateralized -
5.5% to 6.5 % due
2023-2024 $223,040 $223,040
Variable rates (5.0% to
6.0% at 1/1/96) due
2015-2017 89,800 89,800
Non-collateralized -
7.25% due 2003 1,000 1,000
7.4% to 9.375% due
2014-2016 21,000 152,500
5.8% due 2022 9,800 9,800
Variable rates (5.3% to
6.0% at 1/1/96) due
2022 131,500 -
-------------------------------------------------------------
476,140 476,140
Capitalized lease obligations 8,963 9,754
=============================================================
Total $485,103 $485,894
=============================================================
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 $312.8 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.
II-76
NOTES (continued)
Alabama Power Company 1995 Annual Report
The company has capitalized certain office building leases and a street light
lease. In December 1994, the company discontinued capital leases pertaining to
nuclear fuel.
The net book value of capitalized leases included in utility plant in service
was $5.6 million and $6.2 million at December 31, 1995 and 1994, respectively.
The estimated aggregate annual maturities of other long-term debt through 2000
are as follows: $0.9 million in 1996, $1.0 million in 1997, $1.0 million in
1998, $1.2 million in 1999 and $1.1 million in 2000.
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 at December 31 is as follows:
1995 1994
----------------------
(in thousands)
Bond improvement fund
requirements $20,047 $ 20,047
Less:
Portion to be satisfied by
certifying property additions - 20,047
------------------------------------------------------------
Cash sinking fund requirements $20,047 $ -
First mortgage bond maturities
and redemptions 63,750 -
Other long-term debt maturities
(Note 9) 885 796
============================================================
Total $84,682 $ 796
============================================================
The annual first mortgage bond improvement fund requirement is 1 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 1996 requirement of $20.0 million was
satisfied by the deposit of cash in 1996. Also in 1996 are first mortgage bond
maturities and redemptions of $64 million and maturities of $885 thousand
consisting primarily of capitalized office building leases and a street light
lease.
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 provides funds up to $8.9 billion for 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 assessment in the event that losses exceed accumulated
reserve funds. The company's maximum annual assessment per incident is limited
to $10 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.
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 $2.8 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
II-77
NOTES (continued)
Alabama Power Company 1995 Annual Report
that policy. The maximum annual assessments per incident under current policies
for the company would be $21 million for excess property damage and $8 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 $6 million.
All retrospective assessments, whether generated for liability, property
or replacement power may be subject to applicable state premium taxes.
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, 1995, retained earnings of $807 million 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 1995 and 1994 are as follows:
Net Income
After
Dividends
Quarter Operating Operating on Preferred
Ended Revenues Income Stock
---------------- ----------------------------------------------
(in thousands)
March 1995 $646,771 $122,949 $ 65,328
June 1995 753,053 157,685 88,926
September 1995 938,284 233,322 167,938
December 1995 686,666 111,362 38,702
March 1994 $686,847 $128,623 $ 72,031
June 1994 759,399 162,696 98,668
September 1994 838,927 199,736 141,214
December 1994 649,969 104,949 44,425
----------------------------------------------------------------
The company's business is influenced by seasonal weather conditions.
II-78
II-79
II-80A
II-80B
II-80C
II-81
II-82A
II-82B
II-82C
II-83
II-84A
II-84B
II-84C
II-85
II-86A
II-86B
II-86C
II-87
II-88A
II-88B
II-88C
II-89
II-90A
II-90B
II-90C
ALABAMA POWER COMPANY
OUTSTANDING SECURITIES AT DECEMBER 31, 1995
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
1991 100,000 9-1/4% 98,748 5/1/21
1991 150,000 8-3/4% 148,500 12/1/21
1992 200,000 8-1/2% 198,000 5/1/22
1992 100,000 8.30% 99,608 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
1994 150,000 9% 150,000 12/1/24
============= ==============
$ 2,005,000 $ 1,999,856
============= ==============
Pollution Control Bonds
Amount Interest Amount
Series Issued Rate Outstanding Maturity
--------------------------------------------------------------------------------
(Thousands) (Thousands)
1978 $ 5,600 7-1/4% $ 1,000 5/1/03
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
1994 24,400 5-1/2% 24,400 1/1/24
1994 53,700 Variable 53,700 6/1/15
1994 101,650 6-1/2% 101,650 9/1/23
1995 50,000 Variable 50,000 5/1/22
1995 81,500 Variable 81,500 10/1/22
============= ==============
$ 480,740 $ 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-91
ALABAMA POWER COMPANY
SECURITIES RETIRED DURING 1995
Pollution Control Bonds
Principal Interest
Series Amount Rate
--------------------------------------------------------------------------------
(Thousands)
1985 $ 50,000 9-3/8%
1985 81,500 9-1/4%
===========
$ 131,500
===========
II-92
GEORGIA POWER COMPANY
FINANCIAL SECTION
II-93
MANAGEMENT'S REPORT
Georgia Power Company 1995 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 six
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, in all
material respects, the financial position, results of operations and cash flows
of Georgia Power Company in conformity with generally accepted accounting
principles.
/s/ H. Allen Franklin
H. Allen Franklin
President and Chief
Executive Officer
/s/ Warren Y. Jobe
Warren Y. Jobe
Executive Vice President, Treasurer and
Chief Financial Officer
February 21, 1996
II-94
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 and wholly owned subsidiary of
The Southern Company) as of December 31, 1995 and 1994, 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, 1995. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements (pages II-104 through II-125)
referred to above present fairly, in all material respects, the financial
position of Georgia Power Company as of December 31, 1995 and 1994, and the
results of its operations and its cash flows for the periods stated, in
conformity with generally accepted accounting principles.
/s/ Arthur Andersen LLP
Atlanta, Georgia
February 21, 1996
II-95
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Georgia Power Company 1995 Annual Report
RESULTS OF OPERATIONS
Earnings
Georgia Power Company's 1995 earnings totaled $609 million, representing an $83
million (15.9 percent) increase over 1994. Earnings for 1994 were reduced by a
$55 million after-tax charge related to work force reduction programs. Excluding
the charge related to the 1994 work force reduction programs, earnings for 1995
increased 4.8 percent over 1994 primarily due to higher retail energy sales and
lower interest charges, partially offset by higher operating expenses. Earnings
for 1994 declined from the prior year not only because of the work force
reduction charge but also because of lower retail energy sales due to mild
weather. The summer of 1993 was exceptionally hot in comparison.
Revenues
The following table summarizes the factors impacting operating revenues for the
1993-1995 period:
Increase (Decrease)
From Prior Year
-----------------------------------
1995 1994 1993
-----------------------------------
Retail - (in millions)
Sales growth $110 $ 67 $ 45
Weather 69 (128) 126
Fuel cost recovery 66 (35) 76
Demand-side programs 36 (12) 15
-----------------------------------------------------------------
Total retail 281 (108) 262
------------------------------------------------------------------
Sales for resale -
Non-affiliates (61) (183) (106)
Affiliates 16 (1) (6)
------------------------------------------------------------------
Total sales for resale (45) (184) (112)
------------------------------------------------------------------
Other operating revenues 7 3 4
------------------------------------------------------------------
Total operating revenues $243 ($289) $154
------------------------------------------------------------------
Percent change 5.8% (6.5)% 3.6%
------------------------------------------------------------------
Retail revenues of $4.0 billion in 1995 increased $281 million (7.6 percent)
over the prior year, compared with a decrease of $108 million (2.8 percent) in
1994. Sales growth, reflecting continued expansion of Georgia's economy, and the
hot summer of 1995, compared to the milder-than-normal weather during the summer
of 1994, were the primary reasons for the increase in retail revenues. Retail
revenues were down in 1994 from the prior year primarily due to hot summer
weather in 1993.
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 option programs generally represent the direct
recovery of program costs. See Note 3 to the financial statements under
"Demand-Side Conservation Programs" for further information on these programs.
Revenues from sales to non-affiliated utilities decreased in both 1995 and
1994. 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:
1995 1994 1993
-------------------------------
(in millions)
Capacity $53 $ 84 $152
Energy 45 82 113
--------------------------------------------------------------
Total $98 $166 $265
==============================================================
Contractual unit power sales to Florida utilities for 1995 and 1994 are down
primarily due to scheduled reductions that corresponded with the sales to these
utilities of portions of Plant Scherer Unit 4 in June 1995 and June 1994. The
amount of capacity under these contracts declined by 155 megawatts and 427
megawatts in 1995 and 1994, respectively. In 1996, the contracted capacity will
decline another 75 megawatts.
Sales to municipalities and cooperatives in Georgia increased in 1995 due to
higher summer demand resulting from the hot weather; however, such sales
decreased in 1994 as these customers retained more of their own generation at
jointly owned facilities, and as a result of a new agreement with territorial
wholesale customers.
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.
II-96
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1995 Annual Report
Kilowatt-hour (KWH) sales for 1995 and the percent change by year were as
follows:
Percent Change
----------------------------
1995
KWH 1995 1994 1993
----------------------------------------
(in billions)
Residential 17.3 10.4% (5.8)% 11.5%
Commercial 19.8 5.9 2.5 5.9
Industrial 25.3 3.9 3.0 2.9
Other 0.5 2.0 5.0 5.7
-------
Total retail 62.9 6.2 0.4 6.1
-------
Sales for resale -
Non-affiliates 6.6 (17.3) (44.3) (9.8)
Affiliates 2.8 (10.4) 0.9 (8.8)
-------
Total sales for resale 9.4 (15.4) (36.4) (9.7)
-------
Total sales 72.3 2.8 (8.0) 2.1
=======
-----------------------------------------------------------------
Residential, commercial and industrial energy sales growth in 1995 reflected
continued expansion of Georgia's economy, hot summer weather, and an increase in
customers served. The 1994 sales decline in the residential class was primarily
the result of milder-than-normal summer weather in 1994. However in 1994,
industrial and commercial sales were positively impacted by continued
improvement in economic conditions. Assuming normal weather, sales to retail
customers are projected to grow approximately 2 percent annually on average
during 1996 through 1998.
Expenses
Fuel costs constitute 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. The amount and sources of generation and the average cost of
fuel per net kilowatt-hour generated were as follows:
1995 1994 1993
---------------------------
Total generation
(billions of kilowatt-hours) 64 62 64
Sources of generation
(percent) --
Coal 73.7 74.8 76.9
Nuclear 22.6 21.9 20.0
Hydro 3.0 3.1 2.8
Oil and gas 0.7 0.2 0.3
Average cost of fuel per net
kilowatt-hour generated
(cents) --
Coal 1.67 1.67 1.75
Nuclear 0.60 0.63 0.58
Oil and gas * * *
Total 1.44 1.44 1.52
---------------------------------------------------------------
* Not meaningful because of minimal generation from
fuel source.
Fuel expense increased 3.5 percent in 1995 because of higher generation
which stemmed from greater demand. Fuel expense decreased 8.5 percent in 1994
due to lower fuel costs, lower generation, and the displacement of coal-fired
generation with lower cost nuclear generation.
Purchased power expense has decreased significantly since 1993, reflecting
declining contractual capacity purchases from the co-owners of Plant Vogtle.
Purchased power expense decreased $36 million in 1995 and $156 million in 1994.
The declines in 1995 and 1994 also resulted from decreased purchases from
affiliated companies, and in 1994 from decreased energy purchases from
territorial wholesale customers. The declines in Plant Vogtle contractual
capacity purchases did not have a significant impact on earnings in 1995 and
1994 since these costs are being levelized over six years under the terms of the
1991 Georgia Public Service Commission
II-97
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1995 Annual Report
(GPSC) retail rate order. The levelization is reflected in the amortization of
deferred Plant Vogtle costs in the Statements of Income. See Note 3 to the
financial statements under "Plant Vogtle Phase-In Plans" for additional
information.
The Company has incurred expenses for separation benefits associated with
its work force reduction programs. These expenses were $11 million in 1995 and
$82 million in 1994.
Other operation and maintenance (O&M) expenses increased 12.2 percent in
1995 primarily as a result of the recognition of costs associated with
demand-side option programs and increased maintenance expenses. The demand-side
option program costs were offset in part by increases in retail revenues. During
1995, the Company expensed an additional $58 million of demand-side option
program and other related costs, as compared to 1994, of which approximately $29
million was not collected through rate riders. See Note 3 to the financial
statements under "Demand-Side Conservation Programs" for additional information
on the recovery of these program costs. Other O&M expenses decreased 4.5 percent
in 1994 primarily due to environmental remediation costs at various sites of $32
million in 1993 compared to $8 million in 1994; recognition in 1993 of the
one-time cost of an automotive fleet reduction program; and lower maintenance
and pension costs during 1994.
Depreciation and amortization increased $43 million in 1995 primarily due to
additional plant investment, accelerated amortization of software costs, and an
increase in nuclear decommissioning expenses.
Taxes other than income taxes increased 5.2 percent in 1995 and 1.0 percent
in 1994, reflecting primarily higher ad valorem taxes and in 1995, higher
franchise taxes paid to municipalities as a result of increased sales.
Income tax expense fluctuates directly with earnings.
Other income (expense), net decreased in 1995 primarily due to an increase
in charitable contributions.
Interest expense decreased $51 million (14.6 percent) and $61 million (14.7
percent) in 1995 and 1994, respectively, due primarily to refinancing of
long-term debt. The Company refinanced $505 million and $510 million of
securities in 1995 and 1994, respectively. The Company also retired $264 million
of long-term debt with the proceeds from the 1995 and 1994 Plant Scherer Unit 4
sales. Other interest charges in 1993 include interest related to the settlement
of an Internal Revenue Service (IRS) audit.
The settlement had no 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 including energy sales and regulatory matters.
Beginning January 1, 1996, the Company will operate under a three-year
retail rate plan. The plan, which was approved by the GPSC on February 16, 1996,
concludes a GPSC review of the Company's earnings and addresses an alternative
rate plan proposed by the Company. Under the plan, the Company's earnings will
be evaluated against a retail return on common equity range of 10 percent to
12.5 percent. Earnings in excess of 12.5 percent will be used to accelerate the
amortization of regulatory assets or depreciation of electric plant. At its
II-98
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1995 Annual Report
option, the Company may also recognize accelerated amortization or depreciation
of assets within the allowed return on common equity range. The Company is
required to absorb cost increases of approximately $29 million annually during
the plan's three-year operation, including $14 million annually of accelerated
depreciation of electric plant. During the plan's operation, the Company will
not file for a general base rate increase unless its projected retail return on
common equity falls below 10 percent. Under the approved plan, on July 1, 1998
the Company will make a general rate case filing in response to which the GPSC
would be expected either to continue the rate plan or adopt a different one.
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 1996 through 1998.
The addition of four combustion turbine generating units and the Rocky
Mountain pumped storage hydroelectric plant in 1995 and the scheduled addition
of one jointly owned combustion turbine unit in 1996, will increase related O&M
and depreciation expenses. In addition, the Company has entered into a four-year
purchase power agreement to meet peaking needs whereby the Company will purchase
400 megawatts of capacity beginning in 1996 and declining to 200 megawatts of
capacity in 1998. Capacity payments are projected to be $6 million in 1996 and
1997 and $3 million in 1998 and 1999. The Company has also entered into a
30-year purchase power agreement whereby the Company will buy electricity during
peak periods from a planned 300 megawatt cogeneration facility starting in June
1998. Capacity and fixed O&M payments are projected to be $13 million in 1998.
Work force reduction programs implemented in 1994 and 1995 will assist in
efforts to control growth in future operating expenses.
As discussed in Note 3 to the financial statements, regulatory uncertainties
exist related to the Rocky Mountain pumped storage hydroelectric plant. In the
event the GPSC does not allow full recovery of the plant's costs, then the
portion not allowed may have to be written off. The Company's net investment in
the plant is approximately $190 million.
See Note 3 to the financial statements for information regarding proceedings
with respect to the Company's recovery of demand-side conservation program
costs.
During 1995, the Company sold its remaining interest in Unit 4 of Plant
Scherer to two Florida utilities. This transaction coincided with scheduled
reductions in capacity revenues from Florida utilities under contractual unit
power sales contracts of approximately $22 million in 1995 and an additional $7
million in 1996. See Notes 6 and 7 to the financial statements for additional
information.
During 1994 and 1995, Oglethorpe Power Corporation (OPC) gave the Company
notice of its intent to decrease its purchases of capacity under a power supply
agreement by 250 megawatts in September 1996 and an additional 250 megawatts in
September 1997. As a result, the Company's capacity revenues from OPC will
decline approximately $8 million in 1996, an additional $25 million in 1997, and
an additional $18 million in 1998.
OPC and the Municipal Electric Authority of Georgia (MEAG) have filed joint
complaints in two separate venues seeking to recover from the Company
approximately $16.5 million in alleged overcharges, plus approximately $6.3
million in interest. See Note 3 to the financial statements under "Wholesale
Litigation" for further discussion of this matter.
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.
Compliance costs related to the Clean Air Act Amendments of 1990 (Clean Air
Act) could affect earnings if such costs are not fully recovered. The Clean Air
II-99
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1995 Annual Report
Act and other environmental issues are discussed later under "Environmental
Issues."
The Energy Policy Act of 1992 (Energy Act) is beginning to have a dramatic
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 posturing the business to meet the challenge of this
major change in the traditional practice 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. This enhances 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.
Also, electricity sales for resale rates are being driven down by wholesale
transmission access and numerous potential new energy suppliers, including power
marketers and brokers. The Company is aggressively working to maintain and
expand its share of wholesale sales in the Southeastern power markets. Although
the Energy Act does not require transmission access to retail customers, retail
wheeling initiatives are rapidly evolving and becoming very prominent issues in
several states. New federal legislation is being discussed and legislation
allowing customer choice has been introduced in Georgia. In order to address
these initiatives, numerous questions must be resolved with the most complex
ones relating to transmission pricing and recovery of stranded investments. As
the initiatives become a reality, the structure of the utility industry could
radically change. Therefore, unless the Company remains a low-cost producer and
provides quality service, the Company's retail energy sales growth could be
limited, and this could significantly erode earnings. Conversely, being the
low-cost producer could provide significant opportunities to increase market
share and profitability.
The Company continues to compete with other electric suppliers within the
state. In Georgia, most new retail customers with at least 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 Company is subject to the provisions of Financial Accounting Standards
Board (FASB) Statement No. 71, Accounting for the Effects of Certain Types of
Regulation. In the event that a portion of the Company's operations is no longer
subject to these provisions, the Company would be required to write off related
regulatory assets and liabilities, and determine if any other assets have been
impaired. See Note 1 to the financial statements under "Regulatory Assets and
Liabilities" for additional information.
The staff of the Securities and Exchange Commission has questioned certain
of the current accounting practices of the electric utility industry --
including the Company -- regarding the recognition, measurement, and
classification of decommissioning costs for nuclear generating facilities in the
financial statements. In response to these questions, the FASB has decided to
review the accounting for liabilities related to closure and removal of
long-lived assets, including nuclear decommissioning. If the FASB issues new
accounting rules, the estimated costs of closing and removing the Company's
nuclear and other facilities may be required to be recorded as liabilities in
the Balance Sheets. Also, the annual provisions for such costs could increase.
Because of the Company's current ability to recover closure and removal costs
through rates, these changes would not have a significant adverse effect on
results of operations. See Note 1 to the financial statements under
"Depreciation and Nuclear Decommissioning" for additional information.
New Accounting Standards
The FASB has issued Statement No. 121, Accounting for the Impairment of
Long-Lived Assets and Long-Lived Assets to Be Disposed Of. This statement
requires that long-lived assets be reviewed for impairment whenever events or
changes in circumstances indicate that the carrying amount of an asset may not
be recoverable. This statement also imposes stricter criteria for regulatory
assets by requiring that such assets be probable of future recovery at each
balance sheet date. The Company adopted this standard January 1, 1996 with no
material effect on the financial statements. However, this conclusion may change
in the future as competitive factors influence wholesale and retail pricing in
this industry.
II-100
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1995 Annual Report
FINANCIAL CONDITION
Overview
The principal changes in the Company's financial condition in 1995 were gross
utility plant additions of $480 million, which included the commercial operation
of four combustion turbine units (cumulatively, 320 megawatts of capacity) and
all three units of the Rocky Mountain pumped storage hydroelectric plant (the
Company's ownership interest is approximately 70 megawatts of capacity per
unit). In addition, the cost of capital was lowered through the refinancing or
retirement of $1.0 billion of long-term debt.
The funds needed for gross property additions are currently provided from
operations. The Statements of Cash Flows provide additional details.
Financing Activities
In 1995, the Company continued to lower its financing costs by refinancing
higher-cost issues. New issues during 1993 through 1995 totaled $2.7 billion and
retirement or repayment of securities totaled $3.4 billion. The retirements
included the redemption of $131 million, $133 million, and $253 million in 1995,
1994, and 1993, respectively, of first mortgage bonds with the proceeds from the
Plant Scherer Unit 4 sales. Composite financing rates for long-term debt and
preferred stock for the years 1993 through 1995, as of year-end, were as
follows:
1995 1994 1993
---------------------------------
Composite interest rate
on long-term debt 6.57% 7.14% 7.86%
Composite preferred
stock dividend rate 6.73 7.11 6.76
----------------------------------------------------------------
The Company's current securities ratings are as follows:
Duff & Standard &
Phelps Moody's Poor's
------------------------------------
First Mortgage Bonds AA- A1 A+
Preferred Stock A a2 A
Unsecured Bonds A+ A2 A
Commercial Paper D1+ P1 A1
-----------------------------------------------------------------
Liquidity and Capital Requirements
Cash provided from operations increased by $281 million in 1995, primarily due
to increased revenues and a decrease in interest payments.
The Company estimates that construction expenditures for the years 1996
through 1998 will total $530 million, $537 million and $529 million,
respectively. Investments in transmission and distribution facilities,
enhancements to existing generating plants, and additions of a combustion
turbine generating plant and equipment to comply with the provisions of the
Clean Air Act are planned.
Cash requirements for sinking fund requirements, redemptions announced, and
maturities of long-term debt are expected to total $283 million during 1996
through 1998.
As a result of requirements by the Nuclear Regulatory Commission, the
Company has established external trust funds for the purpose of funding nuclear
decommissioning costs. For 1996 through 1998, the amount to be funded totals $24
million annually. For additional information concerning nuclear decommissioning
costs, see Note 1 to the financial statements under "Depreciation and Nuclear
Decommissioning."
As a result of the Energy Policy Act of 1992, the Company is required to pay
a special assessment over a 15-year period beginning in 1993 into a fund which
will be used by the U. S. Department of Energy for the decontamination and
decommissioning of its nuclear enrichment facilities. The Company estimates its
remaining liability to be approximately $31 million as of December 31, 1995. See
Note 1 to the financial statements under "Revenues and Fuel Costs" for
additional information.
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 $975 million of unused credit
II-101
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1995 Annual Report
arrangements with banks at the beginning of 1996. See Note 9 to the financial
statements under "Bank Credit Arrangements" for additional information.
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 amended by Congress. Title IV of the
Clean Air Act -- the acid rain compliance provision of the law -- is having a
significant impact on the operating companies of The Southern Company, including
Georgia Power. Specific reductions in sulfur dioxide and nitrogen oxide
emissions from fossil-fired generating plants are required in two phases. Phase
I compliance began in 1995 and initially affected 28 generating units in the
Southern electric system. As a result of The Southern Company's compliance
strategy, an additional 22 generating units were brought into compliance with
Phase I requirements. Phase II compliance is required in 2000, and all
fossil-fired generating plants in the Southern electric system will be affected.
In 1995, the Environmental Protection Agency (EPA) began issuing 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 issuing 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 Southern Company's sulfur dioxide compliance strategy is
designed to use allowances as a compliance option.
The Southern Company achieved Phase I sulfur dioxide compliance at the
affected units by switching to low-sulfur coal, which has required some
equipment upgrades. This compliance strategy resulted in unused emission
allowances being banked for later use. Compliance with nitrogen oxide emission
limits was achieved by the installation of new control equipment at 22 of the
original 28 affected generating units. Construction expenditures for Georgia
Power's Phase I compliance totaled approximately $165 million through 1995.
For Phase II 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. During the period 1996 to 2000, current compliance strategy could
require total estimated Georgia Power construction expenditures of approximately
$45 million. However, the full impact of Phase II compliance cannot now be
determined with certainty, pending the continuing 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 1 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 Title IV of the Clean Air Act.
Compliance costs include construction expenditures, increased costs for
switching to low-sulfur coal, and costs related to emission allowances.
A significant portion of costs related to the acid rain provision of the
Clean Air Act is expected to be recovered through existing ratemaking
provisions. However, 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
-- affecting sources of nitrogen oxides and volatile organic compounds -- to
achieve attainment by 1999. As the required first step, the state 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
II-102
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1995 Annual Report
nitrogen oxide controls, above Title IV requirements, on some of the Company's
plants. The EPA along with 37 states is conducting studies to evaluate the
benefits of regional controls in meeting the ozone standards. Final attainment
rules, based on modeling studies, could require installation of additional
controls for nitrogen oxide emissions to meet the 1999 deadline or as part of
any regional controls if enacted. A decision on new requirements is expected in
1997. Compliance with any new rules could result in significant additional
costs. The actual 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 EPA is scheduled to submit a
report to Congress on the results of this study during 1996. The report will
include 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 is evaluating the need to revise the ambient air quality standards
for particulate matter 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 1996, the EPA may 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. These costs for the Company amounted to $8 million in 1995
and 1994, and $32 million in 1993. Additional sites may require environmental
remediation for which the Company may be liable for a portion of or all required
cleanup costs. See Note 3 to the financial statements under "Certain
Environmental Contingencies" for information regarding the Company's potentially
responsible party status at a site in Brunswick, Georgia and the status of sites
listed on the State of Georgia's hazardous site inventory.
Several major pieces of environmental legislation are being considered for
reauthorization or amendment by Congress. These include: the Clean Air Act; the
Clean Water Act; the Comprehensive Environmental Response, Compensation, and
Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances
Control Act; and the Endangered Species 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 additional 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 exists for liability as the result of
lawsuits alleging damages caused by electromagnetic fields.
II-103
II-104
II-105
II-106
II-107
II-108
II-109
NOTES TO FINANCIAL STATEMENTS
Georgia Power Company 1995 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), a
system service company, Southern Communications Services (Southern
Communications), Southern Electric International (Southern Electric), Southern
Nuclear Operating Company (Southern Nuclear), The Southern Development and
Investment Group (Southern Development), and other direct and indirect
subsidiaries. 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). SCS provides, at cost, specialized
services to The Southern Company and subsidiary companies. Southern
Communications provides digital wireless communications services to the
operating companies and also markets these services to the public within the
Southeast. Southern Electric designs, builds, owns, and operates power
production and delivery 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. Southern Development develops new business
opportunities related to energy products and services.
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 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
(GAAP) and complies with the accounting policies and practices prescribed by the
respective regulatory commissions. The preparation of financial statements in
conformity with GAAP requires the use of estimates, and the actual results may
differ from these estimates.
Certain prior years' data presented in the financial statements have been
reclassified to conform with current year presentation.
Regulatory Assets and Liabilities
The Company is subject to the provisions of Financial Accounting Standards Board
(FASB) Statement No. 71, Accounting for the Effects of Certain Types of
Regulation. Regulatory assets represent probable future revenues to the Company
associated with certain costs that are expected to be recovered from customers
through the ratemaking process. Regulatory liabilities represent probable future
reductions in revenues associated with amounts that are to be credited to
customers through the ratemaking process. Regulatory assets and (liabilities)
reflected in the Company's Balance Sheets at December 31 relate to the
following:
1995 1994
--------------------
(in millions)
Deferred income taxes $ 872 $ 920
Deferred income tax credits (410) (433)
Deferred Plant Vogtle costs 308 432
Premium on reacquired debt 174 165
Demand-side program costs 79 97
Corporate building lease 49 48
Postretirement benefits 53 41
Vacation pay 36 41
Inventory conversions (31) (39)
Department of Energy assessments 33 36
Other, net 36 52
==============================================================
Total $1,199 $1,360
==============================================================
In the event that a portion of the Company's operations is no longer subject
to the provisions of Statement No. 71, the Company would be required to write
off related regulatory assets and liabilities. In addition, the Company would be
required to determine any impairment to other assets, including plant, and write
down the assets, if impaired, to their fair value.
II-110
NOTES (continued)
Georgia Power Company 1995 Annual Report
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 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.
The Company has a diversified base of customers. No single customer or
industry comprises 10 percent or more of revenues. In 1995, uncollectible
accounts continued to average less than 1 percent of revenues.
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 $86
million in 1995, $87 million in 1994, and $75 million in 1993. 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 2003 at Plant
Hatch and into 2009 at Plant Vogtle.
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 assessment will be paid over a 15-year
period, which began in 1993. The law provides that utilities will recover these
payments in the same manner as any other fuel expense. The Company -- based on
its ownership interests -- estimates its remaining liability under this law at
December 31, 1995, to be approximately $31 million. This obligation is recorded
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
3.2 percent in 1995 and 3.1 percent in 1994 and 1993. See Note 3 under "Retail
Rate Plan" for additional information. 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 and removal of other facilities.
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. The
Company has established external trust funds to comply with the NRC's
regulations. Amounts previously recorded in internal reserves are being
transferred into the external trust funds over a set period of time as approved
by the GPSC. Earnings on the trust funds are considered in determining
decommissioning expense. 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 amounts prescribed by
the NRC.
The site study cost is the estimate to decommission the facility as of the
site study year, and ultimate cost is the estimate to decommission the facility
as of the retirement
II-111
NOTES (continued)
Georgia Power Company 1995 Annual Report
date. The estimated costs of decommissioning -- both site study costs and
ultimate costs at December 31, 1995 -- based on the Company's ownership
interests -- were as follows:
Plant Plant
Hatch Vogtle
--------------------
Site study basis (year) 1994 1994
Decommissioning periods:
Beginning year 2014 2027
Completion year 2027 2038
------------------------------------------------------------
(in millions)
Site study costs:
Radiated structures $294 $233
Non-radiated structures 41 52
============================================================
Total $335 $285
============================================================
(in millions)
Ultimate costs:
Radiated structures $781 $1,018
Non-radiated structures 111 230
------------------------------------------------------------
Total $892 $1,248
============================================================
(in millions)
Amount expensed in 1995 $11 $ 9
Accumulated provisions:
Balance in external trust funds $56 $36
Balance in internal reserves 30 13
============================================================
Total $86 $49
============================================================
Significant assumptions:
Inflation rate 4.4% 4.4%
Trust earnings rate 6.0 6.0
------------------------------------------------------------
Annual provisions for nuclear decommissioning are based on an annuity --
sinking fund -- method as approved by the GPSC. The decommissioning costs
included in cost of service are based on the higher of the costs to decommission
the radioactive portions of the plants based on 1994 site studies or the NRC
minimum funding requirements. The Company expects the GPSC to periodically
review and adjust, if necessary, the amounts collected in rates for the
anticipated cost of decommissioning.
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: changes in the assumed date of
decommissioning; changes in NRC requirements; changes in the assumptions used in
making estimates; changes in regulatory requirements; changes in technology; and
changes in costs of labor, materials, and equipment.
Income Taxes
The Company uses the liability method of accounting for deferred income taxes
and 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.
Plant Vogtle Phase-In Plans
In 1987 and 1989, the 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 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.
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. For the years 1995, 1994 and 1993, the average AFUDC rates
were 6.53 percent, 6.18 percent and 4.96 percent, respectively. The increase in
1994 is primarily the result of the higher short-term borrowing rates. AFUDC,
net of taxes, as a percentage of net income after dividends on preferred stock,
was less than 2.5 percent for 1995, 1994, and 1993.
II-112
NOTES (continued)
Georgia Power Company 1995 Annual Report
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 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, the Company's financial instruments for which the
carrying amounts did not approximate fair value at December 31 are as follows:
Carrying Fair
Amount Value
--------------------------
Long-term debt: (in millions)
At December 31, 1995 $3,378 $3,487
At December 31, 1994 3,838 3,697
Preferred Securities:
At December 31, 1995 100 114
---------------------------------------------------------------
The fair values for securities 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.
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 one of the following 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 trusts 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. Qualified trusts are funded to the extent deductible
under federal income tax regulations and to the extent required by the GPSC and
the FERC. During 1995 and 1994, the Company funded $21 million and $22 million,
respectively, to the qualified trusts. Amounts funded are primarily invested in
debt and equity securities.
FASB Statement No. 106, Employers' Accounting for Postretirement Benefits
Other Than Pensions, 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 cost was expensed
in 1993, and the remaining additional costs were 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.
II-113
NOTES (continued)
Georgia Power Company 1995 Annual Report
Funded Status and Cost of Benefits
The following tables show actuarial results and assumptions for pension and
postretirement benefits as computed under the requirements of FASB Statement
Nos. 87 and 106, respectively. The funded status of the plans at December 31 was
as follows:
Pension
---------------------
1995 1994
---------------------
Actuarial present value of (in millions)
benefit obligations:
Vested benefits $ 830 $ 689
Non-vested benefits 43 32
---------------------------------------------------------------
Accumulated benefit obligation 873 721
Additional amounts related
to projected salary increases 290 294
---------------------------------------------------------------
Projected benefit obligation 1,163 1,015
Less:
Fair value of plan assets 1,688 1,419
Unrecognized net gain (465) (371)
Unrecognized prior service cost 26 28
Unrecognized transition asset (52) (58)
===============================================================
Prepaid asset recognized in
the Balance Sheets $ 34 $ 3
===============================================================
Postretirement
Benefits
---------------------
1995 1994
---------------------
(in millions)
Actuarial present value of benefit obligation:
Retirees and dependents $214 $203
Employees eligible to retire 16 7
Other employees 188 229
---------------------------------------------------------------
Accumulated benefit obligation 418 439
Less:
Fair value of plan assets 81 52
Unrecognized net loss (gain) 44 (1)
Unrecognized transition
obligation 186 301
===============================================================
Accrued liability recognized in the
Balance Sheets $107 $ 87
===============================================================
In 1995, the Company announced a cost sharing program for postretirement
benefits. The program establishes limits on amounts the Company will pay to
provide future postretirement benefits. This change reduced the 1995 accumulated
postretirement benefit obligation by approximately $97 million.
The weighted average rates used in actuarial calculations were:
1995 1994 1993
-------------------------------
Discount 7.3% 8.0% 7.5%
Annual salary increase 4.8 5.5 5.0
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 9.8 percent for 1995, decreasing gradually to 5.3 percent through the year
2005 and remaining at that level thereafter. An annual increase in the assumed
medical care cost trend rate of 1 percent would increase the accumulated benefit
obligation as of December 31, 1995, by $39 million and the aggregate of the
service and interest cost components of the net postretirement cost by $8
million.
The components of the plans' net costs are shown below:
Pension
-----------------------------
1995 1994 1993
-----------------------------
(in millions)
Benefits earned during the year $ 33 $ 34 $ 33
Interest cost on projected
benefit obligation 78 71 69
Actual (return) loss on plan assets (317) 35 (194)
Net amortization and deferral 185 (160) 84
================================================================
Net pension cost $ (21) $ (20) $ (8)
================================================================
Net pension costs were negative in 1995, 1994 and 1993. Of net pension
amounts recorded, $15 million in 1995 and 1994, and $6 million in 1993 were
recorded as a
II-114
NOTES (continued)
Georgia Power Company 1995 Annual Report
reduction to operating expense, and the remainder was recorded as a reduction
to construction and other accounts.
Postretirement Benefits
--------------------------
1995 1994 1993
--------------------------
(in millions)
Benefits earned during the year $13 $15 $14
Interest cost on accumulated
benefit obligation 34 33 29
Amortization of transition
obligation 16 15 15
Actual (return) loss on plan
assets (8) 1 (4)
Net amortization and deferral 4 (3) 2
==================================================================
Net postretirement cost $59 $61 $56
==================================================================
Of the above net postretirement benefit costs recorded, $33 million in 1995,
$28 million in 1994, and $21 million in 1993 were charged to operating expenses.
In addition, $11 million in 1995, $18 million in 1994, and $21 million in 1993
were deferred, and the remainder was charged to construction and other accounts.
Work Force Reduction Programs
The Company has incurred additional costs for work force reduction programs. The
costs related to these programs were $11 million and $82 million for the years
1995 and 1994, respectively. Additionally, in 1994, the Company recognized $8
million for its share of costs associated with SCS's work force reduction
program.
3. REGULATORY AND LITIGATION MATTERS
Retail Rate Plan
On February 16, 1996, the GPSC approved a rate plan recommended by the
Commission staff which concludes the GPSC's review of the Company's earnings
initiated in early 1995 and addresses the Company's proposed alternative retail
rate plan. Under the three-year plan effective January 1, 1996, the Company's
earnings will be evaluated against a retail return on common equity range of 10
percent to 12.5 percent. Earnings in excess of 12.5 percent will be used to
accelerate the amortization of regulatory assets or depreciation of electric
plant. At its option, the Company may also recognize accelerated amortization or
depreciation of assets within the allowed return on common equity range. The
Company is required to absorb cost increases of approximately $29 million
annually during the plan's three-year operation, including $14 million annually
of accelerated depreciation of electric plant. During the plan's operation, the
Company will not file for a general base rate increase unless its projected
retail return on common equity falls below 10 percent. Under the approved plan,
on July 1, 1998 the Company will make a general rate case filing in response to
which the GPSC would be expected either to continue the rate plan or adopt a
different one.
Rocky Mountain Plant Status
In its 1985 financing order, the GPSC concluded that completion of the Rocky
Mountain pumped storage hydroelectric plant 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 plant. In
1988, the Company and OPC entered into a joint ownership agreement for OPC to
assume responsibility for the construction and operation of the plant, as
discussed in Note 6. However, full recovery of the Company's costs depends on
the GPSC's treatment of the plant's costs and disposition of the plant's
capacity output. In the event the GPSC does not allow full recovery of the
plant's costs, then the portion not allowed may have to be written off. AFUDC
accrued on the Rocky Mountain plant was not credited to income or included in
the plant's cost since December 1985. In 1995, the plant went into commercial
operation. At December 31, 1995, the Company's net investment in the plant was
approximately $190 million, and the Company's ownership was 25.4 percent.
The final outcome of this matter cannot now be determined. Accordingly, no
provision for any write-down of the investment in the plant has been made.
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 suspended collection of the demand-side conservation
II-115
NOTES (continued)
Georgia Power Company 1995 Annual Report
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 Superior Court's decision is reversed or until the
next general rate case proceedings.
After the Georgia Court of Appeals upheld the legality of the rate riders,
the Company resumed collection under the rate riders in December 1994. In August
1995, the GPSC ordered the Company to discontinue its current demand-side
conservation programs by the end of 1995. The rate riders will remain in effect
until costs deferred are collected.
Under the Retail Rate Plan approved February 16, 1996, the Company will
recognize approximately $29 million of deferred program costs over a three-year
period which will not be recovered through the riders.
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
change in the rate of return on common equity that could potentially require
refunds as a result of this proceeding would be substantially for the period
beginning in July 1991 and ending in October 1992.
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.
In August 1994, the FERC instituted another proceeding based on
substantially the same issues as in the 1991 proceeding. The second period under
review for possible refunds began in October 1994 and ended in December 1995. In
November 1995, a FERC administrative law judge issued an opinion that the FERC
staff failed to meet its burden of proof, and therefore no change in the equity
return was necessary. The FERC staff has filed exceptions to the administrative
law judge's opinion, and the matter remains pending before the FERC.
If the rates of return on common equity recommended by the FERC staff were
applied to all the schedules and contracts involved in both proceedings and
refunds were ordered, the amount of refunds could range up to approximately $49
million at December 31, 1995. However, management believes that rates are not
excessive, and that refunds are not justified.
Certain Environmental Contingencies
In January 1995, the Company and four other unrelated entities were notified by
the EPA that they have been designated as potentially responsible parties under
the Comprehensive Environmental Response, Compensation and Liability Act with
respect to a site in Brunswick, Georgia. As of December 31, 1995, the Company
has recognized $3.5 million in expenses associated with this site. While the
Company believes that the total amount of costs required for the clean up of
this site may be substantial, it is unable at this time to estimate either such
total or the portion for which the Company may ultimately be responsible.
The final outcome of this matter cannot now be determined. However, based on
the nature and extent of the Company's activities relating to the site,
management believes that the Company's portion of these costs should not be
material.
In compliance with the Georgia Hazardous Site Response Act of 1993, the State
of Georgia was required to compile an inventory of all known or suspected sites
where hazardous wastes, constituents or substances have been disposed of or
released in quantities deemed reportable by the State. In developing this list,
the State identified several hundred properties throughout the State, including
24 sites which may require environmental remediation by the Company. The
majority of these 24 sites are electrical power substations and power generation
facilities. The Company has recognized $10 million in expenses through December
31, 1995 for the anticipated clean-up cost for 18 sites that the Company plans
II-116
NOTES (continued)
Georgia Power Company 1995 Annual Report
to remediate. The Company will conduct studies at each of the remaining sites to
determine the extent of remediation and associated clean-up costs, if any, that
may be required. The Company has recognized $2.4 million in expenses for the
anticipated cost of completing such studies. Any cost of remediating the
remaining sites cannot presently be determined until such studies are completed
for each site and the State of Georgia determines whether remediation is
required. If all listed sites were required to be remediated, the Company could
incur expenses of up to approximately $15 million in additional clean-up costs
and construction expenditures of up to approximately $100 million to develop new
waste management facilities or install additional pollution control devices.
Wholesale Litigation
In July 1994, Oglethorpe Power Corporation (OPC) and the Municipal Electric
Authority of Georgia (MEAG) filed a joint complaint with the FERC seeking to
recover from the Company an aggregate of approximately $16.5 million in alleged
partial requirements rates overcharges, plus approximately $6.3 million in
interest. OPC and MEAG claimed that the Company improperly reflected in such
rates costs associated with capacity that had previously been sold to Gulf
States pursuant to a unit power sales contract or, alternatively, that they
should be allocated a portion of the proceeds received by the Company as a
result of a settlement with Gulf States of litigation arising out of such
contract. The Company's response sought dismissal of the complaint by the FERC.
Dismissal was ordered in November 1994. OPC and MEAG filed a request for
rehearing in December 1994, and the FERC denied such request in July 1995. In
September 1995, OPC appealed the FERC's decision on this issue to the Court of
Appeals for the District of Columbia Circuit.
In August 1994, OPC and MEAG also filed a complaint in the Superior Court of
Fulton County, Georgia, urging substantially the same claims and asking the
court to hear the matter in the event the FERC declines jurisdiction. Such court
proceeding was subsequently stayed pending resolution of the FERC filing.
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 amortized these costs (as
recovered through rates) as follows:
1995 1994 1993
-----------------------------
(in millions)
Deferred costs at beginning
of year $432 $507 $383
----------------------------------------------------------------
Deferred capacity buyback
expenses - 10 38
Amortization of previously
deferred costs (124) (85) (74)
----------------------------------------------------------------
Net amortization (124) (75) (36)
----------------------------------------------------------------
Effect of adoption of FASB
Statement No. 109 - - 160
================================================================
Deferred costs at end of year $308 $432 $507
================================================================
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 percent 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
II-117
NOTES (continued)
Georgia Power Company 1995 Annual Report
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. At December 31, 1995,
the remaining amount to be collected was $2.4 million.
4. COMMITMENTS
Construction Program
While the Company has no new baseload generating plants under construction, the
construction of one jointly owned combustion turbine peaking unit is planned to
be completed in 1996. In addition, significant construction of transmission and
distribution facilities, and projects to upgrade and extend the useful life of
generating plants will continue. The Company currently estimates property
additions to be approximately $530 million in 1996, $537 million in 1997, and
$529 million in 1998. These estimated additions include AFUDC of $12 million in
1996, $14 million in 1997, and $15 million in 1998. The estimates for property
additions for the three-year period include $67 million committed to meeting the
requirements of the Clean Air Act.
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.
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 fossil and nuclear fuel commitments at December 31,
1995 were as follows:
Minimum
Year Obligations
----------------------
(in millions)
1996 $ 831
1997 678
1998 534
1999 321
2000 231
2001 through 2010 1,624
===============================================================
Total minimum obligations $4,219
===============================================================
Additional commitments for coal and for nuclear fuel will be required in the
future to supply the Company's fuel needs.
Purchase Power Commitments
In connection with the joint ownership arrangement for Plant Vogtle, discussed
in Note 6, the Company has made commitments to purchase declining fractions of
OPC's and MEAG's capacity and energy from this plant. 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
$76 million, $129 million and $183 million in 1995, 1994, and 1993,
respectively. The current projected Plant Vogtle capacity payments for the next
five years are: $70 million in 1996, $59 million per year in 1997 through 1999,
and $60 million in 2000. 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.
II-118
NOTES (continued)
Georgia Power Company 1995 Annual Report
As discussed in Note 3, the Plant Vogtle declining capacity buyback expense
is being levelized over a six-year period which began in October 1991.
The Company and an affiliate, Alabama 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 1,020 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 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. The term of the contract extends automatically
for two-year periods, subject to either 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 Income, is as follows:
1995 1994 1993
---------------------------------
(in millions)
Energy $44 $43 $60
Capacity 29 33 30
==============================================================
Total $73 $76 $90
==============================================================
Kilowatt-hours 2,391 2,429 3,352
--------------------------------------------------------------
At December 31, 1995, the capitalization of SEGCO consisted of $54 million
of equity and $78 million of long-term debt on which the annual interest
requirement is $5 million.
The Company has entered into a 30-year purchase power agreement, scheduled to
begin in June 1998, for electricity during peaking periods from a planned 300
megawatt cogeneration facility. Payments are subject to reductions for failure
to meet minimum capacity output. Total estimated capacity and fixed operation
and maintenance (O&M) payments are as follows:
Fixed
Year Capacity O&M Total
-----------------------------------------
(in millions)
1998 $ 10 $ 3 $ 13
1999 11 4 15
2000 11 4 15
2001 and beyond 178 157 335
================================================================
Total $210 $168 $378
================================================================
Operating Leases
The Company has entered into coal rail car rental agreements with various terms
and expiration dates. These expenses totaled $12 million, $13 million, and $8
million for 1995, 1994, and 1993, respectively. At December 31, 1995, estimated
minimum rental commitments for noncancelable operating leases were as follows:
Year Amounts
-------------------
(in millions)
1996 $ 11
1997 10
1998 10
1999 10
2000 10
2001 and beyond 126
=========================================================
Total minimum payments $177
=========================================================
5. 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
II-119
NOTES (continued)
Georgia Power Company 1995 Annual Report
occurring at the Company's nuclear power plants. The act provides funds up to
$8.9 billion for 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. The 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, excluding any
applicable state premium taxes, -- based on its ownership and buyback interests
-- is $162 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 assessment in the event that losses exceed accumulated
reserve funds. The Company's maximum annual assessment is limited to $12 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 Insurance
Limited (NEIL), a mutual insurance company.
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 $2.8 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 the current policies for the
Company would be $24 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 $6 million.
All retrospective assessments, whether generated for liability, property or
replacement power, may be subject to applicable state premium taxes.
6. FACILITY SALES AND JOINT OWNERSHIP AGREEMENTS
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; 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 Company, an affiliate.
Additionally, in 1995 the Company completed the last 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 $808 million. FP&L now owns approximately 76.4 percent of the
unit, with JEA owning the remainder.
II-120
NOTES (continued)
Georgia Power Company 1995 Annual Report
The Scherer Unit 4 transactions were as follows:
Closing Date Percent After-Tax
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 16.55 133 11
June 1995 135 16.55 131 12
===============================================================
Total 818 100.00% $808 $55
===============================================================
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 3, the Company owns 25.4 percent of the Rocky Mountain
pumped storage hydroelectric plant, which began commercial operation in 1995.
OPC owns the remainder, and is the operator of the plant.
The Company owns six of eight 80 megawatt combustion turbine generating
units and 75 percent of the related common facilities at Plant McIntosh.
Savannah Electric and Power Company, an affiliate, owns the remainder and
operates the plant. Four of the Company's six units began commercial operation
during 1994, and the remaining two units began commercial operation in 1995.
In 1994, the Company and Florida Power Corporation (FPC) entered into a
joint ownership agreement regarding a 150 megawatt combustion turbine unit to be
constructed at Intercession City, Florida, near Orlando. The unit is scheduled
to begin commercial operation by the end of 1996, and will be constructed,
operated, and maintained by FPC. The Company will have a one-third interest in
the unit, with use of 100 percent of the unit's capacity from June through
September. FPC will have the capacity the remainder of the year. The Company's
investment in the project is expected to be approximately $14 million at
completion.
At December 31, 1995, the Company's percentage ownership and investment
(exclusive of nuclear fuel) in jointly owned facilities in commercial operation,
were as follows:
Total
Nameplate 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
Plant McIntosh
Common Facilities N/A 75.0
(combustion-turbine)
Rocky Mountain 848 25.4
(pumped storage)
-----------------------------------------------------------------
Accumulated
Facility (Type) Investment Depreciation
-----------------------------------------------------------------
(in millions)
Plant Vogtle (nuclear) $3,295* $730
Plant Hatch (nuclear) 842 394
Plant Wansley (coal) 297 132
Plant Scherer (coal)
Units 1 and 2 112 39
Unit 3 541 135
Plant McIntosh
Common Facilities
(combustion-turbine) 19 **
Rocky Mountain
(pumped storage) 200 10
----------------------------------------------------------------
* Investment net of write-offs.
** Less than $1 million.
II-121
NOTES (continued)
Georgia Power Company 1995 Annual Report
7. LONG-TERM POWER SALES AGREEMENTS
The Company and the operating subsidiaries of The Southern Company have
long-term contractual agreements for the sale of capacity and energy to
non-affiliated utilities located outside the system's service area. These
agreements consist of firm unit power sales pertaining to capacity from specific
generating units. The Company also had agreements for non-firm sales, which
expired in 1994, based on the capacity of the Southern system. Because energy is
generally sold at cost under these agreements, it is primarily the capacity
revenues that affect the Company's profitability.
The Company's capacity revenues have been as follows:
Year Unit Power Sales Non-firm Sales
-----------------------------------------------------------------
(in millions) (megawatts) (in millions) (megawatts)
1995 $ 53 248 $ - -
1994 75 403 9 101
1993 135 830 17 200
-----------------------------------------------------------------
Unit power from specific generating plants is being sold to FP&L, FPC, JEA,
and the City of Tallahassee, Florida. Under these agreements, the Company sold
approximately 248 megawatts of capacity in 1995 and is scheduled to sell
approximately 173 megawatts of capacity in 1996. Thereafter, these sales will
decline to an estimated 159 megawatts and remain at that level through 1999.
After 2000, capacity sales will decline to approximately 103 megawatts -- unless
reduced by FP&L, FPC, and JEA -- until the expiration of the contracts in 2010.
Long-term non-firm power of 200 megawatts was sold by the Southern
system in 1994 to FPC, of which the Company's share was 101 megawatts, under a
contract that expired at the end of 1994. Sales under these long-term non-firm
power sales agreements were made from available power pool energy, and the
revenues from the sales were shared by the operating affiliates.
8. INCOME TAXES
Effective January 1, 1993, the Company adopted FASB Statement No. 109,
Accounting for Income Taxes. The adoption resulted in the recording of
additional deferred income taxes and related regulatory assets and liabilities.
At December 31, 1995, the tax-related regulatory assets were $872 million and
the tax-related regulatory liabilities were $410 million. The assets are
attributable to tax benefits flowed through to customers in prior years and to
taxes applicable to capitalized AFUDC. The liabilities are attributable to
deferred taxes previously recognized at rates higher than current enacted tax
law and to unamortized investment tax credits.
Details of the federal and state income tax provisions are as follows:
1995 1994 1993
------------------------------
Total provision for income taxes: (in millions)
Federal:
Currently payable $349 $306 $223
Deferred -
Current year 84 86 181
Reversal of prior years (55) (57) (40)
Deferred investment tax
credits 1 (1) (18)
-----------------------------------------------------------------
379 334 346
-----------------------------------------------------------------
State:
Currently payable 60 52 41
Deferred -
Current year 15 15 31
Reversal of prior years (8) (10) (3)
-----------------------------------------------------------------
67 57 69
-----------------------------------------------------------------
Total 446 391 415
------------------------------------------------------------------
Less:
Income taxes charged
(credited) to other income (3) (8) (37)
=================================================================
Federal and state income
taxes charged to operations $449 $399 $452
=================================================================
II-122
NOTES (continued)
Georgia Power Company 1995 Annual Report
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:
1995 1994
--------------------
(in millions)
Deferred tax liabilities:
Accelerated depreciation $1,630 $1,541
Property basis differences 1,074 1,085
Deferred Plant Vogtle costs 100 141
Premium on reacquired debt 70 68
Deferred regulatory costs 38 48
Fuel clause underrecovered - 9
Other 29 23
------------------------------------------------------------------
Total 2,941 2,915
------------------------------------------------------------------
Deferred tax assets:
Other property basis differences 239 250
Federal effect of state deferred taxes 97 94
Other deferred costs 83 79
Disallowed Plant Vogtle buybacks 25 26
Accrued interest 13 10
Fuel clause overrecovered 6 -
Other 18 13
------------------------------------------------------------------
Total 481 472
------------------------------------------------------------------
Net deferred tax liabilities 2,460 2,443
Portion included in current assets 51 35
==================================================================
Accumulated deferred income taxes
in the Balance Sheets $2,511 $2,478
==================================================================
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 $22 million in 1995, $25 million in 1994, and $19 million in 1993.
At December 31, 1995, all investment tax credits available to reduce federal
income taxes payable had been utilized.
A reconciliation of the federal statutory tax rate to the effective income
tax rate is as follows:
1995 1994 1993
-----------------------------
Federal statutory rate 35% 35% 35%
State income tax, net of
federal deduction 4 4 4
Non-deductible book
depreciation 2 3 3
Difference in prior years'
deferred and current tax rate (1) (1) (1)
Other - - (1)
================================================================
Effective income tax rate 40% 41% 40%
================================================================
The Southern Company and its subsidiaries file a consolidated federal income
tax return. Under a joint consolidated income tax agreement, each subsidiary's
current and deferred tax expense is computed on a stand-alone basis. Tax
benefits from losses of the parent company are allocated to each subsidiary
based on the ratio of taxable income to total consolidated taxable income.
9. 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, 1995, retained earnings of $897 million 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, 1995, the
ratio as defined was 50.2 percent.
II-123
NOTES (continued)
Georgia Power Company 1995 Annual Report
Preferred Securities
In December 1994, Georgia Power Capital, L.P., of which the Company is the sole
general partner, issued $100 million of 9 percent mandatory redeemable preferred
securities. The sole asset of Georgia Power Capital is $103 million aggregate
principal amount of Georgia Power's 9 percent Junior Subordinated Deferrable
Interest Debentures due December 19, 2024. The Company considers that the
mechanisms and obligations relating to the preferred securities, taken together,
constitute a full and unconditional guarantee by the Company of Georgia Power
Capital's payment obligations with respect to the preferred securities.
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
$1.5 billion 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 $146 million 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 1995 1994
--------------------------------------------------------------
(in millions)
2000 4.375% $ 50 $ -
2004-2005 5% to 5.70% 143 85
2006-2008 6.375% to 6.75% 12 12
2011-2015 10.125% to 10.6%
& Variable 10 515
2016-2019 6% to 9.375% 282 282
2021-2025 5.40% to 7.25%
& Variable 1,181 784
==============================================================
Total pollution control bonds $ 1,678 $1,678
==============================================================
Bank Credit Arrangements
At the beginning of 1996, the Company had unused credit arrangements with banks
totaling $975 million, of which $514.7 million expires at various times during
1996, $60.3 million expires at May 1, 1998, and $400 million expires at June 30,
1998.
The $400 million expiring June 30, 1998, is under revolving credit
arrangements with several banks providing the Company, Alabama Power Company,
and The Southern Company up to a total credit amount of $400 million. To provide
liquidity support for commercial paper programs, $165 million, $135 million, and
$100 million are currently dedicated to the Company, Alabama Power Company, and
The Southern Company, respectively. However, the allocations can be changed
among the borrowers by notifying the respective banks.
During the term of the agreements expiring in 1998, 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.
Of the Company's total $975 million in unused credit arrangements, a portion
of the lines are dedicated to provide liquidity support to variable rate
pollution control bonds. The credit lines dedicated as of December 31, 1995,
were $475 million. In connection with all other lines of credit, the Company has
the option of paying fees or maintaining compensating balances. These balances
are not legally restricted from withdrawal.
In addition, the Company borrows under uncommitted lines of credit with
banks and through a $225 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 1995.
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
II-124
NOTES (continued)
Georgia Power Company 1995 Annual Report
long-term debt. At December 31, 1995 and 1994, the Company had a capitalized
lease obligation for its corporate headquarters building of $87 million and $88
million, respectively, with an interest rate of 8.1 percent. The maturity of
this capital lease obligation through 2000 is approximately as follows: $336
thousand in 1996, $365 thousand in 1997, $395 thousand in 1998, $429 thousand in
1999, and $672 thousand in 2000.
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 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, 1995, and 1994, the interest and lease
amortization deferred on the Balance Sheets are $49 million and $48 million,
respectively.
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:
1995 1994
-----------------
(in millions)
First mortgage bond maturity $150 $130
Other long-term debt - 37
================================================================
Total $150 $167
================================================================
The Company's first mortgage bond indenture includes an improvement fund
requirement that 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 June 1 of each year by depositing cash, reacquiring bonds, or by
pledging additional property equal to 1 2/3 times the requirement. The Company
currently plans to satisfy its 1996 improvement fund requirement by depositing
cash with the trustee or by pledging additional property.
Redemption of Securities
The Company plans to continue a program of redeeming or replacing debt and
preferred stock in cases where opportunities exist to reduce financing costs.
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 through 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.
10. QUARTERLY FINANCIAL DATA (UNAUDITED)
Summarized quarterly financial information for 1995 and 1994 is as follows:
Net Income
After
Dividends on
Operating Operating Preferred
Quarter Ended Revenues Income Stock
-------------------------------------------------------------------
(in millions)
March 1995 $ 974 $207 $ 116
June 1995 1,075 230 149
September 1995 1,374 337 245
December 1995 982 177 99
March 1994 $ 992 $157 $ 58
June 1994 1,030 227 140
September 1994 1,213 331 233
December 1994 927 179 95
-------------------------------------------------------------------
Earnings in 1994 declined by $55 million as a result of work force reduction
programs recorded primarily in the first quarter.
The Company's business is influenced by seasonal weather conditions.
II-125
II-126
II-127A
II-127B
II-127C
II-128
II-129A
II-129B
II-129C
II-130
II-131A
II-131B
II-131C
II-132
II-133A
II-133B
II-133C
II-134
II-135A
II-135B
II-135C
II-136
II-137A
II-137B
II-137C
GEORGIA POWER COMPANY
OUTSTANDING SECURITIES AT DECEMBER 31, 1995
First Mortgage Bonds
Amount Interest Amount
Series Issued Rate Outstanding Maturity
--------------------------------------------------------------------------------
(Thousands) (Thousands)
1993 $ 150,000 4-3/4% $ 150,000 3/1/96
1993 100,000 5-1/2% 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 6-5/8% 200,000 4/1/03
1993 75,000 6.35% 75,000 8/1/03
1993 50,000 6-7/8% 50,000 4/1/08
1992 100,000 8-5/8% 60,368 6/1/22
1993 160,000 7.95% 160,000 2/1/23
1993 100,000 7-5/8% 100,000 3/1/23
1993 75,000 7-3/4% 75,000 4/1/23
1993 125,000 7.55% 125,000 8/1/23
1995 75,000 7.70% 75,000 5/1/25
============= ==============
$ 1,755,000 $ 1,715,368
============= ==============
Pollution Control Bonds
Amount Interest Amount
Series Issued Rate Outstanding Maturity
--------------------------------------------------------------------------------
(Thousands) (Thousands)
1995 $ 50,000 4-3/8% $ 50,000 11/1/00
1992 38,800 5.70% 38,800 9/1/04
1993 46,790 5-3/8% 46,790 3/1/05
1995 57,000 5% 57,000 9/1/05
1976 40,800 6-3/4% 1,920 11/1/06
1977 24,100 6.40% 1,940 6/1/07
1978 21,600 6-3/8% 8,060 4/1/08
1991 10,450 Variable 10,450 7/1/11
1986 56,400 8% 56,400 10/1/16
1987 90,000 8-3/8% 90,000 7/1/17
1987 50,000 9-3/8% 50,000 12/1/17
1993 26,700 6% 26,700 3/1/18
1989 50,000 6.35% 50,000 5/1/19
1991 8,500 6.25% 8,500 7/1/19
1991 51,345 7.25% 51,345 7/1/21
1991 10,125 6.25% 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 5-3/4% 11,935 9/1/23
1993 60,000 5-3/4% 60,000 9/1/23
1994 28,065 5.40% 28,065 1/1/24
1994 175,000 Variable 175,000 7/1/24
1994 125,000 6.60% 125,000 7/1/24
1994 60,000 6-3/8% 60,000 8/1/24
1994 43,420 6-3/4% 43,420 10/1/24
1994 20,000 Variable 20,000 10/1/24
1994 20,000 Variable 20,000 10/1/24
1994 38,725 6-5/8% 38,725 10/1/24
1994 10,000 5.90% 10,000 12/1/24
1994 7,000 5.90% 7,000 12/1/24
1995 73,535 6.10% 73,535 4/1/25
1995 75,000 Variable 75,000 4/1/25
1995 45,000 Variable 45,000 7/1/25
1995 40,000 Variable 40,000 7/1/25
1995 71,580 6% 71,580 7/1/25
1995 35,585 Variable 35,585 9/1/25
1995 30,000 Variable 30,000 9/1/25
1995 27,000 Variable 27,000 9/1/25
============= ==============
$ 1,752,610 $ 1,678,030
============= ==============
II-138
GEORGIA POWER COMPANY
OUTSTANDING SECURITIES AT DECEMBER 31, 1995 (Continued)
Subsidiary Obligated Mandatorily Redeemable Preferred Securities(1)
Preferred Securities Interest Amount
Series Outstanding Rate Outstanding
--------------------------------------------------------------------------------
(Thousands)
1994 4,000,000 9% $ 100,000
Preferred Stock
Shares Dividend Amount
Series Outstanding Rate Outstanding
--------------------------------------------------------------------------------
(Thousands)
(2) 14,090 $5.00 $ 1,409
1953 100,000 $4.92 10,000
1954 433,774 $4.60 43,378
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
------------- ------------
21,027,864 $ 692,787
============= ============
(1) Issued by Georgia Power Capital, L.P., and guaranteed to the extent Georgia
Power Capital has funds by GEORGIA.
(2) Issued in exchange for $5.00 preferred outstanding at the time of
company formation.
II-139
GEORGIA POWER COMPANY
SECURITIES RETIRED DURING 1995
First Mortgage Bonds
Principal Interest
Series Amount Rate
------------------------------------------------------------------------------
(Thousands)
1989 $ 36,157 9.23%
1992 130,000 5-1/8%
1992 100,000 8-3/4%
1992 39,632 8-5/8%
1992 100,000 Variable
1992 100,000 Variable
===========
$ 505,789
===========
Pollution Control Bonds
Principal Interest
Series Amount Rate
------------------------------------------------------------------------------
(Thousands)
1976 $ 20 6-3/4%
1977 20 6.40%
1978 70 6-3/8%
1985 148,535 10-1/8%
1985 156,580 10-1/2%
1985 100,000 10.60%
1985 99,585 10-1/2%
-----------
$ 504,810
===========
II-140
GULF POWER COMPANY
FINANCIAL SECTION
II-141
MANAGEMENT'S REPORT
Gulf Power Company 1995 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 five 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 Gulf Power Company in conformity with generally accepted
accounting principles.
/s/ Travis J. Bowden
Travis J. Bowden
President and Chief Executive Officer
/s/ Arlan E. Scarbrough
Arlan E. Scarbrough
Chief Financial Officer
February 21, 1996
II-142
REPORT OF INDEPENDENT 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, 1995 and 1994, 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, 1995. These financial statements
are the responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements (pages II-152 through II-169)
referred to above present fairly, in all material respects, the financial
position of Gulf Power Company as of December 31, 1995 and 1994, and the
results of its operations and its cash flows for the periods stated, in
conformity with generally accepted accounting principles.
/s/ Arthur Andersen LLP
Atlanta, Georgia
February 21, 1996
II-143
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Gulf Power Company 1995 Annual Report
RESULTS OF OPERATIONS
Earnings
Gulf Power Company's 1995 net income after dividends on preferred stock was
$57.2 million, an increase of $2 million over the prior year. This improvement
is primarily attributable to higher retail revenues due to exceptionally hot
summer weather and lower interest charges on long-term debt. This improvement
was partially offset by higher maintenance expenses and reduced capacity
revenues from non-affiliated utilities under long-term contracts. Costs related
to a work force reduction program implemented in the fourth quarter of 1995
decreased earnings by $4.3 million. These costs are expected to be recovered
through future savings over approximately two years.
In 1994, earnings were $55.2 million, representing an increase of $0.9
million compared to the prior year. Earnings in 1994 were significantly affected
by lower financing costs, an increase in customers, and milder than normal
temperatures. Also, earnings decreased approximately $3.0 million, reflecting
the first full year of lower industrial sales due to the Company's largest
industrial customer, Monsanto, installing its own cogeneration facility in
August, 1993.
The return on average common equity for 1995 was 13.27 percent, a slight
increase from the 13.15 percent return earned in 1994.
Revenues
Operating revenues increased in 1995 and decreased in 1994 as a result of the
following factors:
Increase (Decrease)
From Prior Year
-------------------------------------
1995 1994 1993
-------------------------------------
(in thousands)
Retail --
Change in base rates $ - $ - $ 1,571
Sales growth 3,647 7,126 7,671
Weather 9,749 (4,631) 4,049
Regulatory cost
recovery and other 22,502 8,938 (3,079)
-----------------------------------------------------------------
Total retail 35,898 11,433 10,212
-----------------------------------------------------------------
Sales for resale--
Non-affiliates (5,698) (6,098) 2,131
Affiliates 1,266 (5,813) (909)
-----------------------------------------------------------------
Total sales for resale (4,432) (11,911) 1,222
Other operating
revenues 8,798 (3,851) 806
-----------------------------------------------------------------
Total operating
revenues $40,264 $(4,329) $12,240
=================================================================
Percent change 7.0% (0.7)% 2.1%
-----------------------------------------------------------------
Retail revenues of $519 million in 1995 increased $35.9 million or 7.4
percent from last year, compared with an increase of 2.4 percent in 1994 and 2.2
percent in 1993. Residential and commercial revenues surged upward as a result
of hotter-than-normal summer weather in 1995, compared with the extremely mild
summer of 1994. The Company set an all-time peak demand for energy in 1995.
The increase in regulatory cost recovery and other retail revenue is
primarily attributable to the recovery of increased fuel costs. Regulatory cost
recovery and other includes recovery provisions for fuel expense and the energy
component of purchased power costs; energy conservation costs; purchased power
capacity costs; and environmental compliance costs. The recovery provisions
equal the related expenses and have no material effect on net income. See Notes
1 and 3 to the financial statements under "Revenues and Regulatory Cost Recovery
Clauses" and "Environmental Cost Recovery," respectively, for further
information.
II-144
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 1995 Annual Report
Sales for resale were $79 million in 1995, decreasing $4.4 million or 5.3
percent from 1994. 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 under these long-term contracts were as follows:
1995 1994 1993
----------------------------------------
(in thousands)
Capacity $25,870 $30,926 $33,805
Energy 18,598 18,456 21,202
============================================================
Total $44,468 $49,382 $55,007
============================================================
Capacity revenues decreased in 1995 and 1994, reflecting the scheduled
decline in capacity under long-term contracts.
Sales to affiliated companies 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.
The increase in other operating revenues for 1995 is primarily due to
increased amounts collected to recover newly-imposed county franchise fees.
These collections are also included in taxes other than income taxes and have no
impact on earnings. Other changes for 1995 and the change in 1994 are primarily
attributable to adjustments in the regulatory cost recovery clauses for
differences between recoverable costs and the amounts actually reflected in
revenues. See Notes 1 and 3 to the financial statements under "Revenues and
Regulatory Cost Recovery Clauses" and "Environmental Cost Recovery,"
respectively, for further discussion.
Kilowatt-hour sales for 1995 and percent changes in sales since 1993 are
reported below.
KWH Percent Change
------------ ---------------------------
1995 1995 1994 1993
------------ ---------------------------
(millions)
Residential 4,014 7.0% 1.1% 3.2%
Commercial 2,708 6.3 4.8 2.7
Industrial 1,795 (2.8) (9.0) (6.9)
Other 17 (0.1) - -
------------
Total retail 8,534 4.5 (0.3) 0.4
Sales for resale
Non-affiliates 1,397 (1.6) (2.8) 2.0
Affiliates 759 (13.1) (15.2) (14.8)
------------
Total 10,690 2.2 (2.1) (1.1)
==================================================================
Retail sales increased in 1995 due to hot summer weather, a 0.9 percent
increase in residential customers, and a 2.2 percent increase in commercial
customers. Industrial sales were lower due to the reclassification of a major
customer from the industrial to commercial class and temporary production delays
of other industrial customers. In 1994, retail sales decreased from the prior
year primarily due to mild summer weather and a decline in sales in the
industrial class, which reflected the loss of Monsanto and a lengthy shutdown of
another major customer.
In 1995, energy sales for resale to non-affiliates decreased 1.6 percent and
are predominantly related to unit power sales under long-term contracts to
Florida utilities. Energy sales to affiliated companies vary from year to year
as mentioned previously.
Expenses
Total operating expenses for 1995 increased $41.3 million or 8.5 percent from
1994. The increase is due to higher fuel and purchased power expenses, higher
maintenance expenses, and higher taxes other than income taxes, offset by lower
depreciation and amortization expenses. In 1994, total operating expenses
decreased $4.0 million or 0.8 percent from 1993 primarily due to decreased fuel
and purchased power expenses, offset by an increase in other operation expenses
and taxes.
Fuel and purchased power expenses for 1995 increased $30.1 million or 15.5
percent from 1994. The change reflects the increase in generation due to the
extreme weather conditions during the summer of 1995 and slightly higher fuel
II-145
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 1995 Annual Report
costs. In 1994, fuel and purchased power expenses declined $13.4 million or 6.5
percent from 1993 reflecting the decrease in generation due to the mild weather
and the lower cost of fuel.
The amount and sources of generation and the average cost of fuel per net
kilowatt-hour generated were as follows:
1995 1994 1993
-----------------------------
Total generation
(millions of kilowatt-hours) 9,828 9,559 9,558
Sources of generation
(percent)
Coal 99.5 99.8 99.4
Oil and gas .5 .2 .6
Average cost of fuel per net
kilowatt-hour generated
(cents)
Coal 2.08 2.00 2.03
Oil and gas 3.56 6.93 4.50
Total 2.09 2.01 2.05
------------------------------------------------------------------
In 1995, other operation expenses decreased $0.5 million or 0.4 percent from
the 1994 level. The decrease is primarily attributable to a $9.4 million
reduction in the amortization costs of coal buyouts and renegotiation of coal
supply contracts. This was offset by a $7 million accrual for benefits to be
provided by the Company under a work force reduction program implemented during
the fourth quarter of 1995. These costs are further discussed in Notes 2 and 5
to the financial statements under "Work Force Reduction Programs" and "Fuel
Commitments," respectively. In 1994, other operation expenses increased $4.7
million due to additional costs related to the buyouts and renegotiation of coal
supply contracts and the Company's pro rata share of affiliated companies' work
force reduction costs.
Maintenance expense in 1995 increased $5.2 million or 11.2 percent from the
prior year. This is attributable to higher power production maintenance related
to non-recurring items and higher distribution maintenance. In 1994, maintenance
expense remained relatively flat reflecting no major changes in the scheduling
of maintenance of production facilities.
Depreciation and amortization expenses decreased $1.5 million or 2.7 percent
from 1994. The change is attributable to property which was fully amortized by
December 1994. Refer to Note 1 to the financial statements under "Depreciation
and Amortization" for further discussion.
Federal and state income taxes increased $0.1 million or 0.3 percent in 1995
due to a slight increase in taxable income. Taxes other than income taxes
increased $7.9 million or 18.9 percent due to an increase in county franchise
fees as mentioned previously. In 1994, federal income taxes increased $1.2
million due to an increase in taxable income. Other taxes increased $1.5 million
or 3.7 percent due to higher property taxes, gross receipt taxes, and franchise
fee collections. Changes in gross receipt taxes and franchise fee collections,
which are collected from customers, have no impact on earnings.
In 1995, interest expense decreased $2.5 million or 7.8 percent below the
prior year. The decline is mainly attributable to lower interest on long-term
debt reflecting a lower average principal balance outstanding. The decrease in
interest on long-term debt was partially offset by an increase in interest on
notes payable as a result of a higher average amount of short-term notes
outstanding. Interest expense in 1994 decreased $3.8 million or 10.5 percent
under the prior year. The decrease was a result of 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.
II-146
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 1995 Annual Report
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 energy sales growth to a less regulated more
competitive environment.
A work force reduction program was implemented in the fourth quarter of 1995
that reduced earnings by $4.3 million. This action will assist in efforts to
control growth in future operating expenses.
The Florida Public Service Commission (FPSC) approved the Company's request
in December to increase the amount of its annual accrual to the accumulated
provision for property damage account from $1.2 million to $3.5 million due to
significant hurricane-related charges to the account during 1995. The approved
accrual increase is intended to restore the account balance to a reasonable
level within five years. Refer to Note 1 to the financial statements under
"Provision for Property Damage" for further discussion.
Future earnings in the near term will depend upon growth in energy sales,
which is subject to a number of factors. Traditionally, these factors have
included weather, competition, changes in contracts with neighboring utilities,
energy conservation practiced by customers, the elasticity of demand, and the
rate of economic growth in the Company's service area. However, the Energy
Policy Act of 1992 (Energy Act) is beginning to have a dramatic 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 positioning the business to meet the challenge of this
major change in the traditional practice 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. This may enhance the
incentive for IPPs to build cogeneration plants for industrial and commercial
customers and sell excess energy generation to utilities. Also, electricity
sales for resale rates are being driven down by wholesale transmission access
and numerous potential new energy suppliers, including power marketers and
brokers. The Company is aggressively working to maintain and expand its share of
wholesale sales in the Southeastern power markets.
Currently, Florida law does not permit retail wheeling. Although the Energy
Act does not require transmission access to retail customers, retail wheeling
initiatives are rapidly evolving and becoming very prominent issues in several
states. Potential new federal legislation is being discussed, and legislation
allowing customer choice has already been introduced in Florida. In order to
address these initiatives, numerous questions must be resolved, with the most
complex ones relating to transmission pricing and recovery of stranded
investments. As the initiatives become a reality, the structure of the utility
industry could radically change. Therefore, unless the Company remains a
low-cost producer and provides quality service, the Company's retail energy
sales growth could be limited and this could significantly erode earnings.
Conversely, being the low-cost producer could provide significant opportunities
to increase market share and profitability by seeking new markets that evolve
with the changing regulation.
The future effect of cogeneration and small-power production facilities
cannot be fully determined at this time. One effect of cogeneration which the
Company has experienced was the loss in 1993 of its largest industrial customer,
Monsanto, which is discussed in "Earnings." The Company's strategy is to
identify and pursue profitable cogeneration projects in Northwest Florida.
The FPSC has set conservation goals for the Company, beginning in 1995, which
require programs to reduce 154 megawatts of summer peak demand and 65,000 KWH of
sales by the year 2004. In 1995, the FPSC approved the Company's programs to
accomplish these goals. The Company can experience net growth as long as the
filed programs achieve the intended reductions in peak demand and KWH sales. In
response to these goals and seeking to remain competitive with other electric
utilities, the Company has developed initiatives which emphasize price
flexibility and competitive offering of energy efficiency products and services.
These initiatives will enable customers to lower or alter their peak energy
requirements. Besides promoting energy efficiency, another benefit of these
initiatives could be the ability to defer the need to construct some generating
facilities further into the future.
II-147
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 1995 Annual Report
On September 27, 1995, the Company filed a petition with the FPSC which seeks
approval for a new optional Commercial/Industrial Service (CIS) rider, which
would be applicable to the rate schedules serving the Company's largest and most
at-risk customers who are able to show they have viable alternatives for
electric power supply. The CIS rider would provide the flexibility needed to
enable the Company to offer its services in a more competitive manner to these
customers. The FPSC approval process is expected to take approximately 8 months.
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." Also, state of Florida
legislation adopted in 1993 that provides for recovery of prudent environmental
compliance costs is discussed in Note 3 to the financial statements under
"Environmental Cost Recovery."
The Company is subject to the provisions of Financial Accounting Standards
Board (FASB) Statement No. 71, Accounting for the Effects of Certain Types of
Regulation. In the event that a portion of the Company's operations is no longer
subject to these provisions, the Company would be required to write off related
regulatory assets and liabilities and determine if any other assets have been
impaired. See Note 1 to the financial statements under "Regulatory Assets and
Liabilities" for additional information.
New Accounting Standards
The FASB has issued Statement No. 121, Accounting for the Impairment of
Long-Lived Assets and Long-Lived Assets to Be Disposed Of. This statement
requires that long-lived assets be reviewed for impairment whenever events or
changes in circumstances indicate that the carrying amount for an asset may not
be recoverable. This statement also imposes stricter criteria for regulatory
assets by requiring that such assets be probable of future recovery at each
balance sheet date. The Company adopted the new rules January 1, 1996, with no
material effect on the financial statements. However, this conclusion may change
in the future as competitive factors influence wholesale and retail pricing in
the utility industry.
FINANCIAL CONDITION
Overview
The principal changes in the Company's financial condition during 1995 were
gross property additions of $63.1 million and an increase of $27 million in
notes payable. Funds for the property additions were provided by internal
sources. The increase in short-term notes payable is primarily attributable to a
$22 million note issued in relation to a payment made to a coal supplier for a
new arrangement under an existing coal contract. See the Statements of Cash
Flows and Note 5 to the financial statements under "Fuel Commitments" for
further details.
Financing Activities
The Company continued to lower its financing costs by retiring issues in 1995.
Retirements, including maturities during 1995, totaled $1.8 million of first
mortgage bonds, $0.1 million of pollution control bonds, $13.3 million of bank
notes and other long-term debt, and $1 million of preferred stock. (See the
Statements of Cash Flows for further details.)
Composite financing rates for the years 1993 through 1995 as of year end were
as follows:
1995 1994 1993
------------------------------
Composite interest rate on
long-term debt 6.5% 6.5% 7.1%
Composite preferred stock
dividend rate 6.4% 6.6% 6.5%
----------------------------------------------------------------
The composite interest rate on long-term debt remained constant at 6.5% from
1994 primarily due to no new issues or refinancings during 1995. The decrease in
the composite interest rate from 1993 to 1994 reflects the Company's efforts to
refinance higher-cost debt. The decrease in the composite preferred dividend
rate in 1995 is primarily due to a decrease in dividends on the Company's
adjustable rate preferred stock, reflecting lower interest rates.
II-148
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 1995 Annual Report
Capital Requirements for Construction
The Company's gross property additions, including those amounts related to
environmental compliance, are budgeted at $209 million for the three years
beginning in 1996 ($71 million in 1996, $67 million in 1997, and $71 million in
1998). The estimates of property additions for the three-year period include $9
million committed to meeting the requirements of the Clean Air Act, the cost of
which is expected to be recovered through the Environmental Cost Recovery Clause
(ECRC), 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 changes in business conditions; changes in
environmental regulations; revised load projections; the cost and efficiency of
construction labor, equipment, and materials; and the cost of capital. In
addition, there can be no assurance that costs related to capital expenditures
for the Company will be fully recovered. The Company does not have any baseload
generating plants under construction, and current energy demand forecasts do not
indicate a need for any additional baseload facilities until well into the
future. However, significant construction related to maintaining and upgrading
transmission and distribution facilities and generating plants will continue.
Other Capital Requirements
In addition to the funds needed for the construction program, approximately $109
million will be required by the end of 1998 in connection with maturities of
long-term debt. Also, the Company plans to continue a program to retire
higher-cost debt and preferred stock and replace these obligations with
lower-cost capital as market conditions and terms of the instruments permit.
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 -- has significantly
impacted the Company. Specific reductions in sulfur dioxide and nitrogen oxide
emissions from fossil-fired generating plants are required in two phases. Phase
I compliance began in 1995 and initially affected 28 generating units of The
Southern Company. As a result of The Southern Company's compliance strategy, an
additional 22 generating units were brought into compliance with Phase I
requirements. Phase II compliance is required by 2000, and all fossil-fired
generating plants will be affected.
In 1993, the Florida Legislature adopted legislation that allows a utility to
petition the FPSC for recovery of prudent environmental compliance costs that
are not being recovered through base rates or any other recovery mechanism. The
legislation is discussed in Note 3 to the financial statements under
"Environmental Cost Recovery." Substantially all of the costs for the Clean Air
Act and other new legislation discussed below is expected to be recovered
through the ECRC.
In 1995, the Environmental Protection Agency (EPA) began issuing annual
sulfur dioxide emission allowances through the allowance trading program. An
emission allowance is the authority to emit one ton of sulfur dioxide during a
calendar year. The method for issuing 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 Southern Company's sulfur dioxide compliance strategy is
designed to use allowances as a compliance option.
The Southern Company achieved Phase I sulfur dioxide compliance at the
affected plants by switching to low-sulfur coal, which required some equipment
upgrades. This compliance strategy resulted in unused emission allowances being
banked for later use. Compliance with nitrogen oxide emission limits was
achieved by the installation of new control equipment at 22 generating units.
Construction expenditures for Phase I compliance totaled approximately $320
million for The Southern Company, including approximately $50 million for the
Company through 1995.
For Phase II 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 units as required to meet Phase II limits.
Therefore, during the period 1996 to 2000, the current compliance strategy could
II-149
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 1995 Annual Report
require total construction expenditures of approximately $150 million for The
Southern Company, including approximately $10 million for the Company. However,
the full impact of Phase II compliance cannot now be determined with certainty,
pending the continuing 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 FPSC 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 2 percent in revenue requirements from the
Company's customers could be necessary to fully recover the cost of compliance
for both Phase I and Phase II of Title IV of the Clean Air Act. Compliance costs
include construction expenditures, increased costs for switching to low-sulfur
coal, and costs related to emission allowances.
Title III of the Clean Air Act requires a multi-year EPA study of power plant
emissions of hazardous air pollutants. The EPA is scheduled to submit a report
to Congress on the results of this study in 1996. The report will include 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 is evaluating the need to revise the ambient air quality standards
for particulate matter 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 1996, the EPA may 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 cleanup costs and has recognized in the financial statements costs to
clean up known sites. Additional sites may require environmental remediation for
which the Company may be liable for a portion or all required cleanup costs. For
additional information, see Note 3 to the financial statements under
"Environmental Cost Recovery."
Several major pieces of environmental legislation are being considered for
reauthorization or amendment by Congress. These include: the Clean Air Act; the
Clean Water Act; the Comprehensive Environmental Response, Compensation, and
Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances
Control Act; and the Endangered Species 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 additional 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 exists for liability as the result of
lawsuits alleging damages caused by electromagnetic fields.
II-150
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 1995 Annual Report
Sources of Capital
At December 31, 1995, the Company had $0.7 million of cash and cash equivalents
and $25 million of unused committed lines of credit with banks to meet its
short-term cash needs. See Note 5 to the financial statements under "Bank Credit
Arrangements" for additional information.
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; bank notes; 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.
II-151
II-152
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II-157
II-158
NOTES TO FINANCIAL STATEMENTS
Gulf Power Company 1995 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, a system service company,
Southern Communications Services (Southern Communications), Southern Electric
International (Southern Electric), Southern Nuclear Operating Company (Southern
Nuclear), The Southern Development and Investment Group (Southern Development),
and other direct and indirect subsidiaries. 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. Gulf Power Company provides electric service to the
Northwest Panhandle of Florida. 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 subsidiary companies. Southern Communications provides digital wireless
communications services to the operating companies and also markets these
services to the public within the Southeast. Southern Electric designs, builds,
owns and operates power production and delivery 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. Southern Development develops
new business opportunities related to energy products and services.
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 the FPSC.
The preparation of financial statements in conformity with generally accepted
accounting principles requires the use of estimates, and the actual results may
differ from those estimates.
Certain prior years' data presented in the financial statements have been
reclassified to conform with current year presentation.
Regulatory Assets and Liabilities
The Company is subject to the provisions of Financial Accounting Standards Board
(FASB) Statement No. 71, Accounting for the Effects of Certain Types of
Regulation. Regulatory assets represent probable future revenues to the Company
associated with certain costs that are expected to be recovered from customers
through the ratemaking process. Regulatory liabilities represent probable future
reductions in revenues associated with amounts that are to be credited to
customers through the ratemaking process. Regulatory assets and (liabilities)
reflected in the Balance Sheets at December 31 relate to:
1995 1994
------------------------
(in thousands)
Current & deferred
coal contract costs $ 46,535 $ 40,690
Deferred income taxes 29,093 30,433
Deferred loss on reacquired debt 17,015 18,494
Environmental remediation 5,789 7,800
Vacation pay 4,419 4,172
Regulatory clauses under
recovery, net 632 1,042
Deferred income tax credits (67,481) (71,964)
Deferred storm charges 7,502 -
Accumulated provision for
property damage - (11,522)
Other, net (1,510) (2,691)
----------------------------------------------------------------
Total $ 41,994 $ 16,454
================================================================
In the event that a portion of the Company's operations is no longer subject
to the provisions of Statement No. 71, the Company would be required to write
off related regulatory assets and liabilities. In addition, the Company would be
required to determine any impairment to other assets, including plant, and write
down the assets, if impaired, to their fair values.
II-159
NOTES (continued)
Gulf Power Company 1995 Annual Report
Revenues and Regulatory Cost Recovery Clauses
The Company accrues revenues for service 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 periodically adjust billings for
fluctuations in fuel and the energy component of purchased power costs. The
Company also has similar cost recovery clauses for energy conservation costs,
purchased power capacity costs, and environmental compliance costs. Revenues are
adjusted monthly for differences between recoverable costs and amounts actually
reflected in current rates.
The Company has a diversified base of customers. No single customer or
industry comprises 10 percent or more of revenues. In 1995, uncollectible
accounts continued to average significantly less than 1 percent of revenues.
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
3.6 percent in 1995 and 3.8 percent in 1994 and 1993. 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. Also, the provision for depreciation expense includes an amount
for the expected cost of removal of facilities. The decrease in 1995 is
attributable to property which was fully amortized by December 1994.
Income Taxes
The Company uses the liability method of accounting for deferred income taxes
and 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. The Company is included
in the consolidated federal income tax return of The Southern Company. See Note
8 for further information related to income taxes.
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 FPSC-approved composite rate used to calculate AFUDC
was 7.27 percent for 1995, 1994, and the second half of 1993 and 8.03 percent
for the first half of 1993. AFUDC amounts for 1995, 1994, and 1993 were $223
thousand, $1.1 million, and $966 thousand, respectively. The decrease in 1995 is
primarily due to the completion of major construction projects at Plant Daniel
at the end of 1994.
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.
II-160
NOTES (continued)
Gulf Power Company 1995 Annual Report
Financial Instruments
In accordance with FASB Statement No. 107, Disclosure About Fair Values of
Financial Instruments, financial instruments of the Company, for which the
carrying amounts do not approximate fair value, are shown in the table below as
of December 31:
1995
----------------------------
Carrying Fair
Amount Value
----------------------------
(in thousands)
Long-term debt $354,924 $365,305
-------------------------------------------------------------
1994
----------------------------
Carrying Fair
Amount Value
----------------------------
(in thousands)
Long-term debt $369,832 $355,019
Preferred stock subject to
mandatory redemption 1,000 1,030
-------------------------------------------------------------
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.
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 provides 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 $1.7 million and $2.5 million
at December 31, 1995 and 1994, respectively, is included in miscellaneous
current liabilities in the accompanying Balance Sheets.
Provision for Property Damage
The Company is self-insured for the full cost of storm and other damage to its
transmission and distribution property. At December 31, 1995, in accordance with
the FPSC's order, the accumulated provision for property damage had a negative
balance of $7.5 million as the result of charges for expenses relating to
Hurricanes Erin and Opal. The negative balance was reclassified to deferred
storm charges in the accompanying Balance Sheets. The FPSC approved the
Company's request in December to increase the amount of its annual accrual to
the accumulated provision for property damage account from $1.2 million to $3.5
million, effective October 1, 1995. The approved accrual increase is intended to
restore the account balance to a reasonable level within five years. The FPSC
also ordered the Company to file within six months a study addressing the
appropriate accumulated provision account balance and annual accrual amount. At
December 31, 1994, the accumulated provision for property damage amounted to
$11.5 million. The expense of repairing damages from major storms and other
uninsured property damages are charged to the provision account.
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 one of the
following 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.
II-161
NOTES (continued)
Gulf Power Company 1995 Annual Report
Postretirement Benefits
The Company provides certain medical care and life insurance benefits for
retired employees. Substantially all employees may become eligible for these
benefits when they retire. Trusts are funded to the extent deductible under
federal income tax regulations or to the extent required by the Company's
regulatory commissions. Amounts funded are primarily invested in equity and
fixed-income securities. FASB Statement No. 106, Employers' Accounting for
Postretirement Benefits Other Than Pensions, 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."
Funded Status and Cost of Benefits
The following tables show actuarial results and assumptions for pension and
postretirement insurance benefits as computed under the requirements of FASB
Statement Nos. 87 and 106, respectively. The funded status of the plans at
December 31 was as follows:
Pension
-------------------------
1995 1994
-------------------------
(in thousands)
Actuarial present value of
benefit obligation:
Vested benefits $ 87,652 $ 73,552
Non-vested benefits 4,284 3,016
------------------------------------------------------------------
Accumulated benefit obligation 91,936 76,568
Additional amounts related to
projected salary increases 29,073 29,451
------------------------------------------------------------------
Projected benefit obligation 121,009 106,019
Less:
Fair value of plan assets 180,980 151,337
Unrecognized net gain (48,438) (36,599)
Unrecognized prior service cost 2,578 2,802
Unrecognized transition asset (7,187) (8,034)
------------------------------------------------------------------
Prepaid asset recognized in
the Balance Sheets $ 6,924 $ 3,487
==================================================================
Postretirement Benefits
---------------------------
1995 1994
---------------------------
(in thousands)
Actuarial present value of
benefit obligation:
Retirees and dependents $ 9,759 $10,800
Employees eligible to retire 4,921 4,043
Other employees 17,646 19,639
----------------------------------------------------------------
Accumulated benefit obligation 32,326 34,482
Less:
Fair value of plan assets 7,050 5,740
Unrecognized net loss (gain) 1,538 (458)
Unrecognized transition
obligation 7,437 15,520
----------------------------------------------------------------
Accrued liability recognized in
the Balance Sheets $16,301 $13,680
================================================================
In 1995, the Company announced a cost sharing program for postretirement
benefits. The program establishes limits on amounts the Company will pay to
provide future retiree postretirement benefits. This change reduced the 1995
accumulated postretirement benefit obligation by approximately $7.1 million.
The weighted average rates assumed in the actuarial calculations were:
1995 1994 1993
-----------------------------
Discount 7.3% 8.0% 7.5%
Annual salary increase 4.8% 5.5% 5.0%
Long-term return on plan
assets 8.5% 8.5% 8.5%
---------------------------------------------------------------
An additional assumption used in measuring the accumulated postretirement
benefit obligation was a weighted average medical care cost trend rate of 9.8
percent for 1995, decreasing to 5.3 percent through the year 2005 and remaining
at that level thereafter. An annual increase in the assumed medical care cost
trend rate of 1 percent would increase the accumulated benefit obligation at
December 31, 1995, by $2.5 million and the aggregate of the service and interest
cost components of the net retiree cost by $610 thousand.
II-162
NOTES (continued)
Gulf Power Company 1995 Annual Report
Components of the plans' net costs are shown below:
Pension
------------------------------------
1995 1994 1993
------------------------------------
(in thousands)
Benefits earned during
the year $ 3,867 $ 3,775 $ 3,710
Interest cost on projected
benefit obligation 8,042 7,484 7,319
Actual (return) loss on
plan assets (33,853) 3,721 (20,672)
Net amortization
and deferral 19,619 (17,054) 8,853
------------------------------------------------------------------
Net pension cost (income) $ (2,325) $(2,074) $ (790)
==================================================================
Of the above net pension amounts, pension income of $1.8 million in 1995,
$1.5 million in 1994, and $601 thousand in 1993 were recorded in operating
expenses, and the remainder was recorded in construction and other accounts.
Postretirement Benefits
--------------------------------
1995 1994 1993
--------------------------------
(in thousands)
Benefits earned during the year $1,259 $1,362 $1,166
Interest cost on accumulated
benefit obligation 2,520 2,535 2,339
Amortization of transition
obligation 853 854 854
Actual (return) loss on plan (1,268) 129 (731)
assets
Net amortization and deferral 742 (591) 310
-------------------------------------------------------------------
Net postretirement cost $4,106 $4,289 $3,938
===================================================================
Of the above net postretirement costs recorded, $3.1 million in 1995 and 1994
and $3.0 million in 1993 were charged to operating expenses, and the remainder
was recorded in construction and other accounts.
Work Force Reduction Programs
The Company implemented a voluntary work force reduction program in the fourth
quarter of 1995 and recorded $7 million in December for the total cost related
to the program. These costs are expected to be recovered through future savings
over approximately two years. The Company has also incurred its pro rata share
for the costs of affiliated companies' programs. The costs related to these
programs were $1 million, $1.3 million, and $109 thousand for the years 1995,
1994, and 1993, respectively.
3. LITIGATION AND REGULATORY MATTERS
FERC Reviews Equity Returns
In May 1991, the FERC ordered that hearings be conducted concerning the
reasonableness of the operating companies' 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
change in the rate of return on common equity that may require refunds as a
result of this proceeding would be substantially for the period beginning in
July 1991 and ending in October 1992. 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.
In August 1994, the FERC instituted another proceeding based on substantially
the same issues as in the 1991 proceeding. The second period under review for
possible refunds was substantially from October 1994 through December 1995. In
November 1995, a FERC administrative law judge issued an opinion that the FERC
staff failed to meet its burden of proof, and therefore, no change in the equity
return was necessary. The FERC staff has filed exceptions to the administrative
law judge's opinion, and the matter remains pending before the FERC.
If the rates of return on common equity recommended by the FERC staff were
applied to all of the schedules and contracts involved in both proceedings and
refunds were ordered, the amount of refunds could range up to approximately $120
million for The Southern Company, including approximately $8 million for the
Company at December 31, 1995. However, management believes that rates are not
excessive and that refunds are not justified.
II-163
NOTES (continued)
Gulf Power Company 1995 Annual Report
FPSC Review of Earnings
As a result of an investigation of Gulf's 1995 earnings by the FPSC, Gulf
presented a 1995 earnings proposal, which required deferring any jurisdictional
revenues contributing to annual earnings in excess of a 12.75%
jurisdictional-adjusted return on equity. The proposal was approved by the FPSC
in August 1995. Gulf was to petition the FPSC to determine the disposition of
any deferred revenues by April 1996. Based on 1995 actual results, no revenues
were deferred.
Environmental Cost Recovery
In April 1993, the Florida Legislature adopted legislation for an Environmental
Cost Recovery Clause (ECRC), 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 recovery mechanism. Such environmental
costs include operation and maintenance expense, emission allowance expense,
depreciation, and a return on invested capital.
On January 12, 1994, the FPSC approved the Company's initial petition under
the ECRC for recovery of environmental costs that were projected to be incurred
from July 1993 through September 1994. Since this initial period, recovery under
the ECRC has been determined semi-annually and includes a true-up of the prior
period and a projection of the ensuing six month period. During 1995 and 1994,
the Company recorded ECRC revenues of $11.8 million and $7.2 million,
respectively.
At December 31, 1995, the Company's liability for the estimated costs of
environmental remediation projects for known sites was $5.8 million. These
estimated costs are expected to be expended during the period 1996 to 1999.
These projects have been approved by the FPSC for recovery through the ECRC
discussed above. Therefore, the Company recorded $2.0 million in current assets
and $3.8 million in deferred charges representing the future recoverability of
these costs.
4. CONSTRUCTION PROGRAM
The Company is engaged in a continuous construction program, the cost of which
is currently estimated to total $71 million in 1996, $67 million in 1997, and
$71 million in 1998. 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. At
December 31, 1995, significant purchase commitments were outstanding in
connection with the construction program. The Company does not have any new
baseload generating plants under construction. However, 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, pollution control
bonds, and preferred stock; bank notes; 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. If the attractiveness of current
short-term interest rates continues, the Company may maintain a higher level of
short-term indebtedness than has historically been true.
Bank Credit Arrangements
At December 31, 1995, the Company had $20 million in revolving credit lines that
expire May 31, 1998, $5 million in revolving credit lines subject to renewal
June 1, 1997, and $21.5 million of lines of credit with banks subject to renewal
June 1 of each year, of which $25 million remained unused. In connection with
these credit lines, the Company has agreed to pay commitment fees and/or to
II-164
NOTES (continued)
Gulf Power Company 1995 Annual Report
maintain compensating balances with the banks. The compensating balances, which
represent substantially all of 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 fourteen major money center banks that
total $250 million, of which $37 million was committed at December 31, 1995.
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 at December 31, 1995, were as follows:
Year Fuel
------- ---------------
(in millions)
1996 $ 125
1997 126
1998 95
1999 86
2000 80
2001 - 2007 557
-------------------------------------------------------
Total commitments $1,069
=======================================================
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 this payment was $60 million. This
amount is being amortized to expense on a per ton basis over a nine-year period.
The remaining unamortized amount was $1.5 million at December 31, 1995.
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 was $23 million
at December 31, 1995.
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 was amortized to expense on a per ton basis during 1993,
1994, and the first quarter of 1995.
In December 1995, the Company made a payment of $22 million to a coal
supplier under an arrangement to lower the cost of future coal and/or to suspend
the purchase of coal under an existing contract for 25 months. This amount is to
be amortized to expense on a per ton basis during 1996, 1997, and the first
quarter of 1998.
The amortization expense of these contract buyouts and renegotiations is
being recovered through the fuel cost recovery clause discussed under "Revenues
and Regulatory Cost Recovery Clauses" in Note 1.
Lease Agreements
In 1989, the Company and Mississippi Power jointly entered into a twenty-two
year operating lease agreement for the use of 495 aluminum railcars. In 1994, a
second lease agreement for the use of 250 additional aluminum railcars was
entered into for twenty-two years. Both of these leases are for the
transportation of coal to Plant Daniel. The Company, as a joint owner of Plant
Daniel, is responsible for one half of the lease costs. The lease costs are
charged to fuel inventory and are allocated to fuel expense as the fuel is used.
The Company's share of the lease costs charged to fuel inventory was $1.7
million in 1995 and $1.2 million in 1994 and 1993. The Company's annual lease
payments for 1996 through 2000 will be approximately $1.7 million and after
2000, lease payments total approximately $22.4 million. The Company has the
option after three years from the date of the original contract on the second
lease agreement to purchase the railcars at the greater of the termination value
or the fair market value. Additionally, at the end of each lease term, the
Company has the option to renew the lease.
II-165
NOTES (continued)
Gulf Power Company 1995 Annual Report
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, an operating affiliate, jointly own Plant
Scherer Unit No. 3. Plant Scherer is 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, 1995, the Company's percentage ownership and its investment
in these jointly owned facilities were as follows:
Plant Scherer Plant
Unit No. 3 Daniel
(coal-fired) (coal-fired)
------------------------------
(in thousands)
Plant In Service $185,755(1) $222,515
Accumulated Depreciation $49,982 $97,033
Construction Work in Progress $288 $683
Nameplate Capacity (2)
(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
7. LONG-TERM POWER SALES AGREEMENTS
The Company and the other operating affiliates have long-term contractual
agreements for the sale of capacity and energy to certain non-affiliated
utilities located outside the system's service area. The agreements for non-firm
capacity expired in 1994. The unit power sales agreements, expiring at various
dates discussed below, 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 capacity revenues have been as follows:
Other
Unit Long-
Year Power Term Total
---------- ------------------------------------
(in thousands)
1995 $25,870 $ - $25,870
1994 29,653 1,273 30,926
1993 31,162 2,643 33,805
----------------------------------------------------------
Unit power from specific generating plants of The Southern Company is
currently being sold to Florida Power Corporation (FPC), Florida Power & Light
Company (FP&L), Jacksonville Electric Authority (JEA), and the city of
Tallahassee, Florida. Under these agreements, 210 megawatts of net dependable
capacity were sold by the Company during 1995, and sales will remain at that
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 $25.4 million in 1995, $29.3 million in 1994, and $39.5
million in 1993, or 4.1 percent, 5.1 percent, and 6.8 percent of operating
revenues, respectively.
II-166
NOTES (continued)
Gulf Power Company 1995 Annual Report
8. INCOME TAXES
Effective January 1, 1993, the Company adopted FASB Statement No. 109,
Accounting for Income Taxes. The adoption resulted in the recording of
additional deferred income taxes and related regulatory assets and liabilities.
At December 31, 1995, the tax-related regulatory assets to be recovered from
customers were $29.1 million. These assets are attributable to tax benefits
flowed through to customers in prior years and to taxes applicable to
capitalized AFUDC. At December 31, 1995, the tax-related regulatory liabilities
to be refunded to customers were $67.5 million. These liabilities are
attributable to deferred taxes previously recognized at rates higher than
current enacted tax law and to unamortized investment tax credits.
At December 31, 1995, the Company's current federal and state income taxes
accrued, including the current portion of deferred income taxes, were equal to a
debit balance of $4.2 million as a result of the early settlement of taxes owed.
This amount was reclassified to current assets to reflect the tax prepayment and
will be used to satisfy taxes accrued during 1996.
Details of the federal and state income tax provisions are as follows:
1995 1994 1993
----------------------------------
(in thousands)
Total provision for
income taxes:
Federal--
Currently payable $29,018 $34,941 $24,354
Deferred--current year 23,172 18,556 26,396
--reversal of
prior years (23,116) (24,787) (22,102)
------------------------------------------------------------------
29,074 28,710 28,648
------------------------------------------------------------------
State--
Currently payable 4,778 5,907 3,950
Deferred--current year 3,313 2,549 3,838
--reversal of
prior years (2,979) (3,304) (2,785)
------------------------------------------------------------------
5,112 5,152 5,003
------------------------------------------------------------------
Total 34,186 33,862 33,651
Less income taxes charged
(credited) to other income 121 (95) 921
------------------------------------------------------------------
Federal and state income
taxes charged
to operations $34,065 $33,957 $32,730
==================================================================
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:
1995 1994
-----------------------
(in thousands)
Deferred tax liabilities:
Accelerated depreciation $146,926 $146,686
Property basis differences 19,976 18,468
Coal contract buyouts 3,838 6,896
Property insurance 3,039 -
Other 10,573 11,846
-------------------------------------------------------------------
Total 184,352 183,896
-------------------------------------------------------------------
Deferred tax assets:
Federal effect of state deferred taxes 10,212 9,732
Postretirement benefits 5,494 4,383
Property insurance - 5,200
Other 6,313 7,566
-------------------------------------------------------------------
Total 22,019 26,881
-------------------------------------------------------------------
Net deferred tax liabilities 162,333 157,015
Less current portion, net (12) 5,334
-------------------------------------------------------------------
Accumulated deferred income
taxes in the Balance Sheets $162,345 $151,681
===================================================================
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 1995, 1994 and 1993. At December 31, 1995, 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:
1995 1994 1993
-----------------------------
Federal statutory rate 35% 35% 35%
State income tax,
net of federal deduction 4 4 3
Non-deductible book
depreciation 1 1 1
Difference in prior years'
deferred and current tax rate (3) (2) (2)
Other (2) (2) (1)
---------------------------------------------------------------
Effective income tax rate 35% 36% 36%
===============================================================
The Company and the other subsidiaries of The Southern Company file a
consolidated federal tax return. Under a joint consolidated income tax
agreement, each subsidiary's current and deferred tax expense is computed
II-167
NOTES (continued)
Gulf Power Company 1995 Annual Report
on a stand-alone basis. Tax benefits from losses of the parent company are
allocated to each subsidiary based on the ratio of taxable income to total
consolidated taxable income.
9. POLLUTION CONTROL OBLIGATIONS AND OTHER LONG-TERM DEBT
Details of pollution control bonds and other long-term debt at December 31 are
as follows:
1995 1994
--------------------------
(in thousands)
Obligations incurred in
connection with the sale by
public authorities of
tax-exempt pollution control
revenue bonds:
Collateralized
6% due 2006* $ 12,075 $ 12,200
8.25% due 2017 32,000 32,000
7.125% due 2021 21,200 21,200
6.75% due 2022 8,930 8,930
5.70% due 2023 7,875 7,875
5.80% due 2023 32,550 32,550
6.20% due 2023 13,000 13,000
6.30% due 2024 22,000 22,000
Variable Rate
Remarketable daily 20,000 20,000
---------------------------------------------------------------
$169,630 $169,755
---------------------------------------------------------------
Notes payable:
5.39% due 1995 - 4,500
5.72% due 1995 - 4,500
4.69% due 1996 25,000 25,000
6.44% due 1994-1998 12,074 16,388
---------------------------------------------------------------
37,074 50,388
---------------------------------------------------------------
Total $206,704 $220,143
===============================================================
* Sinking fund requirement applicable to the 6 percent pollution control
bonds is $200 thousand for 1996 with increasing increments periodically
thereafter through 2005, with the remaining balance due in 2006.
Pollution control obligations represent installment purchases of pollution
control facilities financed by funds derived from sales by public authorities of
revenue bonds. 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.
The 5.39 percent and 5.72 percent notes payable were the Company's portion of
notes payable issued in connection with the termination of Plant Daniel coal
contracts (see Note 5 under "Fuel Commitments" for further information). The
estimated annual maturities of the notes payable through 2000 are as follows:
$29.6 million in 1996, $4.9 million in 1997, $2.6 million in 1998, and none in
1999 and 2000.
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 at December 31 is as follows:
1995 1994
----------------------
(in thousands)
Bond improvement fund requirement $ 1,750 $ 1,750
Less: Portion to be satisfied by cash
or certifying property
additions - 1,750
---------------------------------------------------------------
Cash sinking fund requirement 1,750 -
Current portion of notes payable 29,598 13,314
(Note 9)
Pollution control bond maturity 200 125
(Note 9)
---------------------------------------------------------------
Total $31,548 $13,439
===============================================================
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.
II-168
NOTES (continued)
Gulf Power Company 1995 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, 1995, retained earnings of $101 million were
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 of 12 months 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, 1995, the ratio was 48.7 percent.
12. QUARTERLY FINANCIAL DATA (Unaudited)
Summarized quarterly financial data for 1995 and 1994 are as follows:
Net Income
After Dividends
Operating Operating on Preferred
Quarter Ended Revenues Income Stock
------------------------------------------------------------------
(in thousands)
March 31, 1995 $140,918 $19,503 $10,880
June 30, 1995 153,057 23,390 14,096
Sept. 30, 1995 184,251 35,187 26,588
Dec. 31, 1995 140,851 13,082 5,590
March 31, 1994 $138,088 $19,154 $10,117
June 30, 1994 146,769 19,957 8,886
Sept. 30, 1994 162,143 31,123 21,831
Dec. 31, 1994 131,813 21,979 14,395
------------------------------------------------------------------
The Company's business is influenced by seasonal weather conditions and the
timing of rate changes, among other factors.
II-169
II-170
II-171A
II-171B
II-171C
II-172
II-173A
II-173B
II-173C
II-174
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, 1995
OR
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the Transition Period from to
----------------------------------------------
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)
270 Peachtree Street, N.W.
Atlanta, Georgia 30303
(770) 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
================================================================================
Securities registered pursuant to Section 12(b) of the Act:
Each of the following classes or series of securities registered pursuant to
Section 12(b) of the Act is registered on the New York Stock Exchange.
Title of each class Registrant
------------------- ----------
Common Stock, $5 par value The Southern Company
-------------------------------------------------
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
9 1/4% Series due 2021
-------------------------------------------------
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
Subsidiary obligated mandatorily redeemable
preferred securities, $25 stated value*
9% Monthly Income Preferred Securities, Series A
First mortgage bonds
6 1/8% Series due 1999 6 7/8% Series due 2002
----------------------------------------------------
Depositary preferred shares, each representing Mississippi Power Company
one-fourth of a share of preferred stock,
cumulative, $100 par value
7.25% Series 6.32% Series
6.65% Series
-----------------------------------------------------
Preferred stock, cumulative, $25 par value Savannah Electric and Power Company
6.64% Series
*Issued by Georgia Power Capital, L.P., and guaranteed to the extent Georgia
Power Capital has funds by Georgia Power Company.
================================================================================
Securities registered pursuant to Section 12(g) of the Act:
Title of each class Registrant
------------------- ----------
Preferred stock, cumulative, $100 par value Alabama Power Company
4.20% Series 4.64% Series 5.96% Series
4.52% Series 4.72% Series 6.88% Series
4.60% Series 4.92% Series
Class A preferred, cumulative, $100,000 stated capital
Auction (1993 Series)
Class A preferred, cumulative, $100 stated capital
Auction (1988 Series)
--------------------------------------------------------
Preferred stock, cumulative, $100 stated value Georgia Power Company
$4.60 Series $4.72 Series $5.64 Series
$4.60 Series (1962) $4.92 Series $6.48 Series
$4.60 Series (1963) $4.96 Series $6.60 Series
$4.60 Series (1964) $5.00 Series
--------------------------------------------------------
Preferred stock, cumulative, $100 par value Gulf Power Company
4.64% Series 5.44% Series 7.88% Series
5.16% Series 7.52% Series
Class A preferred, cumulative, $10 par, $25 stated capital
6.72% Series 7.00% Series 7.30% Series
Adjustable Rate (1993 Series)
--------------------------------------------------------
Preferred stock, cumulative, $100 par value Mississippi Power Company
4.40% Series 4.60% Series 4.72% Series
7.00% Series
================================================================================
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. (X)
Aggregate market value of voting stock held by non-affiliates of The
Southern Company at February 29, 1996: $16.0 billion. Each of such other
registrants is a wholly-owned subsidiary of The Southern Company and has no
voting stock other than its common stock. A description of registrants' common
stock follows:
Documents incorporated by reference: specified portions of The Southern
Company's Proxy Statement relating to the 1996 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.
================================================================================
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-8
Competition................................................ I-12
Regulation................................................. I-13
Rate Matters............................................... I-15
Employee Relations......................................... I-17
Item 2 Properties................................................... I-18
Item 3 Legal Proceedings............................................ I-23
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 Matters........................................ II-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
i
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
Communications............... Southern Communications Services, Inc.
Dalton....................... City of Dalton, Georgia
DOE.......................... United States Department of Energy
Edelnor...................... Empresa 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
IRS.......................... Internal Revenue Service
JEA.......................... Jacksonville Electric Authority
MEAG......................... Municipal Electric Authority of Georgia
MISSISSIPPI.................. Mississippi Power Company
Mobile Energy................ Mobile Energy Services Company, L.L.C.
NRC.......................... Nuclear Regulatory Commission
OPC.......................... Oglethorpe Power Corporation
operating affiliates......... ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH
PSC.......................... Public Service Commission
RUS.......................... Rural Utility Service (formerly Rural
Electrification Administration)
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 Development......... The Southern Development and Investment Group,
Inc.
Southern Nuclear............. Southern Nuclear Operating Company, Inc.
SOUTHERN system.............. SOUTHERN, the operating affiliates, SEGCO, SEI,
Southern Nuclear, SCS, Communications,
Southern Development and other subsidiaries
SWEB......................... South Western Electricity plc (United Kingdom)
TVA.......................... Tennessee Valley Authority
ii
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 the State 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, Communications,
Southern Nuclear, SCS (the system service company), Southern Development and
other direct and indirect subsidiaries. SEI designs, builds, owns and operates
power production and delivery 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 under "New Business Development."
Communications provides digital wireless communications services to SOUTHERN's
operating affiliates and also markets these services to the public within the
Southeast. Southern Nuclear provides services to the Southern electric system's
nuclear plants. Southern Development explores, develops and markets energy
management services and other business lines relating to SOUTHERN's core
business of generating and distributing energy.
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.
I-1
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 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 SOUTHERN, 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, 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. SEI, Southern
Development and Communications have also secured from the operating affiliates
certain services which are furnished at cost.
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, if approved, 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 subsidiaries.
SEI's primary business focus is international and domestic cogeneration, the
independent power market, and the privatization and development of generation,
transmission and distribution facilities in the international market. During
1995, SEI also entered the business of power marketing.
Reference is made to Note 15 to the financial statements of SOUTHERN in Item
8 herein for additional information regarding SOUTHERN's business segments and
geographic areas.
In September 1995, SOUTHERN acquired SWEB, one of the United Kingdom's 12
regional electric distribution companies, for approximately $1.8 billion. SWEB's
main business is the distribution of electricity to customers in the Southwest
of England. Based in Bristol, SWEB serves approximately 1.3 million customers in
an area roughly the size of Connecticut, with almost 2 million residents. SWEB
is also a supplier of electricity to franchise customers in its authorized area
and to customers in the competitive second-tier market. Through its 7.7% equity
investment in Teesside Power Limited, a combined cycle gas turbine plant with a
capacity of 1,875 megawatts, SWEB is involved in power generation. In addition,
SWEB is involved in certain non-regulated activities which include gas supply
and telecommunications. For additional information regarding the acquisition of
SWEB, reference is made to Note 14 to SOUTHERN's financial statements in Item 8
herein.
I-2
See Item 2 - PROPERTIES - "Other Electric Generation Facilities" herein for
additional information regarding SEI projects.
SEI and Southern Development render consulting services and market SOUTHERN
system expertise in the United States and throughout the world. They contract
with other public utilities, commercial concerns and government agencies for the
rendition of services and the licensing of intellectual property. More
specifically, Southern Development is focusing on new and existing programs to
enhance customer satisfaction and efficiency and stockholder value, such as:
Good Cents, an energy efficiency program for electric utility customers;
EnerLink, a group of energy management products and services for large
commercial and industrial electricity users; Flywheel, an energy storage device;
PowerCall Security, a home security system; other energy management programs
under development; and telecommunications operations related to energy
management programs.
By the end of 1995, the construction of Communications' wireless
communications system was essentially complete, and Communications began serving
SOUTHERN's operating affiliates and marketing its services to non-affiliates
within the Southeast. The system covers 122,000 square miles and combines the
functions of two-way radio dispatch, cellular phone, short text and numeric
messaging and wireless data transfer.
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, these activities also involve a higher degree of risk.
SOUTHERN expects to make substantial investments over the period 1996-1998 in
these and other new businesses.
Certain Factors Affecting the Industry
Various factors are currently affecting the electric utility industry in
general, including increasing competition and the regulatory changes related
thereto, costs required to comply with environmental regulations, and the
potential for new business opportunities (with their associated risks) outside
of traditional rate-regulated operations. The effects of these and other factors
on the SOUTHERN system are described herein; particular reference is made to
Item 1 - BUSINESS - "New Business Development," "Competition" and "Environmental
Regulation."
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 1996 through
1998 by the operating affiliates, SEGCO, SCS, Southern Nuclear, Communications
and SEI are estimated as follows: (in millions)
---------------------------------------------------------
1996 1997 1998
-------- --------- ---------
ALABAMA $ 491 $ 446 $ 479
GEORGIA 530 537 529
GULF 71 67 71
MISSISSIPPI 67 62 53
SAVANNAH 33 30 23
SEGCO 13 6 7
SCS 29 16 10
Southern Nuclear 1 1 1
Communications 26 48 6
SEI* 213 218 123
========================================================
SOUTHERN system $1,474 $1,431 $1,302
========================================================
*These construction estimates do not include amounts which may be expended
by SEI on future power production projects or by any subsidiaries created to
effect such future projects.
Reference is made to Note 4 to the financial statements of each registrant
(except GULF) in Item 8 herein for the amounts of AFUDC included in the above
estimates. GULF's estimates include AFUDC of $75,000 in 1996 and no AFUDC in
1997 and 1998. (See also Item 1 - BUSINESS - "Financing Programs" herein.)
I-3
*Communications, SCS and Southern Nuclear plan capital additions to general
plant in 1996 of $26 million, $29 million and $1 million, respectively, while
SEGCO plans capital additions of $13 million to generating facilities. SEI plans
capital additions of $106 million to generating facilities and $107 million to
distribution facilities. These estimates do not reflect the possibility of SEI's
securing a contract(s) to buy or build additional generating facilities.
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
projections; 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.
The operating affiliates do not have any new baseload generating plants
under construction. However, within the service area, the construction of
combustion turbine peaking units with an aggregate capacity of approximately 600
megawatts is planned to be completed by 1998. In addition, significant
construction related to transmission and distribution facilities and the
upgrading and extension of the useful lives of generating plants will continue.
In 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 Plant
For information regarding GEORGIA's Rocky Mountain Plant, including a joint
ownership agreement with OPC and the uncertain recovery of GEORGIA's costs in
this plant, reference is made to Note 3 to SOUTHERN's and to GEORGIA's financial
statements in Item 8 herein.
I-4
Financing Programs
SOUTHERN may require additional equity capital in 1996. The amount and timing of
additional equity capital to be raised in 1996, as well as subsequent years,
will be contingent on SOUTHERN's investment opportunities, primarily through
SEI. Equity capital can be provided from any combination of public offerings,
private placements, or SOUTHERN's stock plans. The operating affiliates'
construction programs are expected to be financed primarily from internal
sources. Short-term debt will be utilized as appropriate at SOUTHERN and the
operating affiliates. 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 if market conditions permit.
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. The ability to issue securities in the future will depend on
coverages at that time. Currently each of the operating affiliates expects to
have adequate coverage ratios for anticipated requirements through at least
1998.
The amounts of securities representing short-term unsecured indebtedness
allowable under the respective charters, and the maximum amounts of short-term
or term-loan indebtedness authorized by the appropriate regulatory authorities,
are shown in the following table:
======================================================
Short-Term Unsecured Indebtedness
------------------------------------------------------
Allowable
Under Charter
at December 31, 1995
Percent of
Secured
Indebtedness
and Other
Amount Capital (2)
------------- -------------------
(Millions)
ALABAMA $ 1,123 20%
GEORGIA 1,677 20
GULF 88 10
MISSISSIPPI 149 20
SAVANNAH 68 20
SOUTHERN (1) (1)
------------------------------------------------------
======================================================
Short-Term or Term-Loan Indebtedness
------------------------------------------------------
Maximum Regulatory
Authorization
Outstanding at
Amount December 31, 1995
------------ ---------------------
(Millions)
ALABAMA $ 750 (3) $390
GEORGIA 1,700 (4) 400
GULF 150 (3) 118
MISSISSIPPI 350 (3) 55
SAVANNAH 90 (4) 4
SOUTHERN 2,000 (3) 619
--------------------------------------------------------
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 increased from 10% of secured indebtedness
and other capital to 20% thereof. These approved increases are reflected in the
above table.
I-5
(3) ALABAMA's authority is based on authorization received from the Alabama
PSC, which expires December 31, 1998. No SEC authorization is required for
ALABAMA. GULF, MISSISSIPPI 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 December 31, 1996, December 31,
2002 and March 31, 2001, respectively.
(4) GEORGIA and SAVANNAH have received SEC authorization to issue from time
to time short-term and term-loan notes to banks and commercial paper to dealers
in the amounts shown through December 31, 2002. Authorization for term-loan
indebtedness is also required by and has been received from the Georgia PSC.
Currently, GEORGIA and SAVANNAH have remaining authority from the Georgia PSC of
$809 million and $40 million expiring December 31, 1996 and June 30, 1996,
respectively.
Reference is made to Note 5 to the financial statements for SOUTHERN,
ALABAMA, GULF, MISSISSIPPI and SAVANNAH and Note 9 to the financial statements
for GEORGIA in Item 8 herein for information regarding the registrants' credit
arrangements.
I-6
Fuel Supply
The operating affiliates' and SEGCO's supply of electricity is derived
predominantly from coal. The sources of generation for the years 1993 through
1995 and the estimates for 1996 are shown below:
Oil and
ALABAMA Coal Nuclear Hydro Gas
----------------------------------------
1993 70% 22% 8% *%
1994 68 23 9 *
1995 73 19 8 *
1996 73 20 7 *
GEORGIA
1993 77 20 3 *
1994 75 22 3 *
1995 74 22 3 1
1996 76 21 2 1
GULF
1993 99 ** ** 1
1994 100 ** ** *
1995 99 ** ** 1
1996 99 ** ** 1
MISSISSIPPI
1993 90 ** ** 10
1994 85 ** ** 15
1995 79 ** ** 21
1996 81 ** ** 19
SAVANNAH
1993 83 ** ** 17
1994 91 ** ** 9
1995 80 ** ** 20
1996 83 ** ** 17
SEGCO
1993 100 ** ** *
1994 100 ** ** *
1995 100 ** ** *
1996 100 ** ** *
SOUTHERN system***
1993 78 17 4 1
1994 75 19 5 1
1995 77 17 4 2
1996 78 17 4 1
---------------------------------------------------------
*Less than 0.5%.
**Not applicable.
***Amounts shown for the SOUTHERN system are weighted
averages of the operating affiliates and SEGCO.
The average costs of fuel in cents per net kilowatt-hour generated for 1993
through 1995 are shown below:
Oil and Weighted
ALABAMA Coal Nuclear Gas Average
----------------------------------------------
1993 2.11 0.51 * 1.73
1994 1.92 0.49 * 1.56
1995 1.71 0.50 * 1.48
GEORGIA
1993 1.75 0.58 * 1.52
1994 1.67 0.63 * 1.44
1995 1.67 0.60 * 1.44
GULF
1993 2.03 ** 4.50 2.05
1994 2.00 ** * 2.01
1995 2.08 ** 3.56 2.09
MISSISSIPPI
1993 1.66 ** 2.97 1.71
1994 1.67 ** 2.60 1.71
1995 1.58 ** 2.33 1.64
SAVANNAH
1993 2.02 ** 4.70 2.49
1994 2.19 ** 4.72 2.42
1995 1.77 ** 3.80 2.18
SEGCO
1993 1.80 ** * 1.81
1994 1.83 ** * 1.83
1995 1.87 ** * 1.87
SOUTHERN system***
1993 1.90 0.54 4.34 1.67
1994 1.80 0.56 3.99 1.56
1995 1.73 0.56 3.37 1.53
---------------------------------------------------------------
*Not meaningful because of minimal generation from fuel
source.
**Not applicable.
***Amounts shown for the SOUTHERN system are weighted
averages of the operating affiliates and SEGCO.
See SELECTED FINANCIAL DATA in Item 6 herein for each registrant's source
of energy supply.
I-7
As of February 23, 1996, the operating affiliates and SEGCO had stockpiles
of coal on hand at their respective coal-fired plants which represented an
estimated 29 days of recoverable supply for bituminous coal and 32 days for
sub-bituminous coal. It is estimated that approximately 58.2 million tons of
coal will be consumed in 1996 by the operating affiliates and SEGCO (including
those units GEORGIA owns jointly with OPC, MEAG and Dalton and operates for FP&L
and JEA and the units ALABAMA owns jointly with AEC). The operating affiliates
and SEGCO currently have 38 coal contracts. These contracts cover remaining
terms of up to 17 years. Approximately 20% of 1996 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 30% of the SOUTHERN system's coal supply. Additionally, it has been
determined that approximately 34 days of recoverable supply is the appropriate
level for coal stockpiles. During 1995, the operating affiliates' and SEGCO's
average price of coal delivered was approximately $40 per ton.
The typical sulfur content of coal purchased under contracts ranges from
approximately 0.49% to 2.76% 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" herein.
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 agreements with
non-affiliated industrial and mining firms to mine coal from ALABAMA's reserves,
as well as their own reserves, for supply to ALABAMA's generating units.
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 GULF and
MISSISSIPPI in Item 8 herein.
ALABAMA and GEORGIA have numerous contracts covering a portion of their
nuclear fuel needs for uranium, conversion services, enrichment services and
fuel fabrication. These contracts have varying expiration dates and most are
short to medium term (less than 10 years). Management believes that sufficient
capacity for nuclear fuel supplies and processing exists to preclude the
impairment of normal operations of the SOUTHERN system's nuclear generating
units.
ALABAMA and GEORGIA have contracts with the DOE that provide for the
permanent disposal of spent nuclear fuel. Although disposal was scheduled to
begin in 1998, 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.
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,
I-8
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 some of 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, 48 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, six rural electric distribution cooperative
associations and one generating and transmitting cooperative.
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.
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,
1995, the registrants derived their respective industrial revenues as shown in
the following table.
I-9
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. On January 12, 1996, ALABAMA, GEORGIA and MISSISSIPPI filed a
lawsuit against TVA for violation of this Act. See Item 3 - LEGAL PROCEEDINGS
herein for additional information.
The RUS 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 71 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 840 megawatts of nameplate capacity, including an undivided
ownership interest in ALABAMA's Plant Miller Units 1 and 2. AEC's facilities
were financed with RUS 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 RUS, 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 joint-ownership with
AEC of a portion of Plant Miller.
Another of the 71 electric cooperatives is SMEPA, also a generating and
transmitting cooperative. SMEPA 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. During 1994 and 1995, OPC gave GEORGIA notice of its
intent to decrease its purchases of capacity by 250 megawatts in September 1996
and an additional 250 megawatts in September 1997.
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
I-10
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. See
Note 7 to ALABAMA's financial statements in Item 8 herein for further
information on these contracts.
Forty-seven 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. One municipally-owned electric
distribution system is still served on a full requirements wholesale basis 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 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 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
of at least 900 kilowatts may receive electric service from the supplier of its
choice. (See also Item 1 - BUSINESS - "Competition" herein.)
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. (See also Item 1 - BUSINESS - "Competition"
herein.)
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 300,000 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
I-11
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.
Long-Term Power Sales Agreements
Reference is made to Note 7 to the financial statements for SOUTHERN, ALABAMA,
GEORGIA, GULF and MISSISSIPPI and Note 6 to the financial statements for
SAVANNAH in Item 8 herein for information regarding contracts for the sales of
capacity and energy to non-territorial customers.
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 has experienced 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.
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 1995, ALABAMA purchased approximately 115
million kilowatt-hours from such companies at a cost of $1.8 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 1995, GEORGIA purchased 4 million
kilowatt-hours from such companies at a cost of $78,000. GEORGIA has entered
into a 30-year purchase power agreement, scheduled to begin in June 1998, for
electricity during peaking periods from a planned 300-megawatt cogeneration
facility. Payments are subject to reductions for failure to meet minimum
capacity output.
GULF currently has cogeneration agreements for "as available" energy in
effect with two industrial customers. During 1995, GULF purchased 214 million
kilowatt-hours from such companies for $3.6 million.
SAVANNAH currently has cogeneration contracts in effect with four industrial
customers. Under the terms of these contracts, SAVANNAH purchases excess
generation of such companies. During 1995, SAVANNAH purchased 1.5 million
kilowatt-hours from such companies at a cost of $34,000.
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, regulatory, 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.)
I-12
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 or, conversely,
prove to be beneficial. New federal legislation is being discussed, and
legislation allowing customer choice has been introduced in Alabama, Florida and
Georgia. Some form of retail wheeling has been mandated in states such as
California and Michigan. Any form of retail wheeling which may be adopted would
need to address a variety of complex issues, including stranded investments and
the utility's obligation to serve a particular customer or customers. Reference
is made to each registrant's "Management's Discussion and Analysis - Future
Earnings Potential" in Item 7 herein for further discussion of competition.
In order to adapt to the increasingly competitive environment in which they
operate, SOUTHERN and the operating affiliates will evaluate and consider a wide
array of potential business strategies. These may include business combinations
or acquisitions involving other utility or non-utility businesses or properties,
internal restructurings or reorganizations involving SOUTHERN, the operating
affiliates or some combination thereof or dispositions of currently owned
properties or currently operated business units. In addition, SOUTHERN and the
operating affiliates may engage in new business ventures, such as power
marketing, which arise from competitive and regulatory changes in the utility
industry. Pursuit of any of the above strategies, or any combination thereof,
may significantly affect the business operations and financial condition of
SOUTHERN and the operating affiliates.
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.
In June 1995, the Division of Investment Management of the SEC issued a
report on its study of the regulation of public-utility holding companies.
Concluding that significant changes in the current regulatory system are needed,
the report offers various legislative and administrative recommendations for
reform. The legislative option preferred by the Division in the report is repeal
of the Holding Company Act coupled with new provisions for state access to books
and records of holding company system companies and for federal audit authority
and oversight of intrasystem transactions. However, the prospects for further
legislative reform of the Holding Company Act are uncertain at this time.
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 18 existing GEORGIA
generating stations having an aggregate installed capacity of 1,074,696
kilowatts.
I-13
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, totaling 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 on January 1, 2024. The
North Georgia project is operating on an annual license under the same terms and
conditions as its original license. Additionally, the FERC has issued an order
granting a combined, 40-year license for the Yates and Thurlow projects. 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 megawatts.
In August 1995, GEORGIA filed with the FERC its application for a new
license for its Sinclair Project which has 45,000 kilowatts of capacity.
GEORGIA's current license for this project expires September 1, 1997. Certain
environmental issues raised during the licensing process may result in the FERC
including license terms and conditions that could have a substantial effect on
the peaking capability of the project.
In July 1994, flooding of the Flint River in and around Albany, Georgia and
the Flint River Project (5,400 kilowatts of capacity) resulted in substantial
damage to the dam and power house. Under the FERC oversight, GEORGIA has made
repairs to the facilities. In the event GEORGIA elects to file for a new license
for the Flint River Project, it is required to file a notice of intent with the
FERC by September 1996. GEORGIA will then be required to file an application for
a new license for such project by September 1999.
GEORGIA and OPC also have a license, expiring in 2027, for the Rocky
Mountain Plant, a pure pumped storage facility of 847,800 kilowatt capacity
which began commercial operation in 1995. (See Item 2 - PROPERTIES -
"Jointly-Owned Facilities" herein and Note 3 to SOUTHERN's and GEORGIA's
financial statements in Item 8 herein for additional information.)
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 2005-2020
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 5 to GEORGIA's financial statements in Item 8 herein
for information on nuclear decommissioning costs and nuclear insurance.
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
I-14
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 facilities for the years 1996, 1997 and 1998 are
as follows: (in millions)
-------------------------------------------------------
1996 1997 1998
-----------------------------------
ALABAMA $29.8 $31.0 $30.3
GEORGIA 19.4 21.9 25.4
GULF 1.9 5.8 4.1
MISSISSIPPI 1.1 1.5 2.7
SAVANNAH 2.1 0.8 1.3
SEGCO 8.5 1.0 -
-----------------------------------
SOUTHERN
system $62.8 $62.0 $63.8
=======================================================
*The foregoing estimates are included in the current construction programs.
(See Item 1 - BUSINESS - "Construction Programs" herein.)
Additionally, each operating affiliate and SEGCO have incurred costs for
environmental remediation of various sites. Reference is made to each
registrant's "Management's Discussion and Analysis" in Item 7 herein for
information regarding the registrants' environmental remediation efforts. Also,
see Note 3 to SOUTHERN's and GEORGIA's financial statements in Item 8 herein for
information regarding the identification of sites that may require environmental
remediation by GEORGIA and Note 3 to MISSISSIPPI's financial statements in Item
8 herein for information regarding a site that may require environmental
remediation by MISSISSIPPI.
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
including those with special features to encourage off-peak usage. Additionally,
I-15
the operating affiliates are allowed by their respective PSCs to negotiate the
terms and compensation of service to large customers. Such terms and
compensation of service, however, are subject to final PSC approval. With
respect to 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 clause. GULF recovers from retail customers fuel
and net purchased power costs through provisions which are adjusted to reflect
increases or decreases in such costs. 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 fuel costs is based upon a projection for six-months;
any over/under recovery during such period is reflected in a subsequent
six-month period with interest. GULF's recovery of purchased power capacity
costs is based upon an annual projection; any over/under recovery during such
period is reflected in a subsequent annual period with interest. 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.
Rate Proceedings
Reference is made to Note 3 to each registrant's financial statements in Item 8
herein for a discussion of rate matters. For each registrant (except SAVANNAH),
such Note 3 includes a discussion of proceedings initiated 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.
In 1995, GULF filed a petition with the Florida PSC seeking approval for an
optional rate rider, which would be applicable to GULF's largest and most
at-risk customers. For additional information, reference is made to GULF's
"Management's Discussion and Analysis - Future Earnings Potential" in Item 7
herein.
Integrated Resource Planning
In 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 intends 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.
By orders issued in 1992 and by amended orders issued in 1995, the Georgia
PSC approved Integrated Resource Plans for both GEORGIA and SAVANNAH. (See Note
3 to SOUTHERN's and GEORGIA's financial statements in Item 8 herein for
information regarding GEORGIA's demand-side option programs and Note 3 to
SAVANNAH's financial statements for information regarding SAVANNAH's demand-side
option programs.)
The Florida PSC has set energy conservation goals for GULF, which became
effective in 1995, that require programs to reduce 154 megawatts of summer peak
demand and 65,000 kilowatt-hours of sales by the year 2004. For additional
information, reference is made to GULF's "Management's Discussion and Analysis -
Future Earnings Potential" in Item 7 herein.
Environmental Cost Recovery Plans
GULF and MISSISSIPPI both have retail rate mechanisms that provide for recovery
of environmental compliance costs. For a description of these plans, see Note 3
to GULF's and MISSISSIPPI's financial statements in Item 8 herein.
I-16
Employee Relations
The companies of the SOUTHERN system had a total of 31,882 employees on their
payrolls at December 31, 1995.
-------------------------------------------------
Employees
at
December 31, 1995
-----------------------
ALABAMA 7,261
GEORGIA 11,061
GULF 1,501
MISSISSIPPI 1,421
SAVANNAH 584
SCS 3,207
Southern Nuclear 1,298
Communications 78
Southern Development 41
SEI* 5,430
-------------------------------------------------
Total 31,882
=================================================
*Includes 4,977 employees on international payrolls.
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, 1998. 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, and is currently in
negotiations with respect to such agreement. GEORGIA also has a contract with
the United Plant Guard Workers of America with respect to Plant Hatch which
extends through September 30, 1998.
GULF has an agreement with the IBEW on a three-year contract extending to
August 15, 1998.
In July 1995, MISSISSIPPI and the IBEW began negotiating changes to the
contract which extended to August 16, 1995. Due to ongoing negotiations, the
parties agreed to extend the contract beyond August 16, 1995. Discussions
continued into 1996, with union ratification in March.
Southern Nuclear has an agreement with the IBEW on a three-year contract
extending to August 15, 1998. 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 16, 1996 and
December 1, 1996, respectively. SAVANNAH is currently in negotiations with the
IBEW.
SEI has agreements with local unions of the IBEW and the United Paperworkers
International Union which covers employees of Mobile Energy. These agreements
extend to May 31, 1997.
I-17
Item 2. PROPERTIES
Electric Properties
The operating affiliates and SEGCO, at December 31, 1995, operated 33
hydroelectric generating stations, 32 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 (1)
------------------------------------------------------------
(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 (2)
Gaston Unit 5 Wilsonville, AL 880,000
Miller Birmingham, AL 2,532,288 (3)
---------
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 750,924 (4)
Wansley Carrollton, GA 925,550 (5)
Yates Newnan, GA 1,250,000
---------
GEORGIA Total 9,541,174
---------
Crist Pensacola, FL 1,045,000
Lansing Smith Panama City, FL 305,000
Scholz Chattahoochee, FL 80,000
Daniel Pascagoula, MS 500,000 (6)
Scherer Unit 3 Macon, GA 204,500 (4)
---------
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 (6)
Greene County Demopolis, AL 200,000 (2)
-----------
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 (7)
------------
Total Fossil Steam 21,700,243
------------
Nuclear Steam
Farley Dothan, AL
(ALABAMA) 1,720,000
------------
Hatch Baxley, GA 816,630 (8)
Vogtle Augusta, GA 1,060,240 (9)
------------
GEORGIA Total 1,876,870
------------
Total Nuclear Steam 3,596,870
------------
Combustion Turbines
Greene County Demopolis, AL
(ALABAMA) 400,000
-----------
Arkwright Macon, GA 30,580
Atkinson Atlanta, GA 78,720
Bowen Cartersville, GA 39,400
McDonough Atlanta, GA 78,800
McIntosh
Units 1,2,3,4,7,8 Effingham County, GA 480,000
McManus Brunswick, GA 481,700
Mitchell Albany, GA 118,200
Robins Warner Robins, GA 160,000
Wilson Augusta, GA 354,100
Wansley Carrollton, GA 26,322 (5)
-----------
GEORGIA Total 1,847,822
-----------
Lansing Smith
Unit A (GULF) Panama City, FL 39,400
Chevron Cogenerating
Station Pascagoula, MS 147,292 (10)
Sweatt Meridian, MS 39,400
Watson Gulfport, MS 39,360
-----------
MISSISSIPPI Total 226,052
-----------
Boulevard Savannah, GA 59,100
Kraft Port Wentworth, GA 22,000
McIntosh
Units 5&6 Effingham County, GA 160,000
-----------
SAVANNAH Total 241,100
-----------
----------------------------------------------------------------
I-18
----------------------------------------------------------------
Nameplate
Generating Station Location Capacity
----------------------------------------------------------------
(Kilowatts)
Gaston (SEGCO) Wilsonville, AL 19,680 (7)
-----------
Total Combustion Turbines 2,774,054
-----------
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
Rocky Mountain Rome, GA 215,256 (11)
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 1,077,736
-----------
Total Hydroelectric Facilities 2,660,461
-----------
Total Generating Capacity 30,731,628
===========
---------------------------------------------------------------
Notes:
(1) For additional information regarding facilities jointly-owned with
non-affiliated parties, see Item 2 - PROPERTIES - "Jointly-Owned
Facilities" herein.
(2) Owned by ALABAMA and MISSISSIPPI as tenants in common in the
proportions of 60% and 40%, respectively.
(3) Excludes the capacity owned by AEC.
(4) Capacity shown for GEORGIA is 8.4% of Units 1 and 2 and 75% of Unit 3.
Capacity shown for GULF is 25% of Unit 3.
(5) Capacity shown is GEORGIA's portion (53.5%) of total plant capacity.
(6) Represents 50% of the plant which is owned as tenants in common by
GULF and MISSISSIPPI.
(7) SEGCO is jointly-owned by ALABAMA and GEORGIA. (See Item 1 - BUSINESS
herein.)
(8) Capacity shown is GEORGIA's portion (50.1%) of total plant capacity.
(9) Capacity shown is GEORGIA's portion (45.7%) of total plant capacity.
(10) Generation is dedicated to a single industrial customer.
(11) Capacity shown is GEORGIA's portion (25.4%) of total plant capacity.
OPC operates the plant.
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 27,419,700 kilowatts
and occurred in August 1995. This amount excludes demand served by capacity
retained by MEAG and Dalton and excludes demand associated with power purchased
from OPC and SEPA by its preference customers. At that time, 29,596,100
kilowatts were supplied by SOUTHERN system generation and 2,176,400 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 9.4%. For
additional information on peak demands, reference is made to Item 6 SELECTED
FINANCIAL DATA herein.
I-19
ALABAMA and GEORGIA will incur significant costs in decommissioning their
nuclear units at the end of their useful lives. (See Item 1 - BUSINESS
"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 interests in or operates
independent power production facilities and foreign utility companies. The
generating capacity of these utilities (or facilities) at December 31, 1995, was
as follows:
I-20
Jointly-Owned Facilities
ALABAMA and GEORGIA have sold and GEORGIA has purchased undivided interests in
certain generating plants and other related facilities to or from non-affiliated
parties. The percentages of ownership resulting from these transactions are as
follows:
ALABAMA and GEORGIA have contracted to operate and maintain the respective
units in which each has an interest (other than Rocky Mountain and Intercession
City, as described below) as agent for the joint owners.
In connection with the joint ownership arrangements for Plant Vogtle,
GEORGIA has remaining commitments to purchase declining fractions of MEAG's
capacity and energy until December 1996 for Unit 2 and, with regard to a portion
of a 5% interest 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 from non-affiliates in GEORGIA's Statements of
Income in Item 8 herein.
In December 1988, GEORGIA and OPC entered into a joint ownership agreement
for the Rocky Mountain plant under which GEORGIA agreed to retain its present
investment in the project and OPC agreed to finance, complete and operate the
facility. The plant went into commercial operation in 1995. GEORGIA's net
investment in the plant is approximately $190 million, and GEORGIA's ownership
is 25.4 percent. Reference is made to Note 3 to SOUTHERN's and GEORGIA's
financial statements in Item 8 herein for additional information regarding the
Rocky Mountain plant.
In 1994, GEORGIA and FPC entered into a joint ownership agreement regarding
the Intercession City combustion turbine unit. The unit is scheduled to be in
commercial operation by the end of 1996, and will be constructed, operated, and
maintained by FPC. GEORGIA will have a one-third interest in the 150-megawatt
unit, with use of 100% of the capacity from June through September. FPC will
have the capacity the remainder of the year. GEORGIA's investment in the unit at
completion is estimated to be $14 million. Also, GEORGIA entered into a separate
four-year purchase power contract with FPC. Beginning in 1996, GEORGIA will
purchase 400 megawatts of capacity. In 1998, this amount will decline to 200
megawatts for the remaining two years.
Sale of Property
Reference is made to Note 6 to SOUTHERN's and GEORGIA's financial statements in
Item 8 herein for information regarding the sale completed in 1995 of GEORGIA's
remaining ownership interest in Plant Scherer Unit 4.
I-21
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, 1991 to December 31, 1995, the operating
affiliates, SEGCO, SCS, Southern Nuclear, Communications and SEI recorded gross
property additions and retirements as follows:
==================================================
Gross Property
Additions Retirements
--------------- -------------
(in millions)
ALABAMA (1) $2,290 $ 357
GEORGIA (2) 2,850 1,864
GULF 350 125
MISSISSIPPI 433 82
SAVANNAH 179 16
SEGCO 60 14
SCS 111 122
Southern Nuclear 17 4
Communications 162 -
SEI 154 6
--------------------------------------------------
SOUTHERN system $6,606 $2,590
==================================================
Notes:
(1) Includes approximately $62 million attributable to sale of 8.2%
interest in Plant Miller Units 1 and 2 to AEC in 1992.
(2) Includes approximately $691 million attributable to 1991 through 1995
sales of Plant Scherer Unit 4 to FP&L and JEA.
I-22
Item 3. LEGAL PROCEEDINGS
(1) Stepak v. certain SOUTHERN officials
(U.S. District Court for the Southern District of Georgia)
Reference is made to Note 3 to SOUTHERN's financial statements in Item 8
herein under the caption "Stockholder Suit."
(2) SOUTHERN and Subsidiaries v. Commissioner of the IRS
(U.S. Tax Court)
In June 1994, a tax deficiency notice was received from the IRS for the
years 1984 through 1987 with regard to the tax accounting by GEORGIA for
the sale in 1984 of an interest in Plant Vogtle and related capacity and
energy buyback commitments. The potential tax deficiency and interest
arising from this issue currently amount to approximately $25 million and
$31 million, respectively. The tax deficiency relates to a timing issue
as to when taxes are paid; therefore, only the interest portion could
affect future income. Management believes that the IRS position is
incorrect, and GEORGIA has filed a petition with the U.S. Tax Court
challenging the IRS's position. In order to minimize additional interest
charges should the IRS's position prevail, GEORGIA made a payment to the
IRS related to the potential tax deficiency in September 1994.
(3) ALABAMA, GEORGIA and MISSISSIPPI v. TVA, et al.
(U.S. District Court for the Northern District of Alabama)
On January 12, 1996, ALABAMA, GEORGIA and MISSISSIPPI filed an action
seeking to enjoin the TVA from violating a 1959 act which prohibits the
TVA from selling power outside the area that was being served by it in
1957. LG&E Power Marketing, Inc. (LPM), also a defendant, has entered
into an agreement with TVA for the sale of power purchased by LPM from
TVA to organizations outside the TVA's statutorily defined service
territory, which the plaintiffs contend is in violation of the 1959 act.
(4) GEORGIA has been designated as a potentially responsible party under the
Comprehensive Environmental Response, Compensation and Liability Act with
respect to a site in Brunswick, Georgia.
Reference is made to Note 3 to SOUTHERN's and GEORGIA's financial
statements in Item 8 herein under the captions "Georgia Power Potentially
Responsible Party Status" and "Certain Environmental Contingencies,"
respectively.
See Item 1 - BUSINESS - "Construction Programs," "Fuel Supply," "Regulation
- Federal Power Act" and "Rate Matters" as well as Note 3 to each registrant's
financial statements in Item 8 herein for a description of certain other
administrative and legal proceedings discussed therein.
Additionally, each of the operating affiliates, SEI, SCS, Southern Nuclear,
Southern Development and Communications 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.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
I-23
EXECUTIVE OFFICERS OF SOUTHERN
(Identification of executive officers of SOUTHERN is inserted in Part I in
accordance with Regulation S-K, Item 401(b), Instruction 3.) The ages of the
officers set forth below are as of December 31, 1995.
A. W. Dahlberg
Chairman, President and Chief Executive Officer
Age 55
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. He was elected
Chairman and Chief Executive Officer effective March 1995.
Paul J. DeNicola
Executive Vice President and Director
Age 47
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 51
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 Chief Executive Officer of GEORGIA effective January 1994.
Elmer B. Harris
Executive Vice President and Director
Age 56
Elected in 1989; President and Chief Executive Officer of ALABAMA since 1989
and, beginning 1991, Executive Vice President of SOUTHERN.
David M. Ratcliffe
Senior Vice President
Age 47
Elected in 1995; President and Chief Executive Officer of MISSISSIPPI from 1991
to 1995. He also serves as Executive Vice President of SCS beginning in 1995 and
previously held that position from 1989 to 1991.
W. L. Westbrook
Financial Vice President, Chief Financial Officer and Treasurer
Age 56
Elected in 1986; responsible primarily for all aspects of financing for
SOUTHERN. He has served as Executive Vice President of SCS since 1986.
Thomas G. Boren
Vice President
Age 46
Elected in 1995; President and Chief Executive Officer of SEI since 1992. He
previously served as Senior Vice President of GEORGIA from 1989 to 1992.
Bill M. Guthrie
Vice President
Age 62
Elected in 1991; serves as Chief Production Officer for the SOUTHERN system.
Senior Executive Vice President of SCS effective January 1994 and Executive Vice
President of ALABAMA since 1988. He also serves as Executive Vice President of
GEORGIA and Vice President of GULF, MISSISSIPPI and SAVANNAH.
W. G. Hairston, III
Age 51
President and Chief Executive Officer of Southern Nuclear since 1993. He has
also served as Executive Vice President of GEORGIA since 1989.
Each of the above is currently an officer of SOUTHERN, except Mr. Hairston,
serving a term running from the last annual meeting of the directors (July 17,
1995) for one year until the next annual meeting or until his successor is
elected and qualified.
I-24
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
----------- --------
1995
First Quarter $21-1/2 $19-3/8
Second Quarter 22-7/8 20-1/8
Third Quarter 24 21-1/8
Fourth Quarter 25 22-3/4
1994
First Quarter $22 $18-1/2
Second Quarter 20-1/2 17-3/4
Third Quarter 20 17
Fourth Quarter 21 18-1/4
-------------------------------------------
There is no market for the other registrants' common stock, all of
which is owned by SOUTHERN. On February 29, 1996, the closing price
of SOUTHERN's common stock was $23-7/8.
(b) Number of SOUTHERN's common stockholders at December 31, 1995:
225,739
Each of the other registrants have one common stockholder, SOUTHERN.
(c) Dividends on each registrant's common stock are payable at the
discretion of their respective board of directors. The dividends on
common stock paid and/or declared by SOUTHERN and the operating
affiliates to their stockholder(s) for the past two years were as
follows: (in thousands)
----------------------------------------------------
Registrant Quarter 1995 1994
----------------------------------------------------
SOUTHERN First $201,866 $191,262
Second 203,060 191,262
Third 203,061 191,475
Fourth 203,178 192,758
ALABAMA First 71,900 66,500
Second 69,500 67,000
Third 69,300 66,900
Fourth 74,300 67,600
GEORGIA First 113,900 106,600
Second 110,200 107,200
Third 109,700 107,200
Fourth 117,700 108,300
GULF First 11,700 10,900
Second 11,300 11,000
Third 11,300 11,000
Fourth 12,100 11,100
MISSISSIPPI First 9,900 8,500
Second 9,600 8,500
Third 9,600 8,500
Fourth 10,300 8,600
SAVANNAH First 4,400 4,100
Second 4,300 4,100
Third 4,300 4,100
Fourth 4,600 4,000
----------------------------------------------------
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
The dividend paid per share by SOUTHERN was 29.5(cent) for each quarter of
1994 and 30.5(cent) for each quarter of 1995. The dividend paid on SOUTHERN's
common stock for the first quarter of 1996 was raised to 31.5(cent) per share.
The amount of dividends on their common stock 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, 1995, were as follows:
---------------------------------------------
Retained Restricted
Earnings Amount
--------------------------
(in millions)
ALABAMA $1,161 $ 807
GEORGIA 1,570 897
GULF 180 101
MISSISSIPPI 157 118
SAVANNAH 105 62
Consolidated 3,483 1,990
---------------------------------------------
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-39
through II-50.
ALABAMA. Reference is made to information under the heading "Selected
Financial and Operating Data," contained herein at pages II-79 through II-92.
GEORGIA. Reference is made to information under the heading "Selected
Financial and Operating Data," contained herein at pages II-126 through II-140.
GULF. Reference is made to information under the heading "Selected
Financial and Operating Data," contained herein at pages II-170 through II-183.
MISSISSIPPI. Reference is made to information under the heading "Selected
Financial and Operating Data," contained herein at pages II-210 through II-223.
SAVANNAH. Reference is made to information under the heading "Selected
Financial and Operating Data," contained herein at pages II-246 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-54 through II-60.
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-96 through II-103.
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-144 through II-151.
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-187 through II-193.
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-227 through II-232.
II-2
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO 1995 FINANCIAL STATEMENTS
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
II-4
THE SOUTHERN COMPANY
AND SUBSIDIARY COMPANIES
FINANCIAL SECTION
II-5
MANAGEMENT'S REPORT
The Southern Company and Subsidiary Companies 1995 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 five 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 subsidiary companies in
conformity with generally accepted accounting principles.
/s/ A. W. Dahlberg
A. W. Dahlberg
Chairman, President, and Chief Executive Officer
/s/ W. L. Westbrook
W. L. Westbrook
Financial Vice President, Chief Financial Officer, and Treasurer
February 21, 1996
II-6
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 subsidiary companies as of December 31, 1995 and 1994, 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, 1995. These
financial statements are the responsibility of the company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements (pages II-16 through II-38)
referred to above present fairly, in all material respects, the financial
position of The Southern Company and subsidiary companies as of December 31,
1995 and 1994, and the results of their operations and their cash flows for the
periods stated, in conformity with generally accepted accounting principles.
/s/ Arthur Andersen LLP
Atlanta, Georgia
February 21, 1996
II-7
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
The Southern Company and Subsidiary Companies 1995 Annual Report
RESULTS OF OPERATIONS
Earnings and Dividends
This year's financial performance continues to support The Southern Company's
goal to become America's Best Diversified Utility. The core business of selling
electricity in the Southeast remained strong, while the non-core business
expanded both internationally and domestically. The financial results for 1995
demonstrate a very successful year with several records being set. Net income of
$1.1 billion and earnings per share of $1.66 for 1995 both established record
highs. Southern Company common stock reached an all-time high closing price of
24 5/8, surpassing the previous record of 23 3/8 set in 1993. Continued cost
controls and the strong demand for electricity were the dominant forces that
favorably affected earnings in 1995.
Costs related to the work force reduction programs implemented in 1995 and
1994 decreased earnings by 2 cents and 9 cents per share, respectively. These
costs are expected to be recovered through future savings in approximately two
years following each program's implementation. Additional non-operating or
non-recurring items affected earnings in 1995 and 1994. After excluding these
items in both years, 1995 earnings from operations were $1.1 billion -- or $1.71
per share -- an increase of $108 million compared with 1994. The non-operating
items that affected earnings were as follows:
Consolidated Earnings
Net Income Per Share
--------------- ----------------
1995 1994 1995 1994
--------------- ----------------
(in millions)
Earnings as reported $1,103 $ 989 $1.66 $1.52
---------------------------------------------------------------------
Work force reduction
programs 17 61 .02 .09
Sale of facilities (12) (28) (.02) (.04)
Demand-side costs 17 - .03 -
Environmental
cleanup 5 5 .01 .01
Miscellaneous 5 - .01 -
---------------------------------------------------------------------
Total non-operating 32 38 .05 .06
---------------------------------------------------------------------
Earnings from
operations $1,135 $1,027 $1.71 $1.58
=====================================================================
Amount and
percent change $108 10.6% $0.13 8.2%
---------------------------------------------------------------------
In 1995, non-operating items -- both positive and negative -- had an impact
on earnings, which resulted in a net reduction of $32 million. These items were:
(1) Costs associated with work force reduction programs implemented primarily in
1995 decreased earnings. (2) The last in a series of four separate transactions
to sell Plant Scherer Unit 4 to two Florida utilities increased earnings. (3)
Georgia Power's demand-side conservation costs that were not recovered from
customers decreased earnings. (4) Environmental-cleanup costs decreased
earnings.
In 1994, earnings were $989 million or $1.52 per share -- down 5 cents from
the per share amount reported in 1993. Earnings in 1994 were significantly
affected by costs related to work force reduction programs and milder than
normal temperatures.
Dividends paid on common stock during 1995 were $1.22 per share or 30 1/2
cents per quarter. During 1994 and 1993, dividends paid per share were $1.18 and
$1.14, respectively. In January 1996, The Southern Company board of directors
raised the quarterly dividend to 31 1/2 cents per share or an annual rate of
$1.26 per share.
Acquisitions
Southern Electric International (Southern Electric) owns and manages
international and domestic non-core businesses for The Southern Company.
Southern Electric acquired several businesses in late 1994 and in 1995. These
businesses have been included in the consolidated statements of income since the
date of acquisition and not reflected in prior periods. These acquisitions
account for a significant portion of the amount of change in revenues and
certain expenses from year to year. Therefore to facilitate discussing the
results of operations, Southern Electric's 1995 variances are shown separately.
These variances are predominantly acquisition related and require no further
explanation.
II-8
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
The Southern Company and Subsidiary Companies 1995 Annual Report
Revenues
Operating revenues increased in 1995 and decreased in 1994 as a result of the
following factors:
Increase (Decrease)
From Prior Year
------------------------------
1995 1994 1993
------------------------------
Retail -- (in millions)
Change in base rates $ - $ 3 $ 3
Sales growth 177 153 104
Weather 143 (177) 198
Fuel cost recovery and
other 134 (107) 199
-------------------------------------------------------------
Total retail 454 (128) 504
-------------------------------------------------------------
Sales for resale --
Within service area 39 (87) 38
Outside service area (90) (108) (184)
-------------------------------------------------------------
Total sales for resale (51) (195) (146)
Southern Electric 458 131 54
Other operating revenues 22 - 4
-------------------------------------------------------------
Total operating revenues $883 $(192) $ 416
=============================================================
Percent change 10.6% (2.3)% 5.2%
-------------------------------------------------------------
Retail revenues of $7.6 billion in 1995 increased 6.4 percent from last
year, compared with a decrease of 1.8 percent in 1994. 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 $399 million in 1995,
up 11 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 $360 million in
1994, down 19 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.
1995 1994 1993
---------------------------------
(in millions)
Capacity $237 $276 $350
Energy 151 176 230
------------------------------------------------------
Total $388 $452 $580
======================================================
Capacity revenues decreased in 1995 and 1994 because the amount of capacity
under contract declined, as scheduled, by some 100 megawatts and 400 megawatts,
respectively. Additional declines in capacity are not scheduled until after
1999.
Changes in revenues are influenced heavily by the amount of energy sold each
year. Kilowatt-hour sales for 1995 and the percent change by year were as
follows:
Percent Change
----------------------------
(billions of Amount
kilowatt-hours) 1995 1995 1994 1993
------------- ----------------------------
Residential 39.1 9.2% (2.6)% 9.5%
Commercial 35.9 5.5 3.8 5.9
Industrial 51.7 2.7 3.2 1.9
Other 0.9 2.1 3.8 4.6
-----------
Total retail 127.6 5.4 1.6 5.3
Sales for resale --
Within service area 9.5 16.2 (38.5) 9.5
Outside service area 9.1 (15.1) (13.5) (25.2)
-----------
Total 146.2 4.4 (3.4) 2.1
===================================================================
The rate of increase in 1995 retail energy sales was fostered by the impact
of weather. Residential energy sales surged upward as a result of
hotter-than-normal summer weather in 1995, compared with the extremely mild
summer of 1994. Commercial and industrial sales continue to show moderate gains
in excess of the national average. This reflects the strength of business and
economic conditions in The Southern Company's service area. Energy sales to
retail customers are projected to increase at an average annual rate of 1.9
percent during the period 1996 through 2006.
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 continued to decrease
in 1995 and 1994, primarily as a result of the scheduled decline in megawatts of
capacity under contract.
II-9
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
The Southern Company and Subsidiary Companies 1995 Annual Report
Expenses
Total operating expenses of $7.3 billion for 1995 increased $712 million
compared with the prior year. Core business expenses increased $322 million, and
Southern Electric comprised the remainder. The costs to produce and deliver
electricity for the core business in 1995 increased by $120 million to meet
higher energy demands. Depreciation expenses and property taxes increased by $78
million as a result of additional utility plant being placed into service. The
amortization of deferred expenses related to Plant Vogtle increased by $49
million in 1995 when compared with the prior year. For additional information
concerning Plant Vogtle, see Note 1 to the financial statements under "Plant
Vogtle Phase-In Plans."
In 1994, operating expenses of $6.6 billion declined 2.1 percent compared
with 1993. The decrease was attributable to less energy being sold. Total
production costs were down $297 million. However, costs related to the 1994 work
force reduction programs increased operating expenses by $100 million. Also, a
$39 million increase in the amortization of deferred Plant Vogtle expenses
compared with the amount in 1993 contributed to offset the decrease in operating
expenses.
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 -- within the core business service
area -- were as follows:
1995 1994 1993
---------------------------
Total generation
(billions of kilowatt-hours) 147 142 144
Sources of generation
(percent) --
Coal 77 75 78
Nuclear 17 19 17
Hydro 4 5 4
Oil and gas 2 1 1
Average cost of fuel per net
kilowatt-hour generated
(cents) --
Coal 1.73 1.80 1.90
Nuclear 0.56 0.56 0.54
Oil and gas 3.37 3.99 4.34
Total 1.53 1.56 1.67
--------------------------------------------------------------
Fuel and purchased power costs of $2.6 billion in 1995 increased $282 million
compared with 1994. Core business increased $73 million and Southern Electric
increased $209 million. The operating companies' customer demand for electricity
rose by 4.7 billion kilowatt-hours more than in 1994. The additional cost to
meet the demand was offset slightly by a lower average cost of fuel per net
kilowatt-hour generated. Fuel and purchased power expenses of $2.3 billion in
1994 decreased 10 percent compared with the prior year because of lower energy
demands and a lower average cost of fuel per net kilowatt-hour generated.
For 1995, income taxes increased $84 million compared with the prior year.
Core business income taxes increased $65 million, and Southern Electric
accounted for the remainder. The increase was attributable to additional taxable
income from operations. For 1994, income taxes rose $8 million or 1.3 percent
above the amount reported for 1993. The increase resulted primarily from the
sale of interests in generating plant facilities.
Total gross interest charges and preferred stock dividends increased $39
million from amounts reported in the previous year. These costs for core
business continued to decline by $12 million, but Southern Electric interest
charges increased by $51 million. The decline is attributable to lower interest
rates and continued refinancing activities in 1995. In 1994, these costs were
$765 million -- down $66 million or 8.0 percent. As a result of favorable market
conditions, $1.1 billion in 1995, $1.0 billion in 1994, and $3.0 billion in 1993
of senior securities were issued for the primary purpose of retiring higher-cost
securities.
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.
II-10
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
The Southern Company and Subsidiary Companies 1995 Annual Report
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 energy sales growth to a less regulated more
competitive environment, with non-core business becoming more significant.
Work force reduction programs were implemented in 1995 and 1994 that reduced
earnings by $17 million and $61 million, respectively. These actions will assist
in efforts to control growth in future operating expenses.
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 weather, competition, changes in contracts with neighboring utilities,
energy conservation practiced by customers, the elasticity of demand, and the
rate of economic growth in the company's service area. However, the Energy
Policy Act of 1992 (Energy Act) is beginning to have a dramatic 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 Southern Company is positioning the business to meet the
challenge of this major change in the traditional practice 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. This enhances 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. Also, electricity sales for resale rates are
being driven down by wholesale transmission access and numerous potential new
energy suppliers, including power marketers and brokers. The Southern Company is
aggressively working to maintain and expand its share of wholesale sales in the
Southeastern power markets.
Although the Energy Act does not require transmission access to retail
customers, retail wheeling initiatives are rapidly evolving and becoming very
prominent issues in several states. New federal legislation is being discussed,
and legislation allowing customer choice has already been introduced in Florida
and Georgia. In order to address these initiatives, numerous questions must be
resolved, with the most complex ones relating to transmission pricing and
recovery of stranded investments. As the initiatives become a reality, the
structure of the utility industry could radically change. Therefore, unless The
Southern Company remains a low-cost producer and provides quality service, the
company's retail energy sales growth could be limited, and this could
significantly erode earnings. Conversely, being the low-cost producer could
provide significant opportunities to increase market share and profitability by
seeking new markets that evolve with the changing regulation.
The Energy Act amended the Public Utility Holding Company Act of 1935
(PUHCA). The amendment allows holding companies to form exempt wholesale
generators and foreign utility companies to sell power largely free of
regulation under PUHCA. These 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 -- founded in 1981 -- is focusing on
international and domestic cogeneration, the independent power market, and the
privatization of generating and distribution facilities in the international
market. In late 1995, South Western Electricity (SWEB) was acquired for
approximately $1.8 billion. For additional information on this acquisition, see
Note 14 to the financial statements. This British electric distribution utility
and other investments made by Southern Electric should increase the
opportunities for future earnings growth. At December 31, 1995, Southern
Electric's total assets amounted to $5.0 billion.
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 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. Besides promoting energy efficiency,
another benefit of these programs could be the ability to defer the need to
construct costly baseload generating facilities further into the future.
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 retail and wholesale regulatory matters.
II-11
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
The Southern Company and Subsidiary Companies 1995 Annual Report
The staff of the Securities and Exchange Commission has questioned certain of
the current accounting practices of the electric utility industry -- including
The Southern Company's -- regarding the recognition, measurement, and
classification of decommissioning costs for nuclear generating facilities in the
financial statements. In response to these questions, the Financial Accounting
Standards Board (FASB) has decided to review the accounting for liabilities
related to closure and removal of long-lived assets, including nuclear
decommissioning. If the FASB issues new accounting rules, the estimated costs of
closing and removing The Southern Company's nuclear and other facilities may be
required to be recorded as liabilities in the Consolidated Balance Sheets. Also,
the annual provisions for such costs could increase. Because of the company's
current ability to recover closure and removal costs through rates, these
changes would not have a significant adverse effect on results of operations.
See Note 1 to the financial statements under "Depreciation and Nuclear
Decommissioning" for additional information.
The Southern Company is involved in various matters being litigated. See Note
3 to the financial statements for information regarding material issues that
could possibly affect future earnings.
Compliance costs related to the Clean Air Act Amendments of 1990 (Clean Air
Act) could affect earnings if such costs are not fully recovered. The Clean Air
Act and other important environmental items are discussed later under
"Environmental Matters."
The operating companies are subject to the provisions of FASB Statement No.
71, Accounting for the Effects of Certain Types of Regulation. In the event that
a portion of a company's operations is no longer subject to these provisions,
the company would be required to write off related regulatory assets and
liabilities, and determine if any other assets have been impaired. See Note 1 to
the financial statements under "Regulatory Assets and Liabilities" for
additional information.
New Accounting Standards
The FASB has issued Statement No. 121, Accounting for the Impairment of
Long-Lived Assets and Long-Lived Assets to be Disposed of. This statement
requires that long-lived assets be reviewed for impairment whenever events or
changes in circumstances indicate that the carrying amount for an asset may not
be recoverable. This statement also imposes stricter criteria for regulatory
assets by requiring that such assets be probable of future recovery at each
balance sheet date. The Southern Company adopted the new rules January 1, 1996,
with no material effect on the financial statements. However, this conclusion
may change in the future as competitive factors influence wholesale and retail
pricing in the utility industry.
The FASB has issued Statement No. 123, Accounting for Stock-Based
Compensation. This statement establishes a fair value based method of accounting
for employee stock options. This method provides for a compensation cost to be
charged to results of operations at the grant date. However, the statement
allows companies to continue following the accounting prescribed by Accounting
Principles Bulletin Opinion No. 25. Opinion No. 25 generally requires
compensation cost to be recognized only for the excess of the quoted market
price at the grant date over the price that an employee must pay to acquire the
stock. The Southern Company has elected to continue with Opinion No. 25.
FINANCIAL CONDITION
Overview
The Southern Company's financial condition continues to remain strong. Both
earnings per share and market price per share set new record levels in 1995.
Earnings from operations continued to increase in 1995 and exceeded $1.1
billion. Based on this performance, in January 1996, The Southern Company board
of directors increased the common stock dividend for the fifth consecutive year.
In 1995, Southern Electric acquired SWEB for approximately $1.8 billion. For
more information on the purchase of this British electric distribution utility,
see Note 14 to the financial statements.
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 1992 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.
The Southern Company has a policy that financial derivatives are to be used
only to mitigate business risks and not for speculative purposes. Derivatives
have been used by the company on a very limited basis. At December 31, 1995, the
credit risk for derivatives outstanding was not material. See Note 1 to the
financial statements under "Financial Instruments" for additional information.
II-12
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
The Southern Company and Subsidiary Companies 1995 Annual Report
Capital Structure
The Southern Company achieved a ratio of common equity to total capitalization
-- including short-term debt -- of 42.4 percent in 1995, compared with 44.4
percent in 1994, and 43.8 percent in 1993. The company's goal is to maintain
the common equity ratio generally within a range of 40 percent to 45 percent.
During 1995, the subsidiary companies sold $375 million of first mortgage
bonds and, through public authorities, $732 million of pollution control revenue
bonds. The companies continued to reduce financing costs by retiring higher-cost
bonds. Retirements, including maturities, of bonds totaled $1.3 billion during
1995, $973 million during 1994, and $2.5 billion during 1993. Retirements of
preferred stock totaled $1 million a year during 1995 and 1994 and $516 million
during 1993. As a result, the composite interest rate on long-term debt
decreased from 8.2 percent at December 31, 1992, to 7.1 percent at December 31,
1995. During this same period, the composite dividend rate on preferred stock
declined from 7.3 percent to 6.5 percent.
In 1995, The Southern Company raised $174 million from the issuance of new
common stock under the company's various stock plans. An additional $103 million
of new common stock was issued through a public offering in early 1995. At the
close of 1995, the company's common stock had a market value of 24 5/8 per
share, compared with a book value of $13.10 per share. The market-to-book value
ratio was 188 percent at the end of 1995, compared with 160 percent at year-end
1994 and 184 percent at year-end 1993.
Capital Requirements for Construction
The construction program of The Southern Company is budgeted at $1.5 billion for
1996, $1.4 billion for 1997, and $1.3 billion for 1998. The total is $4.2
billion for the three years. Actual construction costs may vary from this
estimate because of changes in such factors as: business conditions;
environmental regulations; nuclear plant regulations; load projections;
the cost and efficiency of construction labor, equipment, and materials; and the
cost of capital. In addition, there can be no assurance that costs related to
capital expenditures for the operating companies will be fully recovered.
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 service
area, the construction of combustion turbine peaking units of approximately 600
megawatts of capacity is planned to be completed by 1998 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 $996
million will be required by the end of 1998 for present sinking fund
requirements and maturities of long-term debt. Also, the subsidiaries will
continue to retire higher-cost debt and preferred stock and replace these
obligations with lower-cost capital if market conditions permit.
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 -- has significantly
impacted The Southern Company. Specific reductions in sulfur dioxide and
nitrogen oxide emissions from fossil-fired generating plants are required in two
phases. Phase I compliance began in 1995 and initially affected 28 generating
units of The Southern Company. As a result of the company's compliance strategy,
an additional 22 generating units were brought into compliance with Phase I
requirements. Phase II compliance is required in 2000, and all fossil-fired
generating plants will be affected.
In 1995, the Environmental Protection Agency (EPA) began issuing annual
sulfur dioxide emission allowances through the allowance trading program. An
emission allowance is the authority to emit one ton of sulfur dioxide during a
calendar year. The method for issuing 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 Southern Company's sulfur dioxide compliance strategy is
designed to use allowances as a compliance option.
II-13
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
The Southern Company and Subsidiary Companies 1995 Annual Report
The Southern Company achieved Phase I sulfur dioxide compliance at the
affected plants by switching to low-sulfur coal, which required some equipment
upgrades. This compliance strategy resulted in unused emission allowances being
banked for later use. Compliance with nitrogen oxide emission limits was
achieved by the installation of new control equipment at 22 of the original 28
affected generating units. Construction expenditures for Phase I compliance
totaled approximately $320 million through 1995.
For Phase II 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 units as required to meet Phase II limits.
Therefore, during the period 1996 to 2000, current compliance strategy could
require total estimated construction expenditures of approximately $150 million.
However, the full impact of Phase II compliance cannot now be determined with
certainty, pending the continuing 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 1 percent in revenue requirements from
customers could be necessary to fully recover the cost of compliance for both
Phase I and Phase II of Title IV of the Clean Air Act. Compliance costs include
construction expenditures, increased costs for switching to low-sulfur coal, and
costs related to emission allowances.
A significant portion of costs related to the acid rain provision of the
Clean Air Act is expected to be recovered through existing ratemaking
provisions. However, 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
-- affecting sources of nitrogen oxides and volatile organic compounds -- to
achieve attainment by 1999. As the required first step, the state 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
required nitrogen oxide controls, above Title IV requirements, on some Georgia
Power plants. The EPA along with 37 states is conducting studies to evaluate the
benefits of regional controls in meeting the ozone standards. Final attainment
rules, based on modeling studies, could require installation of additional
controls for nitrogen oxide emissions to meet the 1999 deadline in Atlanta or as
part of any regional controls if enacted. A decision on new requirements is
expected in 1997. Compliance with any new rules could result in significant
additional costs. The actual 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 EPA is scheduled to submit a
report to Congress on the results of this study during 1996. The report will
include 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 is evaluating the need to revise the ambient air quality standards
for particulate matter 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 1996, the EPA may 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 subsidiaries could incur substantial costs to
clean up properties. The subsidiaries conduct studies to determine the extent of
II-14
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
The Southern Company and Subsidiary Companies 1995 Annual Report
any required cleanup costs and have recognized in their respective financial
statements costs to clean up known sites. These costs for The Southern Company
amounted to $8 million, $8 million, and $41 million in 1995, 1994, and 1993,
respectively. Additional sites may require environmental remediation for which
the subsidiaries may be liable for a portion or all required cleanup costs. See
Note 3 to the financial statements for information regarding Georgia Power's
potentially responsible party status at a site in Bruswick, Georgia.
Several major pieces of environmental legislation are being considered for
reauthorization or amendment by Congress. These include: the Clean Air Act; the
Clean Water Act; the Comprehensive Environmental Response, Compensation, and
Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances
Control Act; and the Endangered Species 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 additional 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 exists for liability as the
result of lawsuits alleging damages caused by electromagnetic fields.
Sources of Capital
The Southern Company may require additional equity capital in 1996. The amount
and timing of additional equity capital to be raised in 1996 -- 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 1996 for the company's 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 companies plan to obtain the funds required for construction
and other purposes from sources similar to those used in the past, which was
primarily from internal sources. However, the type and timing of any financings
-- if needed -- will depend on market conditions and regulatory approval.
To meet short-term cash needs and contingencies, The Southern Company had
approximately $772 million of cash and cash equivalents and $2.8 billion of
unused credit arrangements with banks at the beginning of 1996.
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. Currently, each
of the operating companies expects to have adequate coverage ratios for
anticipated requirements through at least 1998.
II-15
II-16
II-17
II-18
II-19
II-20
II-21
NOTES TO FINANCIAL STATEMENTS
The Southern Company and Subsidiary Companies 1995 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 Communications Services (Southern Communications),
Southern Electric International (Southern Electric), Southern Nuclear Operating
Company (Southern Nuclear), The Southern Development and Investment Group
(Southern Development), and other direct and indirect subsidiaries. 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 subsidiary companies.
Southern Communications provides digital wireless communications services to the
operating companies and also markets these services to the public within the
Southeast. Southern Electric designs, builds, owns, and operates power
production and delivery 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. Southern Development develops new business
opportunities related to energy products and services.
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. The preparation of financial
statements in conformity with generally accepted accounting principles requires
the use of estimates, and the actual results may differ from those estimates.
All material intercompany items have been eliminated in consolidation.
Certain prior years' data presented in the consolidated financial statements
have been reclassified to conform with current year presentation.
Regulatory Assets and Liabilities
The operating companies are subject to the provisions of Financial Accounting
Standards Board (FASB) Statement No. 71, Accounting for the Effects of Certain
Types of Regulation. Regulatory assets represent probable future revenues to the
operating companies associated with certain costs that are expected to be
recovered from customers through the ratemaking process. Regulatory liabilities
represent probable future reductions in revenues associated with amounts that
are to be credited to customers through the ratemaking process. Regulatory
assets and (liabilities) reflected in the Consolidated Balance Sheets at
December 31 relate to:
1995 1994
------------------------
(in millions)
Deferred income taxes $1,386 $1,454
Deferred Plant Vogtle costs 308 432
Premium on reacquired debt 295 298
Demand-side programs 79 97
Department of Energy assessments 73 79
Vacation pay 74 70
Deferred fuel charges 49 51
Postretirement benefits 53 41
Work force reduction costs 56 15
Deferred income tax credits (936) (987)
Storm damage reserves (23) (53)
Other, net 98 108
-----------------------------------------------------------------
Total $1,512 $1,605
=================================================================
In the event that a portion of the operating companies' operations is no
longer subject to the provisions of Statement No. 71, the companies would be
required to write off related regulatory assets and liabilities. In addition,
the operating companies would be required to determine any impairment to other
assets, including plant, and write down the assets, if impaired, to their fair
value.
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.
The company has a diversified base of customers. No single customer or
industry comprises 10 percent or more of revenues. In 1995, uncollectible
accounts continued to average less than 1 percent of revenues.
II-22
NOTES (continued)
The Southern Company and Subsidiary Companies 1995 Annual Report
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 $140
million in 1995, $152 million in 1994, and $137 million in 1993. 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. Although disposal was
scheduled to begin in 1998, 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. Alabama Power and
Georgia Power -- based on its ownership interests -- estimate their respective
remaining liability at December 31, 1995, under this law to be approximately $40
million and $31 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 1995, 3.2 percent in 1994, and 3.3 percent in 1993. 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 and removal of other facilities.
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. Alabama
Power and Georgia Power have external trust funds to comply with the NRC's
regulations. Amounts previously recorded in internal reserves are being
transferred into the external trust funds over set periods of time as approved
by the respective state public service commissions. 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.
Site study cost is the estimate to decommission a specific facility as of
the site study year, and ultimate cost is the estimate to decommission a
specific facility as of retirement date. The estimated costs of decommissioning
-- both site study costs and ultimate costs -- at December 31, 1995, for Alabama
Power's Plant Farley and Georgia Power's ownership interests in plants Hatch and
Vogtle were as follows:
Plant Plant Plant
Farley Hatch Vogtle
-------------------------------
Site study basis (year) 1993 1994 1994
Decommissioning periods:
Beginning year 2017 2014 2027
Completion year 2029 2027 2038
--------------------------------------------------------------------
(in millions)
Site study costs:
Radiated structures $489 $294 $233
Non-radiated structures 89 41 52
--------------------------------------------------------------------
Total $578 $335 $285
====================================================================
(in millions)
Ultimate costs:
Radiated structures $1,504 $781 $1,018
Non-radiated structures 274 111 230
--------------------------------------------------------------------
Total $1,778 $892 $1,248
====================================================================
II-23
NOTES (continued)
The Southern Company and Subsidiary Companies 1995 Annual Report
Plant Plant Plant
Farley Hatch Vogtle
----------------------------
(in millions)
Amount expensed in 1995 $18 $11 $9
Accumulated provisions:
Balance in external trust
funds $108 $56 $36
Balance in internal reserves 49 30 13
-----------------------------------------------------------------
Total $157 $86 $49
=================================================================
Significant assumptions:
Inflation rate 4.5% 4.4% 4.4%
Trust earning rate 7.0 6.0 6.0
-----------------------------------------------------------------
Annual provisions for nuclear decommissioning are based on an annuity --
sinking fund -- method as approved by the respective state public service
commissions. All of Alabama Power's decommissioning costs are approved for
ratemaking. For Georgia Power, only the costs to decommission the radioactive
portion of the plants are included in cost of service. Alabama Power and Georgia
Power expect their respective state public service commission to periodically
review and adjust, if necessary, the amounts collected in rates for the
anticipated cost of decommissioning.
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 changes in the assumed date of
decommissioning, changes in NRC requirements, or changes in the assumptions used
in making estimates.
Income Taxes
The Southern Company uses the liability method of accounting for deferred income
taxes and 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.
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 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. 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. Each GPSC order called for recovery of deferred costs within 10 years.
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:
1995 1994 1993
------------------------------
(in millions)
Deferred capacity buybacks $ - $ 10 $ 38
Amortization of
deferred costs (124) (85) (74)
-----------------------------------------------------------------
Net amortization (124) (75) (36)
Effect of adoption of FASB
Statement No. 109 - - 160
Deferred costs
at beginning of year 432 507 383
-----------------------------------------------------------------
Deferred costs
at end of year $308 $432 $507
=================================================================
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. In 1995 and 1994, the amount deferred was
exceeded by the amortization of amounts previously deferred by $50 million and
$1 million, respectively. The projected net amortization of the deferred expense
is $62 million in 1996 and $57 million in 1997.
II-24
NOTES (continued)
The Southern Company and Subsidiary Companies 1995 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 operating companies to
calculate AFUDC during the years 1993 through 1995 ranged from a
before-income-tax rate of 3.6 percent to 9.8 percent. AFUDC, net of income tax,
as a percent of consolidated net income was 1.6 percent in 1995, 2.3 percent in
1994, and 1.7 percent in 1993.
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
Derivative financial instruments are used by The Southern Company to manage its
interest rate and foreign currency exposures. Gains and losses arising from
effective hedges of existing assets, liabilities, or firm commitments are
deferred and recognized when the offsetting gains and losses are recognized on
the related hedged items. Losses realized on termination of interest rate swap
contracts are deferred and amortized over the terms of the related new debt
agreements. At December 31, 1995, the credit risk for derivatives outstanding
was not material.
The Southern Company hedges its exposure to fluctuations in interest rates
by entering into swap agreements that allow the company to effectively convert
its outstanding variable-rate debt into fixed rates. During 1995, the company
terminated the swap contracts in place at December 31, 1994, incurring a loss on
termination of approximately $32 million, which is being amortized over the life
of the related new fixed-rate debt agreements. At December 31, 1995, six
interest rate swap agreements were in place.
The Southern Company hedges its net investment in South Western Electricity
(SWEB) through forward contracts involving Pounds Sterling. The company
regularly monitors its foreign currency exposure, and ensures that hedge
contract amounts do not exceed the amount of the underlying exposure. At
December 31, 1995, the status of outstanding derivative contracts was as
follows:
Year Of
Maturity or Notional Unrealized
Type Termination Amount Gain (Loss)
--------------------- -------------- ---------------------------
(in millions)
Interest rate
swaps 1999-2006 $308 $(9)
Foreign currency
forwards 1996 389 -
-----------------------------------------------------------------------
In accordance with FASB Statement No. 107, Disclosure About Fair Value of
Financial Instruments, The Southern Company's financial instruments that the
carrying amount did not approximate fair value at December 31 were as follows:
Carrying Fair
Amount Value
--------------------------
(in millions)
Long-term debt:
At December 31, 1995 $8,668 $8,935
At December 31, 1994 7,674 7,373
Preferred securities:
At December 31, 1995 100 114
-----------------------------------------------------------------
The fair value for long-term debt and preferred securities were based on
either closing market price or closing price of comparable instruments.
II-25
NOTES (continued)
The Southern Company and Subsidiary Companies 1995 Annual Report
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 Plan
The system companies have defined benefit, trusteed, pension plans that cover
substantially all regular employees. Benefits are based on one of the following
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 trusts 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
In the United States, The Southern Company provides certain medical care and
life insurance benefits for retired employees. Substantially all employees may
become eligible for these benefits when they retire. Trusts are funded to the
extent deductible under federal income tax regulations or to the extent required
by the operating companies' respective regulatory commissions.
Amounts funded are primarily invested in debt and equity securities.
FASB Statement No. 106, Employers' Accounting for Postretirement Benefits
Other Than Pensions, 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 was expensed
in 1993 and the remaining costs were deferred. An additional one-fifth of the
costs is being 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. For the other
operating companies, the cost of postretirement benefits is reflected in rates
on a current basis.
Funded Status and Cost of Benefits
The following tables show actuarial results and assumptions for pension and
postretirement insurance benefits as computed under the requirements of FASB
Statement Nos. 87 and 106, respectively. The funded status of the plans at
December 31 was as follows:
Pension
-----------------------
1995 1994
-----------------------
(in millions)
Actuarial present value of
benefit obligation:
Vested benefits $2,643 $1,593
Non-vested benefits 97 68
------------------------------------------------------------------
Accumulated benefit obligation 2,740 1,661
Additional amounts related to
projected salary increases 705 638
------------------------------------------------------------------
Projected benefit obligation 3,445 2,299
Less:
Fair value of plan assets 4,725 3,171
Unrecognized net gain (1,025) (789)
Unrecognized prior service cost 60 64
Unrecognized transition asset (126) (139)
------------------------------------------------------------------
Prepaid asset recognized in the
Consolidated Balance Sheets $ 189 $ 8
==================================================================
Postretirement Benefits
----------------------------
1995 1994
----------------------------
(in millions)
Actuarial present value of
benefit obligation:
Retirees and dependents $394 $375
Employees eligible to retire 63 40
Other employees 392 459
------------------------------------------------------------------
Accumulated benefit obligation 849 874
Less:
Fair value of plan assets 205 140
Unrecognized net loss (gain) 85 3
Unrecognized prior service cost (4) -
Unrecognized transition
obligation 292 500
------------------------------------------------------------------
Accrued liability recognized in the
Consolidated Balance Sheets $271 $231
==================================================================
In 1995, the system companies announced a cost sharing program for
postretirement benefits. The program establishes limits on amounts the companies
II-26
NOTES (continued)
The Southern Company and Subsidiary Companies 1995 Annual Report
will pay to provide future retiree postretirement benefits. This change reduced
the 1995 accumulated postretirement benefit obligation by approximately $186
million.
The weighted average rates assumed in the actuarial calculations were:
1995 1994 1993
--------------------------------
Discount 7.3% 8.0% 7.5%
Annual salary increase 4.8 5.5 5.0
Long-term return on
plan assets 8.5 8.5 8.5
---------------------------------------------------------------
An additional assumption used in measuring the accumulated postretirement
benefit obligation was a weighted average medical care cost trend rate of 9.8
percent for 1995, decreasing gradually to 5.3 percent through the year 2005 and
remaining at that level thereafter. An annual increase in the assumed medical
care cost trend rate of 1 percent would increase the accumulated benefit
obligation at December 31, 1995, by $73 million and the aggregate of the service
and interest cost components of the net retiree cost by $16 million.
Components of the plans' net costs are shown below:
Pension
-----------------------------
1995 1994 1993
-----------------------------
(in millions)
Benefits earned during the year $ 79 $ 77 $ 76
Interest cost on projected
benefit obligation 193 160 156
Actual (return) loss on plan assets (730) 75 (432)
Net amortization and deferral 412 (351) 186
--------------------------------------------------------------------
Net pension cost (income) $ (46) $(39) $(14)
====================================================================
Of the above net pension income, $30 million in 1995, $29 million in 1994,
and $9 million in 1993 were recorded in operating expenses, and the remainder
was recorded in construction and other accounts.
Postretirement Benefits
---------------------------
1995 1994 1993
---------------------------
(in millions)
Benefits earned during the year $ 28 $ 31 $ 27
Interest cost on accumulated
benefit obligation 67 64 56
Amortization of transition
obligation 27 27 28
Actual (return) loss on plan
assets
assets (23) 2 (12)
Net amortization and deferral 12 (10) 5
------------------------------------------------------------------
Net postretirement costs $111 $114 $104
==================================================================
Of the above net postretirement costs, $78 million in 1995, $77 million in
1994, and $64 million in 1993 were charged to operating expenses. In addition,
$11 million in 1995, $18 million in 1994, and $21 million in 1993 were deferred,
and the remainder was charged to construction and other accounts.
Work Force Reduction Programs
The system companies have incurred additional costs for work force reduction
programs. The costs related to these programs were $42 million, $112 million,
and $35 million for the years 1995, 1994, and 1993, respectively. In addition,
certain costs of these programs were deferred and are being amortized in
accordance with regulatory treatment. The unamortized balance of these costs was
$56 million at December 31, 1995.
3. LITIGATION AND REGULATORY MATTERS
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
II-27
NOTES (continued)
The Southern Company and Subsidiary Companies 1995 Annual Report
adequately their allegation that The Southern Company board of directors'
refusal of an earlier demand by the plaintiffs was wrongful. In April 1994, the
U.S. Court of Appeals for the 11th Circuit reversed the dismissal and remanded
the case to the trial court, finding that allegations by the plaintiffs created
a reasonable doubt that the board validly exercised its business judgment in
refusing the earlier demand. In June 1995, for the second time, the trial court
dismissed the suit. The plaintiffs once again have filed an appeal. This action
is still pending.
Georgia Power Potentially Responsible Party Status
In January 1995, Georgia Power and four other unrelated entities were notified
by the Environmental Protection Agency (EPA) that they have been designated as
potentially responsible parties under the Comprehensive Environmental Response,
Compensation, and Liability Act with respect to a site in Brunswick, Georgia. As
of December 31, 1995, Georgia Power had recorded approximately $4 million in
expenses associated with the site. While Georgia Power believes that the total
amount of costs required for the cleanup of this site may be substantial, it is
unable at this time to estimate either such total or the portion for which
Georgia Power may be ultimately responsible. However, based on the nature and
extent of Georgia Power's activities relating to the site, management believes
that the company's portion of these costs should not be material.
Georgia Power Investment in Rocky Mountain
In its 1985 financing order, the GPSC concluded that completion of the Rocky
Mountain pumped storage hydroelectric plant in 1991 as then planned was not
economically justifiable and reasonable and withheld authorization for Georgia
Power to spend funds from approved securities issuances on that plant. 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 plant. However, full recovery of Georgia Power's costs depends
on the GPSC's treatment of the plant's costs and the disposition of the plant's
capacity output. In the event the GPSC does not allow full recovery of the plant
costs, then the portion not allowed may have to be written off. In 1995, the
plant went into commercial operation. At December 31, 1995, Georgia Power's net
investment in the plant was approximately $190 million.
The final outcome of this matter cannot now be determined. Accordingly, no
provision for any write-down of the investment in the plant has been made.
FERC Reviews Equity Returns
In May 1991, the FERC ordered that hearings be conducted concerning the
reasonableness of the operating companies' 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
change in the rate of return on common equity that may require refunds as a
result of this proceeding would be substantially for the period beginning in
July 1991 and ending in October 1992.
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.
In August 1994, the FERC instituted another proceeding based on
substantially the same issues as in the 1991 proceeding. The second period under
review for possible refunds was substantially from October 1994 through December
1995. In November 1995, a FERC administrative law judge issued an opinion that
the FERC staff failed to meet its burden of proof, and therefore, no change in
the equity return was necessary. The FERC staff has filed exceptions to the
administrative law judge's opinion, and the matter is pending before the FERC.
If the rates of return on common equity recommended by the FERC staff were
applied to all of the schedules and contracts involved in both proceedings, and
refunds were ordered, the amount of refunds could range up to approximately $120
million at December 31, 1995. However, management believes that rates are not
excessive and that refunds are not justified.
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.
II-28
NOTES (continued)
The Southern Company and Subsidiary Companies 1995 Annual Report
In June 1995, the APSC issued a rate order granting Alabama Power's request
for gradual adjustments to move toward parity among customer classes. This order
also calls for a moratorium on any periodic retail rate increases (but not
decreases) until July 2001.
In December 1995, the APSC issued an order authorizing Alabama Power to
reduce balance sheet items -- such as plant and deferred charges -- at any time
the company's actual base rate revenues exceed the budgeted revenues. In
accordance with this order, Alabama Power reduced the unamortized balance of
premium on reacquired debt by $10 million in 1995.
The ratemaking procedures will remain in effect until the APSC votes to
modify or discontinue them.
Georgia Power Retail Rate Plan
On February 16, 1996, the GPSC approved a rate plan recommended by the GPSC
staff that concludes the GPSC's review of Georgia Power's earnings initiated in
early 1995 and addressed the company's proposed alternative retail rate plan.
Under the three-year plan, effective January 1, 1996, Georgia Power's earnings
will be evaluated against a retail return on common equity range of 10 percent
to 12.5 percent. Earnings in excess of 12.5 percent will be used to accelerate
the amortization of regulatory assets or accelerate the depreciation of electric
plant. At its option, Georgia Power may also accelerate amortization or
depreciation of assets while within the allowed return on common equity range.
The company is required to absorb cost increases of approximately $29 million
annually during the plan's three-year operation, including $14 million annually
of accelerated depreciation of electric plant. During the plan's operation,
Georgia Power will not file for a general base rate increase unless its
projected retail return on equity falls below 10 percent. On July 1, 1998,
Georgia Power is required to file a general rate case. In response, the GPSC
would be expected to either continue the rate plan or adopt a different one.
Georgia Power 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, pending the resolution of the
recovery of such costs.
After the Georgia Court of Appeals upheld the legality of the rate riders,
Georgia Power resumed collection under the riders in December 1994. In August
1995, the GPSC ordered Georgia Power to discontinue the demand-side conservation
programs by the end of 1995. However, Georgia Power's rate riders will continue
in effect until costs deferred are collected. Under the new retail rate plan,
approved February 16, 1996, Georgia Power will expense approximately $29 million
of deferred program costs over a three-year period that will not be recovered
under the rate riders.
4. CONSTRUCTION PROGRAM
The system companies are engaged in continuous construction programs, currently
estimated to total some $1.5 billion in 1996, $1.4 billion in 1997, and $1.3
billion in 1998. These estimates include AFUDC of $22 million in 1996, $22
million in 1997, and $25 million in 1998. 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, 1995, 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 600 megawatts is planned to be completed by 1998. In addition,
significant construction will continue related to transmission and distribution
facilities and the upgrading and extension of the useful lives of generating
plants.
II-29
NOTES (continued)
The Southern Company and Subsidiary Companies 1995 Annual Report
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, INVESTMENTS, AND COMMITMENTS
General
The Southern Company may require additional equity capital in 1996. The amount
and timing of additional equity capital to be raised in 1996 -- 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.
The operating companies' construction programs are expected to be financed
primarily from internal sources. Short-term debt is often utilized and the
amounts available are discussed below. The companies may issue additional
long-term debt and preferred stock primarily for the purposes of debt maturities
and for redeeming higher-cost securities if market conditions permit.
Southern Electric Investments
Southern Electric has substantial investments in production and delivery
facilities in the United States and various international markets. The most
recent acquisition was SWEB, and for additional information see Note 14.
Southern Electric's total assets were $5.0 billion at December 31, 1995. The
consolidated financial statements reflect investments in majority-owned or
controlled subsidiaries on a consolidated basis and other investments on an
equity basis.
Bank Credit Arrangements
At the beginning of 1996, unused credit arrangements with banks totaled $2.8
billion, of which approximately $1.5 billion expires at various times during
1996 and 1997; $16 million expires in February 1998; $73 million expires in May
1998; $400 million expires in June 1998; $300 million expires in July 1998; $300
million expires in November 1998; and $56 million expires in December 1998.
Also, $136 million expires in the years 1999 through 2002.
Georgia Power's revolving credit agreements of $60 million, all of which
remained unused as of December 31, 1995, expire May 1, 1998. 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.
Gulf Power's revolving credit agreements of $20 million, of which $13
million remained unused as of December 31, 1995, expire May 31, 1998. These
agreements allow short-term and/or term borrowings with various terms and
conditions regarding repayment. In connection with these credit arrangements,
Gulf 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, 1998, is under revolving credit
arrangements with several banks that provide 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, $100 million, $135
million, and $165 million available credit are currently dedicated to the
exclusive use of The Southern Company, 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.
The Southern Company has $300 million of revolving credit agreements
expiring July 1, 1998, and $300 million of revolving credit agreements expiring
November 30, 1998, all of which remained unused at 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 Southern Company's option. In connection with these credit
arrangements, The Southern Company agrees to pay commitment fees based on the
unused portions of the commitments or to maintain compensating balances with the
banks.
II-30
NOTES (continued)
The Southern Company and Subsidiary Companies 1995 Annual Report
Mississippi Power's revolving credit agreements of $40 million, all of which
remained unused as of December 31, 1995, expire December 1, 1998. 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's revolving credit arrangements of $20 million, of which
$16 million remained unused as of December 31, 1995, expire December 31, 1998.
These agreements allow short-term borrowings to be converted into terms 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.
Southern Electric's revolving credit agreements of $212 million, of which
$151 million remained unused as of December 31, 1995, expire at various times
from 1998 through 2002. These agreements allow for short-term borrowings with
various terms and conditions. These agreements require payment of commitment
fees based on the unused portions of the commitments.
A portion of the $2.8 billion unused credit arrangements with banks --
discussed earlier -- is allocated to provide liquidity support to the companies'
variable rate pollution control bonds. At December 31, 1995, the amount of
credit lines allocated was $692 million.
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 The Southern Company, Alabama Power, and
Georgia Power, through commercial paper programs that have the liquidity support
of committed bank credit arrangements.
Assets Subject to Lien
Each of The Southern Company's subsidiaries is organized as a legal entity,
separate, and apart from The Southern Company and its other subsidiaries. The
subsidiary 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. There are no agreements or
other arrangements among the subsidiary companies under which the assets of one
company have been pledged or otherwise made available to satisfy obligations of
The Southern Company or any of its subsidiaries.
Fuel and Purchase Power Commitments
To supply a portion of the fuel requirements of the generating plants, The
Southern 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. Also, The Southern Company has entered into various long-term
commitments for the purchase of electricity. Total estimated long-term
obligations at December 31, 1995, were as follows:
Purchased
Year Fuel Power
----------- -----------------------------
(in millions)
1996 $ 1,914 $ 495
1997 1,656 427
1998 1,482 155
1999 1,093 161
2000 728 166
2001 and thereafter 6,078 1,943
-------------------------------------------------------------
Total commitments $12,951 $3,347
=============================================================
II-31
NOTES (continued)
The Southern Company and Subsidiary Companies 1995 Annual Report
Operating Leases
The Southern Company has operating lease agreements with various terms and
expiration dates. These expenses totaled $17 million, $15 million, and $11
million for 1995, 1994, and 1993, respectively. At December 31, 1995, estimated
minimum rental commitments for noncancelable operating leases were as follows:
Year Amounts
-------- ----------------
(in millions)
1996 $ 22
1997 20
1998 19
1999 19
2000 20
2001 and thereafter 252
---------------------------------------------------------------
Total minimum payments $352
===============================================================
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, and the
city of Dalton, Georgia. In addition, Georgia Power has joint ownership
agreements with OPC for the Rocky Mountain project and with Florida Power
Corporation (FPC) for a combustion turbine unit at Intercession City, Florida.
In 1995, Georgia Power completed the sale of Unit 4 of Plant Scherer to
Florida Power & Light Company (FP&L) and Jacksonville Electric Authority (JEA).
FP&L owns approximately 76.4 percent of the unit, with JEA owning the remainder.
Georgia Power operates and maintains the unit.
At December 31, 1995, 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
---------------- ------------------------------
Plant Vogtle (in millions)
(nuclear) 45.7% $3,295 $730
Plant Hatch
(nuclear) 50.1 842 394
Plant Miller
(coal)
Units 1 and 2 91.8 712 281
Plant Scherer
(coal)
Units 1 and 2 8.4 112 39
Plant Wansley
(coal) 53.5 297 132
Rocky Mountain
(pumped storage) 25.4 200 10
------------------------------------------------------------------
In 1994, Georgia Power and FPC entered into a joint ownership agreement
regarding the Intercession City combustion turbine unit. The unit is scheduled
to be in commercial operation by the end of 1996, and will be constructed,
operated, and maintained by FPC. Georgia Power will have an approximate interest
of 33 percent in the 150-megawatt unit, with retention of 100 percent of the
capacity from June through September. FPC will have the capacity the remainder
of the year. Georgia Power's investment in the unit at completion is estimated
to be $14 million.
Alabama Power and Georgia Power have contracted to operate and maintain the
jointly owned facilities -- except for the Rocky Mountain project and
Intercession City -- 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.
7. LONG-TERM POWER SALES AGREEMENTS
The operating companies have long-term contractual agreements for the sale of
capacity and energy to certain non-affiliated utilities located outside the
system's service area. The agreements for non-firm capacity expired in 1994.
Other agreements --expiring at various dates discussed below -- are firm and
pertain to capacity related to specific generating units. Because the energy is
II-32
NOTES (continued)
The Southern Company and Subsidiary Companies 1995 Annual Report
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)
1995 $237 $ - $237
1994 257 19 276
1993 312 38 350
In 1994, long-term non-firm power of 200 megawatts was sold to FPC under a
contract that expired at year-end. In January 1995, the amount of unit power
sales to FPC increased by 200 megawatts.
Unit power from specific generating plants is currently being sold to FP&L,
FPC, JEA, and the city of Tallahassee, Florida. Under these agreements,
approximately 1,600 megawatts of capacity is scheduled to be sold annually
through 1999. Thereafter, these sales will decline to some 1,500 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.
8. INCOME TAXES
Effective January 1, 1993, The Southern Company adopted FASB Statement No. 109,
Accounting for Income Taxes. The adoption resulted in the recording of
additional deferred income taxes and related regulatory assets and liabilities.
At December 31, 1995, the tax- related regulatory assets and liabilities were
$1.4 billion and $936 million, respectively. These assets are attributable to
tax benefits flowed through to customers in prior years and to taxes applicable
to capitalized AFUDC. These liabilities are attributable to deferred taxes
previously recognized at rates higher than current enacted tax law and to
unamortized investment tax credits.
Details of the federal and state income tax provisions are as follows:
1995 1994 1993
---------------------------
(in millions)
Total provision for income taxes:
Federal --
Currently payable $567 $598 $421
Deferred -- current year 184 67 224
-- reversal of
prior years (111) (75) (51)
Deferred investment tax
credits 1 - (20)
-------------------------------------------------------------------
641 590 574
-------------------------------------------------------------------
State --
Currently payable 90 86 64
Deferred -- current year 26 15 39
-- reversal of
prior years (12) (11) (3)
-------------------------------------------------------------------
104 90 100
-------------------------------------------------------------------
International 24 5 3
-------------------------------------------------------------------
Total 769 685 677
Less income taxes charged
(credited) to other income (36) (26) (57)
-------------------------------------------------------------------
Federal and state income
taxes charged to operations $805 $711 $734
===================================================================
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:
1995 1994
-----------------------
(in millions)
Deferred tax liabilities:
Accelerated depreciation $2,795 $2,637
Property basis differences 2,175 1,647
Deferred plant costs 100 141
Other 247 271
-------------------------------------------------------------------
Total 5,317 4,696
-------------------------------------------------------------------
Deferred tax assets:
Federal effect of state deferred taxes 107 104
Other property basis differences 273 278
Deferred costs 118 79
Pension and other benefits 66 63
Other 192 225
-------------------------------------------------------------------
Total 756 749
-------------------------------------------------------------------
Net deferred tax liabilities 4,561 3,947
Portion included in current assets, net 50 60
-------------------------------------------------------------------
Accumulated deferred income taxes
in the Consolidated Balance Sheet $4,611 $4,007
===================================================================
II-33
NOTES (continued)
The Southern Company and Subsidiary Companies 1995 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 $38 million in 1995, $42 million in 1994, and $36 million in
1993. At December 31, 1995, 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:
1995 1994 1993
------------------------------
Federal statutory rate 35.0% 35.0% 35.0%
State income tax,
net of federal deduction 3.4 3.3 3.7
Non-deductible book
depreciation 1.6 1.8 1.9
Difference in prior years'
deferred and current tax rate (1.1) (1.5) (1.3)
Other 0.3 0.3 (1.1)
----------------------------------------------------------------------
Effective income tax rate 39.2% 38.9% 38.2%
======================================================================
The Southern Company files a consolidated federal income tax return. Under a
joint consolidated income tax agreement, each subsidiary's current and deferred
tax expense is computed on a stand-alone basis. Tax benefits from losses of the
parent company are allocated to each subsidiary based on the ratio of taxable
income to total consolidated taxable income.
9. 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 reflect the stock distribution.
Shares Reserved
At December 31, 1995, a total of 69 million shares was reserved for issuance
pursuant to the Dividend Reinvestment and Stock Purchase Plan, the Employee
Savings Plan, the Outside Directors Stock 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. As of December 31, 1995, some 200 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 the date of grant. Options outstanding will
expire no later than 10 years after the date of grant, unless terminated earlier
by the board of directors in accordance with the plan.
Stock option activity in 1994 and 1995 is summarized below:
Shares Average
Subject Option Price
To Option Per Share
-----------------------------------
Balance at December 31, 1993 1,364,810 $16.77
Options granted 446,443 18.88
Options canceled -- --
Options exercised (74,649) 14.81
---------------------------------------------------------------------
Balance at December 31, 1994 1,736,604 17.39
Options granted 1,161,174 21.63
Options canceled (8,088) 21.63
Options exercised (413,391) 14.34
---------------------------------------------------------------------
Balance at December 31, 1995 2,476,299 $19.87
=====================================================================
Shares reserved for future grants:
At December 31, 1993 3,714,444
At December 31, 1994 3,268,001
At December 31, 1995 2,114,915
---------------------------------------------------------------------
Options exercisable:
At December 31, 1994 793,989
At December 31, 1995 831,227
---------------------------------------------------------------------
Common Stock Dividend Restrictions
The income of The Southern Company is derived primarily from equity in earnings
of its subsidiaries. At December 31, 1995, consolidated retained earnings
included $3.1 billion of undistributed retained earnings of the subsidiaries. Of
this amount, $2.0 billion was restricted against the payment by the subsidiary
companies of cash dividends on common stock under terms of bond indentures or
charters.
II-34
NOTES (continued)
The Southern Company and Subsidiary Companies 1995 Annual Report
10. PREFERRED SECURITIES
In December 1994, Georgia Power Capital, L.P., of which Georgia Power is the
sole general partner, issued $100 million of 9 percent mandatorily redeemable
preferred securities. The sole asset of Georgia Power Capital is $103 million
aggregate principal amount of Georgia Power's 9 percent Junior Subordinated
Deferrable Interest Debentures due December 19, 2024. Georgia Power considers
that the mechanisms and obligations relating to the preferred securities, taken
together, constitute a full and unconditional guarantee by Georgia Power of
Georgia Power Capital's payment obligations with respect to the preferred
securities.
11. OTHER LONG-TERM DEBT
Details of other long-term debt at December 31 are as follows:
1995 1994
--------------------
(in millions)
Obligations incurred in connection
with the sale by public authorities
of tax-exempt pollution control
revenue bonds:
Collateralized --
4.375% to 9.375% due
2000-2025 $1,466 $1,179
Variable rates (3.5% to 6.1%
at 1/1/96) due 2011-2025 639 412
Non-collateralized --
7.25% due 2003 1 1
6.75% to 10.6% due 2015-2020 277 828
5.8% due 2022 10 10
Variable rates (3.25% to 3.75%
at 1/1/96) due 2019-2022 132 85
----------------------------------------------------------------
2,525 2,515
----------------------------------------------------------------
Capitalized lease obligations 147 148
----------------------------------------------------------------
Notes payable:
4.15% to 13% due 1995-1998 107 179
6.31% to 11% due 1999-2008 404 170
Adjustable rates (4% to 7% at
1/1/96) due 1995-1998 129 119
Adjustable rates (7.5% to 9.18%
at 1/1/96) due 1999-2000 165 130
Adjustable rate (7.7 % at
1/1/96) due 2000 926 -
----------------------------------------------------------------
1,731 598
----------------------------------------------------- ----------
Total $4,403 $3,261
================================================================
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 $122 million and $126 million at
December 31, 1995 and 1994, respectively. At December 31, 1995, the composite
interest rates for buildings and other were 9.7 percent and 11.3 percent,
respectively. Sinking fund requirements and/or serial maturities through 2000
applicable to other long-term debt are as follows: $264 million in 1996; $99
million in 1997; $42 million in 1998; $23 million in 1999; and $56 million in
2000.
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 at December 31 is as follows:
1995 1994
-----------------
(in millions)
Bond improvement fund requirements $ 43 $ 48
Less:
Portion to be satisfied by certifying
property additions 18 46
Reacquired bonds - -
------------------------------------------------------------------
Cash sinking fund requirements 25 2
First mortgage bond maturities
and redemptions 220 130
Other long-term debt maturities
(Note 11) 264 97
------------------------------------------------------------------
Total $509 $229
==================================================================
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.
II-35
NOTES (continued)
The Southern Company and Subsidiary Companies 1995 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 provides funds up to
$8.9 billion for 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 $162 million, respectively, per incident but
not more than an aggregate of $20 million per company 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 assessment in the event that losses exceed
accumulated reserve funds. Alabama Power's and Georgia Power's maximum annual
assessments are limited to $10 million and $12 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.
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 $2.8 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 $21 million and $24
million, respectively. The maximum replacement power assessments are $8 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 approximately $6 million
each.
All retrospective assessments -- whether generated for liability, property,
or replacement power -- may be subject to applicable state premium taxes.
II-36
NOTES (continued)
The Southern Company and Subsidiary Companies 1995 Annual Report
14. ACQUISITION
In 1995, Southern Electric acquired SWEB for approximately $1.8 billion. This
British utility distributes electricity to some 1.3 million customers.
The acquisition has been accounted for under the purchase method of
accounting. The acquisition cost exceeded the preliminary estimate of the fair
market value of net assets by $333 million. This amount is considered goodwill
and will be amortized on a straight-line basis over 40 years. The preliminary
estimate of net assets may be revised in 1996.
SWEB has been included in the consolidated financial statements since
September 1995. The following unaudited pro forma results of operations for the
years 1995 and 1994 have been prepared assuming the acquisition of SWEB,
effective January 1994, and assuming 100 percent short-term debt financing.
Eventually, the short-term borrowings will be replaced by a combination of
long-term debt and equity. The pro forma results are not necessarily indicative
of the actual results that would have been realized had the acquisition occurred
on the assumed date, nor are they necessarily indicative of future results. Pro
forma operating results are for information purposes only and are as follows:
15. SEGMENT INFORMATION
The Southern Company's principal business segment -- or its core business -- is
the five electric utility operating companies, which provide electric service in
four Southeastern states. The other reportable business segment is Southern
Electric, which owns and operates power production and delivery facilities in
the United States and various international markets. Financial data for business
segments and geographic areas are as follows:
Business Segments
II-37
NOTES (continued)
The Southern Company and Subsidiary Companies 1995 Annual Report
Geographic Areas
II-38
II-39
II-40A
II-40B
II-41
II-42A
II-42B
II-43
II-44A
II-44B
II-44C
II-45
II-46A
II-46B
II-46C
II-47
II-48A
II-48B
II-48C
II-49
II-50A
II-50B
II-50C
ALABAMA POWER COMPANY
FINANCIAL SECTION
II-51
Management's Report
Alabama Power Company 1995 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, 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 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
Elmer B. Harris
President
and Chief Executive Officer
/s/ William B. Hutchins, III
William B. Hutchins, III
Executive Vice President
and Chief Financial Officer
February 21, 1996
II-52
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, 1995 and 1994, and the related
statements of income, retained earnings, and cash flows for each of the three
years in the period ended December 31, 1995. These financial statements are the
responsibility of the company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements (pages II-61 through II-78)
referred to above present fairly, in all material respects, the financial
position of Alabama Power Company as of December 31, 1995 and 1994, and the
results of its operations and its cash flows for the periods stated, in
conformity with generally accepted accounting principles.
/s/ Arthur Andersen LLP
Birmingham, Alabama
February 21, 1996
II-53
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Alabama Power Company 1995 Annual Report
RESULTS OF OPERATIONS
Earnings
Alabama Power Company's 1995 net income after dividends on preferred stock was
$361 million, representing a $4.6 million (1.3 percent) increase from the prior
year. This improvement can be attributed to an increase in retail energy sales
of 4.7 percent from 1994 levels. This was primarily due to the extreme summer
weather during 1995, especially when compared to the mild weather of 1994. This
improvement was partially offset by a 2.6 percent increase in operating costs.
In 1994, earnings were $356 million, representing a 2.8 percent increase
from the prior year. This increase was due to lower operating expenses which
decreased 3.0 percent from the previous year. This improvement was partially
offset by reduced capacity sales to nonterritorial utilities. Net income was
also impacted by the mild weather in 1994.
The return on average common equity for 1995 was 13.61 percent compared to
13.86 percent in 1994, and 13.94 percent in 1993.
Revenues
Total revenues for 1995 were $3.0 billion, reflecting a 3.1 percent increase
from 1994. The following table summarizes the principal factors that affected
operating revenues for the past three years:
Increase (Decrease)
From Prior Year
----------------------------------------
1995 1994 1993
------------- ------------ -------------
(in thousands)
Retail --
Change in
base rates $ 990 $ -- $ --
Unbilled
adjustment -- 28,000 --
Sales growth 18,174 45,304 24,960
Weather 54,888 (39,964) 58,536
Fuel cost recovery
and other 35,235 (84,344) 96,437
---------------------------------------------------------------
Total retail 109,287 (51,004) 179,933
---------------------------------------------------------------
Sales for Resale --
Non-affiliates 15,380 (9,345) (43,686)
Affiliates (37,032) (17,213) 23,887
---------------------------------------------------------------
Total sales for resale (21,652) (26,558) (19,799)
Other operating
revenues 1,997 5,095 635
---------------------------------------------------------------
Total operating
revenues $89,632 $(72,467) $160,769
---------------------------------------------------------------
Percent change 3.1% (2.4)% 5.6%
---------------------------------------------------------------
Retail revenues of $2.5 billion in 1995 increased $109 million (4.6 percent)
from the prior year, compared with a decrease of $51 million (2.1 percent) in
1994. The hot weather during the summer of 1995 and higher fuel cost recovery
were the primary reasons for the increase in retail revenues over 1994. The mild
weather during 1994 and lower fuel cost recovery contributed to the decrease in
retail revenues from 1993. Fuel revenues, which increased in 1995, generally
represent the direct recovery of fuel expense, including the fuel component of
purchased energy, and therefore have no effect on net income.
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
II-54
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 1995 Annual Report
contracts. Energy is generally sold at variable cost. These capacity and energy
components, as well as the components of the sales to affiliated companies,
were:
1995 1994 1993
-------------------------------------------
(in thousands)
Capacity $158,825 $165,063 $187,062
Energy 209,376 222,579 233,253
----------------------------------------------------------
Total $368,201 $387,642 $420,315
----------------------------------------------------------
Capacity revenues from non-affiliates remained relatively constant in 1995
and 1994. Capacity revenues from sales to affiliates decreased $22 million in
1994. Sales to affiliated companies within the Southern electric system will
vary from year to year depending on demand, the availability, and the variable
production cost of generating resources at each company.
Kilowatt-hour (KWH) sales for 1995 and the percent change by year were as
follows:
KWH Percent Change
-------------------------------------------
1995 1995 1994 1993
-------------------------------------------
(millions)
Residential 14,383 9.1% (1.7)% 9.2%
Commercial 10,043 4.1 3.4 6.4
Industrial 19,863 2.0 3.2 1.8
Other 187 0.5 1.1 2.8
----------
Total retail 44,476 4.7 3.3 5.1
Sales for resale -
Non-affiliates 8,046 18.8 (5.2) (14.8)
Affiliates 6,705 (20.5) 4.3 12.1
----------
Total 59,227 2.6% 2.4% 3.0%
-----------------------------------------------------------------
The rate of increase in 1995 retail energy sales was fostered by the impact
of weather. Residential energy sales surged upward as a result of
hotter-than-normal summer weather in 1995, compared with the mild summer of
1994. The gains in commercial and industrial sales reflect the strength of
business and economic conditions in the company's service area.
Expenses
Total operating expenses of $2.4 billion for 1995 were up $60 million or 2.6
percent compared with 1994. The major components of this increase include $27
million in purchased power, $43 million in other operation expenses, $11 million
in depreciation and amortization, and $7 million in income taxes offset by
decreases in fuel costs and maintenance expenses of $10 million and $19 million,
respectively.
Total operating expenses of $2.3 billion for 1994 were down 3.0 percent
compared with the prior year. The decrease was mainly due to less coal-fired
generation and a lower average cost of fuel consumed. Coal-fired generation
decreased because it was displaced with lower cost nuclear and hydro generation.
Fuel costs constitute 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. The amount and sources of generation and the average cost of
fuel per net kilowatt-hour generated were as follows:
--------------------------
1995 1994 1993
-------------------------
Total generation
(billions of kilowatt-hours) 58 57 55
Sources of generation
(percent) --
Coal 73 68 70
Nuclear 19 23 22
Hydro 8 9 8
Average cost of fuel per net
kilowatt-hour generated
(cents) --
Coal 1.71 1.92 2.11
Nuclear 0.50 0.49 0.51
Total 1.48 1.56 1.73
--------------------------------------------------------------
Note: Oil & Gas comprise less than 0.5% of generation.
Fuel expense decreased in 1995 by $10 million or 1.3 percent. This decrease
resulted from lower average cost of fuel consumed. Fuel expense decreased in
1994 by $75 million (8.6 percent) from the previous year. This decrease is
attributable to the increase in availability of nuclear and hydro generation and
a decrease in the cost of fuel.
The increase in purchased power is primarily attributable to the
exceptionally hot summer weather. Purchased power consists primarily of
purchases from the affiliates of the Southern electric system. Purchased power
II-55
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 1995 Annual Report
transactions among the company and its affiliates will vary from period to
period depending on demand, the availability, and the variable production cost
of generating resources at each company. KWH purchases from affiliates increased
18 percent from the prior year.
Other operation expenses increased 9.4 percent in 1995 following a 2.5
percent decrease in 1994. This increase over 1994 is primarily attributable to
the 1995 expenses not reflecting the positive impact of the amortization of the
Gulf States Utilities settlement which expired in 1994.
The decrease in maintenance expenses for 1995 reflects the establishment in
September 1994 of a Natural Disaster Reserve. This also caused the increase in
1994 maintenance expenses over 1993. See Note 1 to the financial statements
under "Natural Disaster Reserve" for additional information.
Depreciation and amortization expense increased 3.6 percent in 1995. This
increase reflects additions to utility plant. The amount for 1994 was virtually
unchanged from the previous year because of lower average depreciation rates
effective January 1994 and offsetting growth in depreciable plant in service.
Income tax expense increased 3.0 percent and 8.2 percent in 1995 and 1994,
respectively. These increases are primarily attributable to higher taxable
income.
The company contributed $11.5 million to the Alabama Power Foundation, Inc.
in 1995, which represents a decrease of $2.0 million from the previous year. The
Foundation makes distributions to qualified entities which are organized
exclusively for charitable, educational, literary, and scientific purposes.
Total net interest charges and preferred stock dividends rose in 1995 to
$265 million, an increase of 12.2 percent. This increase results from (i)
interest on interim obligations which rose due to higher average interest rates
on an increased average amount of short-term debt outstanding and (ii)
amortization of debt discount, premium, and expense, net pursuant to an APSC
order. See Note 3 to the financial statements under "Retail Rate Adjustment
Procedures" for additional details. The decline in net interest charges in 1994
by $23 million (9.0 percent) reflects the benefits from refinancing.
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 energy sales growth to a less regulated more
competitive environment.
Future earnings in the near term will depend upon growth in electric sales,
which are subject to a number of factors. Traditionally, these factors have
included weather, competition, changes in contracts with neighboring utilities,
energy conservation practiced by customers, the elasticity of demand, and the
rate of economic growth in the company's service area. However, the Energy
Policy Act of 1992 (Energy Act) is beginning to have a dramatic 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 positioning the business to meet the challenge of this
major change in the traditional practice 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. This enhances 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.
Also, electricity sales for resale rates are being driven down by wholesale
transmission access and numerous potential new energy suppliers, including power
II-56
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 1995 Annual Report
marketers and brokers. The company is aggressively working to maintain and
expand its share of wholesale sales in the Southeastern power markets.
Although the Energy Act does not require transmission access to retail
customers, retail wheeling initiatives are rapidly evolving and becoming very
prominent issues in several states. New federal legislation is being discussed,
and legislation allowing customer choice has already been introduced in Florida
and Georgia. In order to address these initiatives, numerous questions must be
resolved, with the most complex ones relating to transmission pricing and
recovery of stranded investments. As the initiatives become a reality, the
structure of the utility industry could radically change. Therefore, unless the
company remains a low-cost producer and provides quality service, the company's
retail energy sales growth could be limited, and this could significantly erode
earnings. Conversely, being the low-cost producer could provide significant
opportunities to increase market share and profitability by seeking new markets
that evolve with the changing regulation.
The addition of four combustion turbine generating units in 1996 will
increase related operation and maintenance expenses and depreciation expenses.
These additions are to ensure reliable service to its customers during critical
peak times.
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. In June 1995, the APSC issued an order granting
the company's request for gradual adjustments to move toward parity among
customer classes. This order also calls for a moratorium on any periodic retail
rate increases (but not decreases) until 2001.
In December 1995, the APSC issued an order authorizing the company to reduce
balance sheet items
-- such as plant and deferred charges -- at any time the company's actual base
rate revenues exceed the budgeted revenues. See Note 3 to the financial
statements for information about this and other regulatory matters.
The staff of the Securities and Exchange Commission has questioned certain
of the current accounting practices of the electric utility industry --
including the company -- regarding the recognition, measurement, and
classification of decommissioning costs for nuclear generating facilities in the
financial statements. In response to these questions, the Financial Accounting
Standards Board (FASB) has decided to review the accounting for liabilities
related to closure and removal of long-lived assets, including nuclear
decommissioning. If the FASB issues new accounting rules, the estimated costs of
closing and removing the company's nuclear and other facilities may be required
to be recorded as liabilities in the Balance Sheets. Also, the annual provisions
for such costs could increase. Because of the company's current ability to
recover closure and removal costs through rates, these changes should not have a
significant adverse effect on results of operations. See Note 1 to the financial
statements under "Depreciation and Nuclear Decommissioning" for additional
information.
Compliance costs related to the Clean Air Act Amendments of 1990 (Clean Air
Act) could affect earnings if such costs are not fully recovered. The Clean Air
Act and other important environmental items are discussed later under
"Environmental Matters."
The company is subject to the provisions of FASB Statement No. 71,
Accounting for the Effects of Certain Types of Regulation. In the event that a
portion of the company's operations is no longer subject to these provisions,
the company would be required to write off related regulatory assets and
liabilities, and determine if any other assets have been impaired. See Note 1 to
the financial statements under "Regulatory Assets and Liabilities" for
additional information.
New Accounting Standards
The FASB has issued Statement No. 121, Accounting for the Impairment of
Long-Lived Assets and Long-Lived Assets to be Disposed of. This statement
requires that long-lived assets be reviewed for impairment whenever events or
changes in circumstances indicate that the carrying amount for an asset may not
be recoverable. This statement also imposes stricter criteria for regulatory
assets by requiring that such assets be probable of future recovery at each
balance sheet date. The company adopted the new rules January 1, 1996, with no
material effect on the financial statements. However, this conclusion may change
in the future as competitive factors influence wholesale and retail pricing in
the utility industry.
II-57
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 1995 Annual Report
FINANCIAL CONDITION
Overview
The company's financial condition remained stable in 1995. This stability is the
continuation over recent years of growth in energy sales and cost control
measures 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.
The company had gross property additions of $552 million in 1995. The
majority of funds needed for gross property additions for the last several years
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.
Capital Structure
The company's ratio of common equity to total capitalization -- including
short-term debt -- was 45.0 percent in 1995, compared with 45.9 percent in 1994,
and 46.5 percent in 1993.
In 1995, the company issued through public authorities, $131.5 million of
pollution control revenue refunding bonds. Composite financing rates as of
year-end for 1993 through 1995 were as follows:
1995 1994 1993
--------------------------------
Composite interest rate on
long-term debt 7.02% 7.39% 7.35%
Composite dividend rate on
preferred stock 6.04% 6.23% 5.80%
----------------------------------------------------------------
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 $491 million for 1996, $446 million for
1997, and $479 million for 1998. The total is $1.4 billion for the three years.
Actual capital costs may vary from this estimate because of factors such as
changes in business conditions; revised load growth projections; changes in
environmental regulations; changes in the existing nuclear plant to meet new
regulatory requirements; increasing cost of labor, equipment, and materials; and
cost of capital. In addition, there can be no assurance that costs related to
capital expenditures will be fully recovered.
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 addition of combustion
turbine peaking units of approximately 320 megawatts of capacity is planned in
1996 to meet increased peak-hour demands. In addition, significant construction
of transmission and distribution facilities and upgrading of generating plants
will continue.
Other Capital Requirements
In addition to the funds needed for the capital budget, approximately $110
million will be required by the end of 1998 for maturities of first mortgage
bonds. Also, the company will continue to retire higher-cost debt and preferred
stock and replace these obligations with lower-cost capital if market conditions
permit.
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 -- has significantly
impacted the Southern electric system. Specific reductions in sulfur dioxide and
nitrogen oxide emissions from fossil-fired generating plants are required in two
phases. Phase I compliance began in 1995 and affected 28 generating units in the
Southern electric system. As a result of The Southern Company's compliance
strategy, an additional 22 generating units were brought into compliance with
Phase I requirements. Phase II compliance is required in 2000, and all
fossil-fired generating plants will be affected.
II-58
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 1995 Annual Report
In 1995, the Environmental Protection Agency (EPA) began issuing annual
sulfur dioxide emission allowances through the allowance trading program. An
emission allowance is the authority to emit one ton of sulfur dioxide during a
calendar year. The method for issuing 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 Southern Company's sulfur dioxide compliance strategy is
designed to use allowances as a compliance option.
The Southern Company achieved Phase I sulfur dioxide compliance at the
affected plants by switching to low-sulfur coal, which required some equipment
upgrades. This compliance strategy resulted in unused emission allowances being
banked for later use. Compliance with nitrogen oxide emission limits was
achieved by the installation of new control equipment at 22 of the original 28
affected generating units. Construction expenditures for Phase I compliance
totaled approximately $320 million through 1995 for The Southern Company, of
which the company's portion was approximately $32 million.
For Phase II 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 Phase II limits.
Therefore, during the period 1996 to 2000, current compliance strategy could
require total estimated construction expenditures of approximately $150 million
for The Southern Company, of which the company's portion is approximately $96
million. However, the full impact of Phase II compliance cannot now be
determined with certainty, pending the continuing 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 1 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 Title IV of the Clean Air Act. Compliance costs
include construction expenditures, increased costs for switching to low-sulfur
coal, and costs related to emission allowances.
A significant portion of costs related to the acid rain provision of the
Clean Air Act is expected to be recovered through existing ratemaking
provisions. However, 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 EPA is scheduled to submit a report
to Congress on the results of this study during 1996. The report will include 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 is evaluating the need to revise the ambient air quality standards
for particulate matter 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 1996, the EPA may 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
II-59
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 1995 Annual Report
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. The company
conducts studies to determine the extent of any required cleanup costs and has
recognized in the financial statements costs to clean up known sites.
Several major pieces of environmental legislation are being considered for
reauthorization or amendment by Congress. These include: the Clean Air Act; the
Clean Water Act; the Comprehensive Environmental Response, Compensation, and
Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances
Control Act; and the Endangered Species 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 additional 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 exists for
liability as the result of lawsuits alleging damages caused by electromagnetic
fields.
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. In 1994, the company also established an external trust fund for
postretirement benefits as ordered by the APSC. 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."
II-60
II-61
II-62
II-63
II-64
II-65
II-66
NOTES TO FINANCIAL STATEMENTS
Alabama Power Company 1995 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING
POLICIES
General
Alabama Power Company (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 Communications Services (Southern Communications),
Southern Electric International (Southern Electric), Southern Nuclear Operating
Company (Southern Nuclear), The Southern Development and Investment Group
(Southern Development), and other direct and indirect subsidiaries. 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 subsidiary companies. Southern
Communications provides digital wireless communications services to the
operating companies and also markets these services to the public within the
Southeast. Southern Electric designs, builds, owns and operates power production
and delivery 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. Southern Development develops new business
opportunities related to energy products and services.
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 Alabama Public Service
Commission (APSC). The company follows generally accepted accounting principles
and complies with the accounting policies and practices prescribed by the
respective regulatory commissions. The preparation of financial statements in
conformity with generally accepted accounting principles requires the use of
estimates, and the actual results may differ from those estimates.
Regulatory Assets and Liabilities
The company is subject to the provisions of Financial Accounting Standards Board
(FASB) Statement No. 71, Accounting for the Effects of Certain Types of
Regulation. Regulatory assets represent probable future revenues to the company
associated with certain costs that are expected to be recovered from customers
through the ratemaking process. Regulatory liabilities represent probable future
reductions in revenues associated with amounts that are to be credited to
customers through the ratemaking process. Regulatory assets and (liabilities)
reflected in the Balance Sheets at December 31 relate to:
1995 1994
-----------------------
(in thousands)
Deferred income taxes $436,837 $451,886
Premium on reacquired debt 89,967 101,620
Department of Energy assessments 40,282 42,996
Vacation pay 29,458 20,442
Work force reduction costs 48,402 3,664
Deferred income tax credits (386,038) (405,256)
Natural disaster reserve (17,959) (28,750)
Other, net 39,172 45,956
================================================================
Total $280,121 $232,558
================================================================
In the event that a portion of the company's operations is no longer subject
to the provisions of Statement No. 71, the company would be required to write
off related regulatory assets and liabilities. In addition, the company would be
required to determine any impairment to other assets, including plant, and write
down the assets, if impaired, to their fair value.
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.
II-67
NOTES (continued)
Alabama Power Company 1995 Annual Report
The company has a diversified base of customers. No single customer or
industry comprises 10 percent or more of revenues. In 1995, uncollectible
accounts continued to average less than 1 percent of revenues.
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 $54
million in 1995, $65 million in 1994, and $62 million in 1993. The company has a
contract with the U.S. Department of Energy (DOE) that provides for the
permanent disposal of spent nuclear fuel. Although disposal was scheduled to
begin in 1998, 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
estimates its remaining liability at December 31, 1995, under this law to be
approximately $40 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
3.2 percent in 1995 and 1994, and 3.3 percent in 1993. 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 and removal of other facilities.
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. The company
has established external trust funds to comply with the NRC's regulations.
Amounts previously recorded in internal reserves are being transferred into the
external trust funds over set periods of time as approved by the APSC. 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 amounts prescribed by the NRC.
Site study cost is the estimate to decommission the facility as of the
site study year, and ultimate cost is the estimate to decommission the facility
as of retirement date. The estimated costs of decommissioning -- both site study
costs and ultimate costs -- at December 31, 1995, for Plant Farley were as
follows:
Plant
Farley
----------------
Site study basis (year) 1993
Decommissioning periods:
Beginning year 2017
Completion year 2029
-----------------------------------------------------------
(in millions)
Site study costs:
Radiated structures $ 489
Non-radiated structures 89
===========================================================
Total $ 578
===========================================================
(in millions)
Ultimate costs:
Radiated structures $ 1,504
Non-radiated structures 274
===========================================================
Total $ 1,778
===========================================================
II-68
NOTES (continued)
Alabama Power Company 1995 Annual Report
(in millions)
Amount expensed in 1995 $ 18
-----------------------------------------------------------
Accumulated provisions:
Balance in external trust funds $108
Balance in internal reserves 49
===========================================================
Total $157
===========================================================
Assumed in ultimate costs:
Inflation rate 4.5%
Trust earning rate 7.0
-----------------------------------------------------------
Annual provisions for nuclear decommissioning are based on an annuity --
sinking fund -- method as approved by the APSC. The decommissioning costs
approved for ratemaking are $578 million for Plant Farley.
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 changes in the assumed date of
decommissioning, changes in NRC requirements, or changes in the assumptions used
in making estimates.
Income Taxes
The company uses the liability method of accounting for deferred income taxes
and 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.
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 was 7.1 percent in 1995, 7.9 percent in 1994, and 7.8 percent in 1993.
AFUDC, net of income tax, as a percent of net income after dividends on
preferred stock was 1.7 percent in 1995 and 1.5 percent in both 1994 and 1993.
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.
Financial Instruments
In accordance with FASB Statement No. 107, Disclosure About Fair Value of
Financial Instruments, the company's only financial instrument for which the
carrying amount did not approximate fair value at December 31 was as follows:
Long-Term Debt
-------------------------
Carrying Fair
Year Amount Value
----------- ----------
(in millions)
1995 $2,451 $2,577
1994 2,446 2,323
------------------------------------------------------------
The fair value for long-term debt was based on either closing market price
or closing price 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.
Natural Disaster Reserve
In September 1994, in response to a request by the company, the APSC issued an
order allowing the company to establish a Natural Disaster Reserve. As of
December 31, 1995, the accumulated provision amounted to $18.0 million. This
balance is down from the December 31, 1994 balance of $28.8 million, due to
charges related primarily to Hurricane Opal, somewhat offset by a $10 million
accrual to partially replenish the reserve. Regulatory treatment allows the
II-69
NOTES (continued)
Alabama Power Company 1995 Annual Report
company to accrue $250 thousand per month, until the maximum accumulated
provision of $32 million is attained. However, in December 1995, the APSC
approved higher accruals to restore the reserve to its authorized level whenever
the balance in the reserve declines below $22.4 million.
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 one of the
following formulas: years of service and final average pay or years of service
and a flat-dollar benefit. Primarily, 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 trusts 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. Amounts funded are primarily invested in debt and
equity securities. In December 1993, the APSC issued an accounting policy
statement which requires the company to externally fund net annual
postretirement benefits.
FASB Statement No. 106, Employers' Accounting for Postretirement Benefits
Other Than Pensions, 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."
Funded Status and Cost of Benefits
The following tables show actuarial results and assumptions for pension and
postretirement insurance benefits as computed under the requirements of
Statement Nos. 87 and 106, respectively. The funded status of the plans at
December 31 was as follows:
Pension
-----------------------
1995 1994
------------- ---------
(in millions)
Actuarial present value of
benefit obligations:
Vested benefits $ 604 $ 522
Non-vested benefits 25 18
------------------------------------------------------------------
Accumulated benefit obligation 629 540
Additional amounts related to
projected salary increases 173 174
------------------------------------------------------------------
Projected benefit obligation 802 714
Less:
Fair value of plan assets 1,256 1,059
Unrecognized net gain (331) (251)
Unrecognized prior service cost 21 23
Unrecognized transition asset (45) (51)
------------------------------------------------------------------
Prepaid asset recognized in the
Balance Sheets $ 99 $ 66
==================================================================
Postretirement
Benefits
----------------------
1995 1994
----------------------
(in millions)
Actuarial present value of
benefit obligation:
Retirees and dependents $ 103 $ 96
Employees eligible to retire 31 22
Other employees 104 119
-----------------------------------------------------------
Accumulated benefit obligation 238 237
Less:
Fair value of plan assets 89 61
Unrecognized net loss 23 -
Unrecognized transition
obligation 72 120
-----------------------------------------------------------
Accrued liability recognized
in the Balance Sheets $ 54 $ 56
===========================================================
In 1995, the system companies announced a cost sharing program for
postretirement benefits. The program establishes limits on amounts the company
will pay to provide future retiree postretirement benefits. This change reduced
the 1995 accumulated postretirement benefit obligation by approximately $41
million.
II-70
NOTES (continued)
Alabama Power Company 1995 Annual Report
The weighted average rates assumed in the actuarial calculations were:
1995 1994 1993
-------------------------------
Discount 7.3% 8.0% 7.5%
Annual salary increase 4.8 5.5 5.0
Long-term return on
plan assets 8.5 8.5 8.5
----------------------------------------------------------
An additional assumption used in measuring the accumulated postretirement
benefit obligation was a weighted average medical care cost trend rate of 9.8
percent for 1995, decreasing gradually to 5.3 percent through the year 2005 and
remaining at that level thereafter. An annual increase in the assumed medical
care cost trend rate of 1 percent would increase the accumulated benefit
obligation as of December 31, 1995, by $20 million and the aggregate of the
service and interest cost components of the net retiree cost by $4 million.
Components of the plans' net income are shown below:
Pension
--------------------------------------------------------------
1995 1994 1993
-----------------------------
(in millions)
Benefits earned during
the year $ 21.2 $ 20.8 $ 20.6
Interest cost on projected
benefit obligation 54.3 51.2 50.4
Actual (return) loss on plan
assets (236.3) 23.5 (146.3)
Net amortization and deferral 136.9 (116.2) 63.3
==============================================================
Net pension income $(23.9) $(20.7) $(12.0)
==============================================================
Of the above net pension income, $(17.1) million in 1995, $(15.7)
million in 1994, and $(8.9) million in 1993 were recorded in operating expenses,
and the remainder was recorded in construction and other accounts.
Postretirement
Benefits
--------------------
1995 1994 1993
--------------------
(in millions)
Benefits earned during the year $ 7 $ 8 $ 7
Interest cost on accumulated
benefit obligation 18 18 16
Amortization of transition
obligation 7 6 6
Actual (return) loss on plan
assets (10) 1 (5)
Net amortization and deferral 5 (4) 2
=============================================================
Net postretirement costs $ 27 $ 29 $ 26
=============================================================
Of the above net postretirement costs recorded, $22.7 million in 1995, $23
million in 1994, and $22 million in 1993 were charged to operating expenses and
the remainder was charged to construction and other accounts.
Work Force Reduction Programs
The company has incurred additional costs for work force reduction programs. The
costs related to these programs were $14.3 million, $8.2 million and $16.1
million for the years 1995, 1994 and 1993, respectively. In addition, certain
costs of these programs were deferred and are being amortized in accordance with
regulatory treatment. The unamortized balance of these costs was $48.4 million
at December 31, 1995.
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.
In June 1995, the APSC issued a rate order granting the company's request
for gradual adjustments to move toward parity among customer classes. This order
II-71
NOTES (continued)
Alabama Power Company 1995 Annual Report
also calls for a moratorium on any periodic retail rate increases (but not
decreases) until July 2001.
In December 1995, the APSC issued an order authorizing the company to reduce
balance sheet items -- such as plant and deferred charges -- at any time the
company's actual base rate revenues exceed the budgeted revenues. In accordance
with this order, the company reduced the unamortized balance of Premium on
reacquired debt by $10 million in 1995.
The ratemaking procedures will remain in effect until the APSC votes to
modify or discontinue them.
FERC Reviews Equity Returns
In May 1991, the FERC ordered that hearings be conducted concerning the
reasonableness of the operating companies' 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
change in the rate of return on common equity that may require refunds as a
result of this proceeding would be substantially for the period beginning in
July 1991 and ending in October 1992.
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.
In August 1994, the FERC instituted another proceeding based on
substantially the same issues as in the 1991 proceeding. The second period under
review for possible refunds was substantially from October 1994 through December
1995. In November 1995, a FERC administrative law judge issued an opinion that
the FERC staff failed to meet its burden of proof, and therefore, no change in
the equity return was necessary. The FERC staff has filed exceptions to the
administrative law judge's opinion, and the matter is pending before the FERC.
If the rates of return on common equity recommended by the FERC staff were
applied to all of the schedules and contracts involved in both proceedings, and
refunds were ordered, the amount of refunds could range up to approximately $120
million at December 31, 1995 for the Southern Company, of which the company's
portion would be approximately $53 million. However, management believes that
rates are not excessive, and that refunds are not justified.
4. CAPITAL BUDGET
The company's capital expenditures are currently estimated to total $491 million
in 1996, $446 million in 1997, and $479 million in 1998. The estimates include
AFUDC of $7 million in 1996, $6 million in 1997, and $9 million in 1998. 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, 1995, 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 320 megawatts is planned to be completed in 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 at
appropriate levels. The amounts available are discussed below. The company may
issue additional long-term debt and preferred stock for the purposes of debt
maturities, redeeming higher-cost securities, and meeting additional capital
requirements.
II-72
NOTES (continued)
Alabama Power Company 1995 Annual Report
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 company's primary sources of external financing are sales of first mortgage
bonds and preferred stock to the public and receipt of additional paid-in
capital from The Southern Company. 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. The company's
coverages are at a level that would permit any necessary amount of security
sales at current interest and dividend rates.
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, 1998. 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 require 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 $353.5 million which expire at various times during 1996 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.
At December 31, 1995, the company had regulatory approval to have
outstanding up to $530 million of short-term borrowings. In February 1996, such
regulatory approval was increased to $750 million.
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 at December 31, 1995, were as follows:
Year Amounts
---- --------------
(in millions)
1996 $ 866
1997 852
1998 853
1999 672
2000 402
2001 - 2013 3,790
=========================================================
Total commitments $7,435
=========================================================
Operating Leases
The company has entered into coal rail car rental agreements with various terms
and expiration dates. At December 31, 1995, estimated minimum rental commitments
for noncancellable operating leases were as follows:
II-73
NOTES (continued)
Alabama Power Company 1995 Annual Report
Year Amounts
---- --------------------
(in millions)
1996 $ 2.8
1997 2.8
1998 2.9
1999 2.9
2000 2.9
2001 and thereafter 56.5
===============================================================
Total minimum payments $70.8
===============================================================
6. 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 which, in
substance, requires payments sufficient to provide for the operating expenses,
taxes, interest expense and a return on equity, whether or not SEGCO has any
capacity and energy available. The company's share of expenses totaled $71
million in 1995, $74 million in 1994 and $86 million in 1993, and is included in
"Purchased power from affiliates" in the Statements of Income.
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, 1995, the capitalization of SEGCO consisted of $54 million
of equity and $78 million of long-term debt on which the annual interest
requirement is $5.0 million. SEGCO paid dividends totaling $7.6 million in 1995,
$11.6 million in 1994, and $11.3 million in 1993, of which one-half of each was
paid to the company. SEGCO's net income was $8.1 million, $7.2 million, and $8.3
million for 1995, 1994 and 1993, respectively.
The company's percentage ownership and investment in jointly-owned
generating plants at December 31, 1995, 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 Alabama Electric Cooperative, Inc.
Company Accumulated
Facility Investment Depreciation
--------------------- -------------- -----------------
(in millions)
Greene County $ 90 $ 41
Plant Miller
Units 1 and 2 712 281
-------------------------------------------------------------
7. LONG-TERM POWER SALES AGREEMENTS
General
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 area. The
agreements for non-firm capacity expired in 1994. Other agreements -- expiring
at various dates discussed below -- 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 capacity revenues have been as follows:
Unit Other
Year Power Long-Term Total
----------------------------------------------------------
(in millions)
1995 $ 157 $ - $ 157
1994 152 7 159
1993 144 15 159
----------------------------------------------------------
Unit power from Plant Miller is being sold to Florida Power Corporation
(FPC), Florida Power & Light Company (FP&L), Jacksonville Electric Authority
(JEA) and the City of Tallahassee, Florida. Under these agreements,
II-74
NOTES (continued)
Alabama Power Company 1995 Annual Report
approximately 1,200 megawatts of capacity is scheduled to be sold through 1999.
Thereafter, these sales will 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.
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,
1995, $137.5 million of such bonds was 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 resulted in the recording of
additional deferred income taxes and related regulatory assets and liabilities.
At December 31, 1995, the tax-related regulatory assets and liabilities were
$437 million and $386 million, respectively. These assets are attributable to
tax benefits flowed through to customers in prior years and to taxes applicable
to capitalized AFUDC. These liabilities are attributable to deferred taxes
previously recognized at rates higher than current enacted tax law and to
unamortized investment tax credits.
Details of the federal and state income tax provisions are as follows:
1995 1994 1993
--------------------------------
(in thousands)
Total provision for income taxes:
Federal --
Currently payable $166,105 $219,494 $149,680
Deferred --
current year 43,493 (48,153) 9,636
reversal of prior years (15,817) 15,932 19,653
Deferred investment tax
credits (75) (1) (2,106)
----------------------------------------------------------------
193,706 187,272 176,863
----------------------------------------------------------------
State --
Currently payable 18,108 20,565 14,297
Deferred --
current year 5,117 (4,067) 1,898
reversal of prior years (91) 3,676 3,913
----------------------------------------------------------------
23,134 20,174 20,108
----------------------------------------------------------------
Total 216,840 207,446 196,971
Less income taxes credited
to other income (14,142) (16,834) (10,239)
----------------------------------------------------------------
Federal and state income
taxes charged to operations $230,982 $224,280 $207,210
================================================================
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:
II-75
NOTES (continued)
Alabama Power Company 1995 Annual Report
1995 1994
--------------------------------------------------------------
(in millions)
Deferred tax liabilities:
Accelerated depreciation $ 780 $734
Property basis differences 491 513
Premium on reacquired debt 31 38
Fuel clause underrecovered 5 4
Other 37 26
--------------------------------------------------------------
Total 1,344 1,315
--------------------------------------------------------------
Deferred tax assets:
Capacity prepayments 35 36
Other deferred costs 26 27
Postretirement benefits 25 24
Accrued nuclear outage costs - 7
Unbilled revenue 13 13
Other 43 44
--------------------------------------------------------------
Total 142 151
--------------------------------------------------------------
Net deferred tax liabilities 1,202 1,164
Portion included in current assets
(liabilities), net (10) 17
--------------------------------------------------------------
Accumulated deferred income taxes
in the Balance Sheets $1,192 $1,181
==============================================================
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 $12 million in 1995 and $13 million in 1994 and 1993. At December
31, 1995, 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:
1995 1994 1993
--------------------------
Federal statutory rate 35.0% 35.0% 35.0%
State income tax,
net of federal deduction 2.5 2.2 2.3
Non-deductible book
depreciation 1.6 1.6 1.6
Differences in prior years'
deferred and current tax rates (1.8) (2.9) (1.6)
Other (1.4) (0.7) (2.9)
==============================================================
Effective income tax rate 35.9% 35.2% 34.4%
==============================================================
The Southern Company files a consolidated federal income tax return. Under a
joint consolidated income tax agreement, each subsidiary's current and deferred
tax expense is computed on a stand-alone basis. Tax benefits from losses of the
parent company are allocated to each subsidiary based on the ratio of taxable
income to total consolidated taxable income.
9. OTHER LONG-TERM DEBT
Details of other long-term debt at December 31 are as follows:
1995 1994
--------------------------
(in thousands)
Obligations incurred in
connection with the
sale of tax-exempt
pollution control revenue
bonds by public authorities-
Collateralized -
5.5% to 6.5 % due
2023-2024 $223,040 $223,040
Variable rates (5.0% to
6.0% at 1/1/96) due
2015-2017 89,800 89,800
Non-collateralized -
7.25% due 2003 1,000 1,000
7.4% to 9.375% due
2014-2016 21,000 152,500
5.8% due 2022 9,800 9,800
Variable rates (5.3% to
6.0% at 1/1/96) due
2022 131,500 -
-------------------------------------------------------------
476,140 476,140
Capitalized lease obligations 8,963 9,754
=============================================================
Total $485,103 $485,894
=============================================================
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 $312.8 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.
II-76
NOTES (continued)
Alabama Power Company 1995 Annual Report
The company has capitalized certain office building leases and a street light
lease. In December 1994, the company discontinued capital leases pertaining to
nuclear fuel.
The net book value of capitalized leases included in utility plant in service
was $5.6 million and $6.2 million at December 31, 1995 and 1994, respectively.
The estimated aggregate annual maturities of other long-term debt through 2000
are as follows: $0.9 million in 1996, $1.0 million in 1997, $1.0 million in
1998, $1.2 million in 1999 and $1.1 million in 2000.
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 at December 31 is as follows:
1995 1994
----------------------
(in thousands)
Bond improvement fund
requirements $20,047 $ 20,047
Less:
Portion to be satisfied by
certifying property additions - 20,047
------------------------------------------------------------
Cash sinking fund requirements $20,047 $ -
First mortgage bond maturities
and redemptions 63,750 -
Other long-term debt maturities
(Note 9) 885 796
============================================================
Total $84,682 $ 796
============================================================
The annual first mortgage bond improvement fund requirement is 1 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 1996 requirement of $20.0 million was
satisfied by the deposit of cash in 1996. Also in 1996 are first mortgage bond
maturities and redemptions of $64 million and maturities of $885 thousand
consisting primarily of capitalized office building leases and a street light
lease.
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 provides funds up to $8.9 billion for 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 assessment in the event that losses exceed accumulated
reserve funds. The company's maximum annual assessment per incident is limited
to $10 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.
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 $2.8 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
II-77
NOTES (continued)
Alabama Power Company 1995 Annual Report
that policy. The maximum annual assessments per incident under current policies
for the company would be $21 million for excess property damage and $8 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 $6 million.
All retrospective assessments, whether generated for liability, property
or replacement power may be subject to applicable state premium taxes.
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, 1995, retained earnings of $807 million 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 1995 and 1994 are as follows:
Net Income
After
Dividends
Quarter Operating Operating on Preferred
Ended Revenues Income Stock
---------------- ----------------------------------------------
(in thousands)
March 1995 $646,771 $122,949 $ 65,328
June 1995 753,053 157,685 88,926
September 1995 938,284 233,322 167,938
December 1995 686,666 111,362 38,702
March 1994 $686,847 $128,623 $ 72,031
June 1994 759,399 162,696 98,668
September 1994 838,927 199,736 141,214
December 1994 649,969 104,949 44,425
----------------------------------------------------------------
The company's business is influenced by seasonal weather conditions.
II-78
II-79
II-80A
II-80B
II-80C
II-81
II-82A
II-82B
II-82C
II-83
II-84A
II-84B
II-84C
II-85
II-86A
II-86B
II-86C
II-87
II-88A
II-88B
II-88C
II-89
II-90A
II-90B
II-90C
ALABAMA POWER COMPANY
OUTSTANDING SECURITIES AT DECEMBER 31, 1995
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
1991 100,000 9-1/4% 98,748 5/1/21
1991 150,000 8-3/4% 148,500 12/1/21
1992 200,000 8-1/2% 198,000 5/1/22
1992 100,000 8.30% 99,608 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
1994 150,000 9% 150,000 12/1/24
============= ==============
$ 2,005,000 $ 1,999,856
============= ==============
Pollution Control Bonds
Amount Interest Amount
Series Issued Rate Outstanding Maturity
--------------------------------------------------------------------------------
(Thousands) (Thousands)
1978 $ 5,600 7-1/4% $ 1,000 5/1/03
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
1994 24,400 5-1/2% 24,400 1/1/24
1994 53,700 Variable 53,700 6/1/15
1994 101,650 6-1/2% 101,650 9/1/23
1995 50,000 Variable 50,000 5/1/22
1995 81,500 Variable 81,500 10/1/22
============= ==============
$ 480,740 $ 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-91
ALABAMA POWER COMPANY
SECURITIES RETIRED DURING 1995
Pollution Control Bonds
Principal Interest
Series Amount Rate
--------------------------------------------------------------------------------
(Thousands)
1985 $ 50,000 9-3/8%
1985 81,500 9-1/4%
===========
$ 131,500
===========
II-92
GEORGIA POWER COMPANY
FINANCIAL SECTION
II-93
MANAGEMENT'S REPORT
Georgia Power Company 1995 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 six
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, in all
material respects, the financial position, results of operations and cash flows
of Georgia Power Company in conformity with generally accepted accounting
principles.
/s/ H. Allen Franklin
H. Allen Franklin
President and Chief
Executive Officer
/s/ Warren Y. Jobe
Warren Y. Jobe
Executive Vice President, Treasurer and
Chief Financial Officer
February 21, 1996
II-94
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 and wholly owned subsidiary of
The Southern Company) as of December 31, 1995 and 1994, 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, 1995. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements (pages II-104 through II-125)
referred to above present fairly, in all material respects, the financial
position of Georgia Power Company as of December 31, 1995 and 1994, and the
results of its operations and its cash flows for the periods stated, in
conformity with generally accepted accounting principles.
/s/ Arthur Andersen LLP
Atlanta, Georgia
February 21, 1996
II-95
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Georgia Power Company 1995 Annual Report
RESULTS OF OPERATIONS
Earnings
Georgia Power Company's 1995 earnings totaled $609 million, representing an $83
million (15.9 percent) increase over 1994. Earnings for 1994 were reduced by a
$55 million after-tax charge related to work force reduction programs. Excluding
the charge related to the 1994 work force reduction programs, earnings for 1995
increased 4.8 percent over 1994 primarily due to higher retail energy sales and
lower interest charges, partially offset by higher operating expenses. Earnings
for 1994 declined from the prior year not only because of the work force
reduction charge but also because of lower retail energy sales due to mild
weather. The summer of 1993 was exceptionally hot in comparison.
Revenues
The following table summarizes the factors impacting operating revenues for the
1993-1995 period:
Increase (Decrease)
From Prior Year
-----------------------------------
1995 1994 1993
-----------------------------------
Retail - (in millions)
Sales growth $110 $ 67 $ 45
Weather 69 (128) 126
Fuel cost recovery 66 (35) 76
Demand-side programs 36 (12) 15
-----------------------------------------------------------------
Total retail 281 (108) 262
------------------------------------------------------------------
Sales for resale -
Non-affiliates (61) (183) (106)
Affiliates 16 (1) (6)
------------------------------------------------------------------
Total sales for resale (45) (184) (112)
------------------------------------------------------------------
Other operating revenues 7 3 4
------------------------------------------------------------------
Total operating revenues $243 ($289) $154
------------------------------------------------------------------
Percent change 5.8% (6.5)% 3.6%
------------------------------------------------------------------
Retail revenues of $4.0 billion in 1995 increased $281 million (7.6 percent)
over the prior year, compared with a decrease of $108 million (2.8 percent) in
1994. Sales growth, reflecting continued expansion of Georgia's economy, and the
hot summer of 1995, compared to the milder-than-normal weather during the summer
of 1994, were the primary reasons for the increase in retail revenues. Retail
revenues were down in 1994 from the prior year primarily due to hot summer
weather in 1993.
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 option programs generally represent the direct
recovery of program costs. See Note 3 to the financial statements under
"Demand-Side Conservation Programs" for further information on these programs.
Revenues from sales to non-affiliated utilities decreased in both 1995 and
1994. 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:
1995 1994 1993
-------------------------------
(in millions)
Capacity $53 $ 84 $152
Energy 45 82 113
--------------------------------------------------------------
Total $98 $166 $265
==============================================================
Contractual unit power sales to Florida utilities for 1995 and 1994 are down
primarily due to scheduled reductions that corresponded with the sales to these
utilities of portions of Plant Scherer Unit 4 in June 1995 and June 1994. The
amount of capacity under these contracts declined by 155 megawatts and 427
megawatts in 1995 and 1994, respectively. In 1996, the contracted capacity will
decline another 75 megawatts.
Sales to municipalities and cooperatives in Georgia increased in 1995 due to
higher summer demand resulting from the hot weather; however, such sales
decreased in 1994 as these customers retained more of their own generation at
jointly owned facilities, and as a result of a new agreement with territorial
wholesale customers.
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.
II-96
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1995 Annual Report
Kilowatt-hour (KWH) sales for 1995 and the percent change by year were as
follows:
Percent Change
----------------------------
1995
KWH 1995 1994 1993
----------------------------------------
(in billions)
Residential 17.3 10.4% (5.8)% 11.5%
Commercial 19.8 5.9 2.5 5.9
Industrial 25.3 3.9 3.0 2.9
Other 0.5 2.0 5.0 5.7
-------
Total retail 62.9 6.2 0.4 6.1
-------
Sales for resale -
Non-affiliates 6.6 (17.3) (44.3) (9.8)
Affiliates 2.8 (10.4) 0.9 (8.8)
-------
Total sales for resale 9.4 (15.4) (36.4) (9.7)
-------
Total sales 72.3 2.8 (8.0) 2.1
=======
-----------------------------------------------------------------
Residential, commercial and industrial energy sales growth in 1995 reflected
continued expansion of Georgia's economy, hot summer weather, and an increase in
customers served. The 1994 sales decline in the residential class was primarily
the result of milder-than-normal summer weather in 1994. However in 1994,
industrial and commercial sales were positively impacted by continued
improvement in economic conditions. Assuming normal weather, sales to retail
customers are projected to grow approximately 2 percent annually on average
during 1996 through 1998.
Expenses
Fuel costs constitute 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. The amount and sources of generation and the average cost of
fuel per net kilowatt-hour generated were as follows:
1995 1994 1993
---------------------------
Total generation
(billions of kilowatt-hours) 64 62 64
Sources of generation
(percent) --
Coal 73.7 74.8 76.9
Nuclear 22.6 21.9 20.0
Hydro 3.0 3.1 2.8
Oil and gas 0.7 0.2 0.3
Average cost of fuel per net
kilowatt-hour generated
(cents) --
Coal 1.67 1.67 1.75
Nuclear 0.60 0.63 0.58
Oil and gas * * *
Total 1.44 1.44 1.52
---------------------------------------------------------------
* Not meaningful because of minimal generation from
fuel source.
Fuel expense increased 3.5 percent in 1995 because of higher generation
which stemmed from greater demand. Fuel expense decreased 8.5 percent in 1994
due to lower fuel costs, lower generation, and the displacement of coal-fired
generation with lower cost nuclear generation.
Purchased power expense has decreased significantly since 1993, reflecting
declining contractual capacity purchases from the co-owners of Plant Vogtle.
Purchased power expense decreased $36 million in 1995 and $156 million in 1994.
The declines in 1995 and 1994 also resulted from decreased purchases from
affiliated companies, and in 1994 from decreased energy purchases from
territorial wholesale customers. The declines in Plant Vogtle contractual
capacity purchases did not have a significant impact on earnings in 1995 and
1994 since these costs are being levelized over six years under the terms of the
1991 Georgia Public Service Commission
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1995 Annual Report
(GPSC) retail rate order. The levelization is reflected in the amortization of
deferred Plant Vogtle costs in the Statements of Income. See Note 3 to the
financial statements under "Plant Vogtle Phase-In Plans" for additional
information.
The Company has incurred expenses for separation benefits associated with
its work force reduction programs. These expenses were $11 million in 1995 and
$82 million in 1994.
Other operation and maintenance (O&M) expenses increased 12.2 percent in
1995 primarily as a result of the recognition of costs associated with
demand-side option programs and increased maintenance expenses. The demand-side
option program costs were offset in part by increases in retail revenues. During
1995, the Company expensed an additional $58 million of demand-side option
program and other related costs, as compared to 1994, of which approximately $29
million was not collected through rate riders. See Note 3 to the financial
statements under "Demand-Side Conservation Programs" for additional information
on the recovery of these program costs. Other O&M expenses decreased 4.5 percent
in 1994 primarily due to environmental remediation costs at various sites of $32
million in 1993 compared to $8 million in 1994; recognition in 1993 of the
one-time cost of an automotive fleet reduction program; and lower maintenance
and pension costs during 1994.
Depreciation and amortization increased $43 million in 1995 primarily due to
additional plant investment, accelerated amortization of software costs, and an
increase in nuclear decommissioning expenses.
Taxes other than income taxes increased 5.2 percent in 1995 and 1.0 percent
in 1994, reflecting primarily higher ad valorem taxes and in 1995, higher
franchise taxes paid to municipalities as a result of increased sales.
Income tax expense fluctuates directly with earnings.
Other income (expense), net decreased in 1995 primarily due to an increase
in charitable contributions.
Interest expense decreased $51 million (14.6 percent) and $61 million (14.7
percent) in 1995 and 1994, respectively, due primarily to refinancing of
long-term debt. The Company refinanced $505 million and $510 million of
securities in 1995 and 1994, respectively. The Company also retired $264 million
of long-term debt with the proceeds from the 1995 and 1994 Plant Scherer Unit 4
sales. Other interest charges in 1993 include interest related to the settlement
of an Internal Revenue Service (IRS) audit.
The settlement had no 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 including energy sales and regulatory matters.
Beginning January 1, 1996, the Company will operate under a three-year
retail rate plan. The plan, which was approved by the GPSC on February 16, 1996,
concludes a GPSC review of the Company's earnings and addresses an alternative
rate plan proposed by the Company. Under the plan, the Company's earnings will
be evaluated against a retail return on common equity range of 10 percent to
12.5 percent. Earnings in excess of 12.5 percent will be used to accelerate the
amortization of regulatory assets or depreciation of electric plant. At its
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1995 Annual Report
option, the Company may also recognize accelerated amortization or depreciation
of assets within the allowed return on common equity range. The Company is
required to absorb cost increases of approximately $29 million annually during
the plan's three-year operation, including $14 million annually of accelerated
depreciation of electric plant. During the plan's operation, the Company will
not file for a general base rate increase unless its projected retail return on
common equity falls below 10 percent. Under the approved plan, on July 1, 1998
the Company will make a general rate case filing in response to which the GPSC
would be expected either to continue the rate plan or adopt a different one.
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 1996 through 1998.
The addition of four combustion turbine generating units and the Rocky
Mountain pumped storage hydroelectric plant in 1995 and the scheduled addition
of one jointly owned combustion turbine unit in 1996, will increase related O&M
and depreciation expenses. In addition, the Company has entered into a four-year
purchase power agreement to meet peaking needs whereby the Company will purchase
400 megawatts of capacity beginning in 1996 and declining to 200 megawatts of
capacity in 1998. Capacity payments are projected to be $6 million in 1996 and
1997 and $3 million in 1998 and 1999. The Company has also entered into a
30-year purchase power agreement whereby the Company will buy electricity during
peak periods from a planned 300 megawatt cogeneration facility starting in June
1998. Capacity and fixed O&M payments are projected to be $13 million in 1998.
Work force reduction programs implemented in 1994 and 1995 will assist in
efforts to control growth in future operating expenses.
As discussed in Note 3 to the financial statements, regulatory uncertainties
exist related to the Rocky Mountain pumped storage hydroelectric plant. In the
event the GPSC does not allow full recovery of the plant's costs, then the
portion not allowed may have to be written off. The Company's net investment in
the plant is approximately $190 million.
See Note 3 to the financial statements for information regarding proceedings
with respect to the Company's recovery of demand-side conservation program
costs.
During 1995, the Company sold its remaining interest in Unit 4 of Plant
Scherer to two Florida utilities. This transaction coincided with scheduled
reductions in capacity revenues from Florida utilities under contractual unit
power sales contracts of approximately $22 million in 1995 and an additional $7
million in 1996. See Notes 6 and 7 to the financial statements for additional
information.
During 1994 and 1995, Oglethorpe Power Corporation (OPC) gave the Company
notice of its intent to decrease its purchases of capacity under a power supply
agreement by 250 megawatts in September 1996 and an additional 250 megawatts in
September 1997. As a result, the Company's capacity revenues from OPC will
decline approximately $8 million in 1996, an additional $25 million in 1997, and
an additional $18 million in 1998.
OPC and the Municipal Electric Authority of Georgia (MEAG) have filed joint
complaints in two separate venues seeking to recover from the Company
approximately $16.5 million in alleged overcharges, plus approximately $6.3
million in interest. See Note 3 to the financial statements under "Wholesale
Litigation" for further discussion of this matter.
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.
Compliance costs related to the Clean Air Act Amendments of 1990 (Clean Air
Act) could affect earnings if such costs are not fully recovered. The Clean Air
II-99
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1995 Annual Report
Act and other environmental issues are discussed later under "Environmental
Issues."
The Energy Policy Act of 1992 (Energy Act) is beginning to have a dramatic
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 posturing the business to meet the challenge of this
major change in the traditional practice 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. This enhances 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.
Also, electricity sales for resale rates are being driven down by wholesale
transmission access and numerous potential new energy suppliers, including power
marketers and brokers. The Company is aggressively working to maintain and
expand its share of wholesale sales in the Southeastern power markets. Although
the Energy Act does not require transmission access to retail customers, retail
wheeling initiatives are rapidly evolving and becoming very prominent issues in
several states. New federal legislation is being discussed and legislation
allowing customer choice has been introduced in Georgia. In order to address
these initiatives, numerous questions must be resolved with the most complex
ones relating to transmission pricing and recovery of stranded investments. As
the initiatives become a reality, the structure of the utility industry could
radically change. Therefore, unless the Company remains a low-cost producer and
provides quality service, the Company's retail energy sales growth could be
limited, and this could significantly erode earnings. Conversely, being the
low-cost producer could provide significant opportunities to increase market
share and profitability.
The Company continues to compete with other electric suppliers within the
state. In Georgia, most new retail customers with at least 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 Company is subject to the provisions of Financial Accounting Standards
Board (FASB) Statement No. 71, Accounting for the Effects of Certain Types of
Regulation. In the event that a portion of the Company's operations is no longer
subject to these provisions, the Company would be required to write off related
regulatory assets and liabilities, and determine if any other assets have been
impaired. See Note 1 to the financial statements under "Regulatory Assets and
Liabilities" for additional information.
The staff of the Securities and Exchange Commission has questioned certain
of the current accounting practices of the electric utility industry --
including the Company -- regarding the recognition, measurement, and
classification of decommissioning costs for nuclear generating facilities in the
financial statements. In response to these questions, the FASB has decided to
review the accounting for liabilities related to closure and removal of
long-lived assets, including nuclear decommissioning. If the FASB issues new
accounting rules, the estimated costs of closing and removing the Company's
nuclear and other facilities may be required to be recorded as liabilities in
the Balance Sheets. Also, the annual provisions for such costs could increase.
Because of the Company's current ability to recover closure and removal costs
through rates, these changes would not have a significant adverse effect on
results of operations. See Note 1 to the financial statements under
"Depreciation and Nuclear Decommissioning" for additional information.
New Accounting Standards
The FASB has issued Statement No. 121, Accounting for the Impairment of
Long-Lived Assets and Long-Lived Assets to Be Disposed Of. This statement
requires that long-lived assets be reviewed for impairment whenever events or
changes in circumstances indicate that the carrying amount of an asset may not
be recoverable. This statement also imposes stricter criteria for regulatory
assets by requiring that such assets be probable of future recovery at each
balance sheet date. The Company adopted this standard January 1, 1996 with no
material effect on the financial statements. However, this conclusion may change
in the future as competitive factors influence wholesale and retail pricing in
this industry.
II-100
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1995 Annual Report
FINANCIAL CONDITION
Overview
The principal changes in the Company's financial condition in 1995 were gross
utility plant additions of $480 million, which included the commercial operation
of four combustion turbine units (cumulatively, 320 megawatts of capacity) and
all three units of the Rocky Mountain pumped storage hydroelectric plant (the
Company's ownership interest is approximately 70 megawatts of capacity per
unit). In addition, the cost of capital was lowered through the refinancing or
retirement of $1.0 billion of long-term debt.
The funds needed for gross property additions are currently provided from
operations. The Statements of Cash Flows provide additional details.
Financing Activities
In 1995, the Company continued to lower its financing costs by refinancing
higher-cost issues. New issues during 1993 through 1995 totaled $2.7 billion and
retirement or repayment of securities totaled $3.4 billion. The retirements
included the redemption of $131 million, $133 million, and $253 million in 1995,
1994, and 1993, respectively, of first mortgage bonds with the proceeds from the
Plant Scherer Unit 4 sales. Composite financing rates for long-term debt and
preferred stock for the years 1993 through 1995, as of year-end, were as
follows:
1995 1994 1993
---------------------------------
Composite interest rate
on long-term debt 6.57% 7.14% 7.86%
Composite preferred
stock dividend rate 6.73 7.11 6.76
----------------------------------------------------------------
The Company's current securities ratings are as follows:
Duff & Standard &
Phelps Moody's Poor's
------------------------------------
First Mortgage Bonds AA- A1 A+
Preferred Stock A a2 A
Unsecured Bonds A+ A2 A
Commercial Paper D1+ P1 A1
-----------------------------------------------------------------
Liquidity and Capital Requirements
Cash provided from operations increased by $281 million in 1995, primarily due
to increased revenues and a decrease in interest payments.
The Company estimates that construction expenditures for the years 1996
through 1998 will total $530 million, $537 million and $529 million,
respectively. Investments in transmission and distribution facilities,
enhancements to existing generating plants, and additions of a combustion
turbine generating plant and equipment to comply with the provisions of the
Clean Air Act are planned.
Cash requirements for sinking fund requirements, redemptions announced, and
maturities of long-term debt are expected to total $283 million during 1996
through 1998.
As a result of requirements by the Nuclear Regulatory Commission, the
Company has established external trust funds for the purpose of funding nuclear
decommissioning costs. For 1996 through 1998, the amount to be funded totals $24
million annually. For additional information concerning nuclear decommissioning
costs, see Note 1 to the financial statements under "Depreciation and Nuclear
Decommissioning."
As a result of the Energy Policy Act of 1992, the Company is required to pay
a special assessment over a 15-year period beginning in 1993 into a fund which
will be used by the U. S. Department of Energy for the decontamination and
decommissioning of its nuclear enrichment facilities. The Company estimates its
remaining liability to be approximately $31 million as of December 31, 1995. See
Note 1 to the financial statements under "Revenues and Fuel Costs" for
additional information.
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 $975 million of unused credit
II-101
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1995 Annual Report
arrangements with banks at the beginning of 1996. See Note 9 to the financial
statements under "Bank Credit Arrangements" for additional information.
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 amended by Congress. Title IV of the
Clean Air Act -- the acid rain compliance provision of the law -- is having a
significant impact on the operating companies of The Southern Company, including
Georgia Power. Specific reductions in sulfur dioxide and nitrogen oxide
emissions from fossil-fired generating plants are required in two phases. Phase
I compliance began in 1995 and initially affected 28 generating units in the
Southern electric system. As a result of The Southern Company's compliance
strategy, an additional 22 generating units were brought into compliance with
Phase I requirements. Phase II compliance is required in 2000, and all
fossil-fired generating plants in the Southern electric system will be affected.
In 1995, the Environmental Protection Agency (EPA) began issuing 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 issuing 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 Southern Company's sulfur dioxide compliance strategy is
designed to use allowances as a compliance option.
The Southern Company achieved Phase I sulfur dioxide compliance at the
affected units by switching to low-sulfur coal, which has required some
equipment upgrades. This compliance strategy resulted in unused emission
allowances being banked for later use. Compliance with nitrogen oxide emission
limits was achieved by the installation of new control equipment at 22 of the
original 28 affected generating units. Construction expenditures for Georgia
Power's Phase I compliance totaled approximately $165 million through 1995.
For Phase II 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. During the period 1996 to 2000, current compliance strategy could
require total estimated Georgia Power construction expenditures of approximately
$45 million. However, the full impact of Phase II compliance cannot now be
determined with certainty, pending the continuing 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 1 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 Title IV of the Clean Air Act.
Compliance costs include construction expenditures, increased costs for
switching to low-sulfur coal, and costs related to emission allowances.
A significant portion of costs related to the acid rain provision of the
Clean Air Act is expected to be recovered through existing ratemaking
provisions. However, 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
-- affecting sources of nitrogen oxides and volatile organic compounds -- to
achieve attainment by 1999. As the required first step, the state 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
II-102
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1995 Annual Report
nitrogen oxide controls, above Title IV requirements, on some of the Company's
plants. The EPA along with 37 states is conducting studies to evaluate the
benefits of regional controls in meeting the ozone standards. Final attainment
rules, based on modeling studies, could require installation of additional
controls for nitrogen oxide emissions to meet the 1999 deadline or as part of
any regional controls if enacted. A decision on new requirements is expected in
1997. Compliance with any new rules could result in significant additional
costs. The actual 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 EPA is scheduled to submit a
report to Congress on the results of this study during 1996. The report will
include 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 is evaluating the need to revise the ambient air quality standards
for particulate matter 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 1996, the EPA may 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. These costs for the Company amounted to $8 million in 1995
and 1994, and $32 million in 1993. Additional sites may require environmental
remediation for which the Company may be liable for a portion of or all required
cleanup costs. See Note 3 to the financial statements under "Certain
Environmental Contingencies" for information regarding the Company's potentially
responsible party status at a site in Brunswick, Georgia and the status of sites
listed on the State of Georgia's hazardous site inventory.
Several major pieces of environmental legislation are being considered for
reauthorization or amendment by Congress. These include: the Clean Air Act; the
Clean Water Act; the Comprehensive Environmental Response, Compensation, and
Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances
Control Act; and the Endangered Species 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 additional 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 exists for liability as the result of
lawsuits alleging damages caused by electromagnetic fields.
II-103
II-104
II-105
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II-109
NOTES TO FINANCIAL STATEMENTS
Georgia Power Company 1995 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), a
system service company, Southern Communications Services (Southern
Communications), Southern Electric International (Southern Electric), Southern
Nuclear Operating Company (Southern Nuclear), The Southern Development and
Investment Group (Southern Development), and other direct and indirect
subsidiaries. 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). SCS provides, at cost, specialized
services to The Southern Company and subsidiary companies. Southern
Communications provides digital wireless communications services to the
operating companies and also markets these services to the public within the
Southeast. Southern Electric designs, builds, owns, and operates power
production and delivery 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. Southern Development develops new business
opportunities related to energy products and services.
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 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
(GAAP) and complies with the accounting policies and practices prescribed by the
respective regulatory commissions. The preparation of financial statements in
conformity with GAAP requires the use of estimates, and the actual results may
differ from these estimates.
Certain prior years' data presented in the financial statements have been
reclassified to conform with current year presentation.
Regulatory Assets and Liabilities
The Company is subject to the provisions of Financial Accounting Standards Board
(FASB) Statement No. 71, Accounting for the Effects of Certain Types of
Regulation. Regulatory assets represent probable future revenues to the Company
associated with certain costs that are expected to be recovered from customers
through the ratemaking process. Regulatory liabilities represent probable future
reductions in revenues associated with amounts that are to be credited to
customers through the ratemaking process. Regulatory assets and (liabilities)
reflected in the Company's Balance Sheets at December 31 relate to the
following:
1995 1994
--------------------
(in millions)
Deferred income taxes $ 872 $ 920
Deferred income tax credits (410) (433)
Deferred Plant Vogtle costs 308 432
Premium on reacquired debt 174 165
Demand-side program costs 79 97
Corporate building lease 49 48
Postretirement benefits 53 41
Vacation pay 36 41
Inventory conversions (31) (39)
Department of Energy assessments 33 36
Other, net 36 52
==============================================================
Total $1,199 $1,360
==============================================================
In the event that a portion of the Company's operations is no longer subject
to the provisions of Statement No. 71, the Company would be required to write
off related regulatory assets and liabilities. In addition, the Company would be
required to determine any impairment to other assets, including plant, and write
down the assets, if impaired, to their fair value.
II-110
NOTES (continued)
Georgia Power Company 1995 Annual Report
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 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.
The Company has a diversified base of customers. No single customer or
industry comprises 10 percent or more of revenues. In 1995, uncollectible
accounts continued to average less than 1 percent of revenues.
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 $86
million in 1995, $87 million in 1994, and $75 million in 1993. 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 2003 at Plant
Hatch and into 2009 at Plant Vogtle.
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 assessment will be paid over a 15-year
period, which began in 1993. The law provides that utilities will recover these
payments in the same manner as any other fuel expense. The Company -- based on
its ownership interests -- estimates its remaining liability under this law at
December 31, 1995, to be approximately $31 million. This obligation is recorded
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
3.2 percent in 1995 and 3.1 percent in 1994 and 1993. See Note 3 under "Retail
Rate Plan" for additional information. 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 and removal of other facilities.
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. The
Company has established external trust funds to comply with the NRC's
regulations. Amounts previously recorded in internal reserves are being
transferred into the external trust funds over a set period of time as approved
by the GPSC. Earnings on the trust funds are considered in determining
decommissioning expense. 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 amounts prescribed by
the NRC.
The site study cost is the estimate to decommission the facility as of the
site study year, and ultimate cost is the estimate to decommission the facility
as of the retirement
II-111
NOTES (continued)
Georgia Power Company 1995 Annual Report
date. The estimated costs of decommissioning -- both site study costs and
ultimate costs at December 31, 1995 -- based on the Company's ownership
interests -- were as follows:
Plant Plant
Hatch Vogtle
--------------------
Site study basis (year) 1994 1994
Decommissioning periods:
Beginning year 2014 2027
Completion year 2027 2038
------------------------------------------------------------
(in millions)
Site study costs:
Radiated structures $294 $233
Non-radiated structures 41 52
============================================================
Total $335 $285
============================================================
(in millions)
Ultimate costs:
Radiated structures $781 $1,018
Non-radiated structures 111 230
------------------------------------------------------------
Total $892 $1,248
============================================================
(in millions)
Amount expensed in 1995 $11 $ 9
Accumulated provisions:
Balance in external trust funds $56 $36
Balance in internal reserves 30 13
============================================================
Total $86 $49
============================================================
Significant assumptions:
Inflation rate 4.4% 4.4%
Trust earnings rate 6.0 6.0
------------------------------------------------------------
Annual provisions for nuclear decommissioning are based on an annuity --
sinking fund -- method as approved by the GPSC. The decommissioning costs
included in cost of service are based on the higher of the costs to decommission
the radioactive portions of the plants based on 1994 site studies or the NRC
minimum funding requirements. The Company expects the GPSC to periodically
review and adjust, if necessary, the amounts collected in rates for the
anticipated cost of decommissioning.
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: changes in the assumed date of
decommissioning; changes in NRC requirements; changes in the assumptions used in
making estimates; changes in regulatory requirements; changes in technology; and
changes in costs of labor, materials, and equipment.
Income Taxes
The Company uses the liability method of accounting for deferred income taxes
and 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.
Plant Vogtle Phase-In Plans
In 1987 and 1989, the 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 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.
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. For the years 1995, 1994 and 1993, the average AFUDC rates
were 6.53 percent, 6.18 percent and 4.96 percent, respectively. The increase in
1994 is primarily the result of the higher short-term borrowing rates. AFUDC,
net of taxes, as a percentage of net income after dividends on preferred stock,
was less than 2.5 percent for 1995, 1994, and 1993.
II-112
NOTES (continued)
Georgia Power Company 1995 Annual Report
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 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, the Company's financial instruments for which the
carrying amounts did not approximate fair value at December 31 are as follows:
Carrying Fair
Amount Value
--------------------------
Long-term debt: (in millions)
At December 31, 1995 $3,378 $3,487
At December 31, 1994 3,838 3,697
Preferred Securities:
At December 31, 1995 100 114
---------------------------------------------------------------
The fair values for securities 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.
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 one of the following 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 trusts 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. Qualified trusts are funded to the extent deductible
under federal income tax regulations and to the extent required by the GPSC and
the FERC. During 1995 and 1994, the Company funded $21 million and $22 million,
respectively, to the qualified trusts. Amounts funded are primarily invested in
debt and equity securities.
FASB Statement No. 106, Employers' Accounting for Postretirement Benefits
Other Than Pensions, 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 cost was expensed
in 1993, and the remaining additional costs were 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.
II-113
NOTES (continued)
Georgia Power Company 1995 Annual Report
Funded Status and Cost of Benefits
The following tables show actuarial results and assumptions for pension and
postretirement benefits as computed under the requirements of FASB Statement
Nos. 87 and 106, respectively. The funded status of the plans at December 31 was
as follows:
Pension
---------------------
1995 1994
---------------------
Actuarial present value of (in millions)
benefit obligations:
Vested benefits $ 830 $ 689
Non-vested benefits 43 32
---------------------------------------------------------------
Accumulated benefit obligation 873 721
Additional amounts related
to projected salary increases 290 294
---------------------------------------------------------------
Projected benefit obligation 1,163 1,015
Less:
Fair value of plan assets 1,688 1,419
Unrecognized net gain (465) (371)
Unrecognized prior service cost 26 28
Unrecognized transition asset (52) (58)
===============================================================
Prepaid asset recognized in
the Balance Sheets $ 34 $ 3
===============================================================
Postretirement
Benefits
---------------------
1995 1994
---------------------
(in millions)
Actuarial present value of benefit obligation:
Retirees and dependents $214 $203
Employees eligible to retire 16 7
Other employees 188 229
---------------------------------------------------------------
Accumulated benefit obligation 418 439
Less:
Fair value of plan assets 81 52
Unrecognized net loss (gain) 44 (1)
Unrecognized transition
obligation 186 301
===============================================================
Accrued liability recognized in the
Balance Sheets $107 $ 87
===============================================================
In 1995, the Company announced a cost sharing program for postretirement
benefits. The program establishes limits on amounts the Company will pay to
provide future postretirement benefits. This change reduced the 1995 accumulated
postretirement benefit obligation by approximately $97 million.
The weighted average rates used in actuarial calculations were:
1995 1994 1993
-------------------------------
Discount 7.3% 8.0% 7.5%
Annual salary increase 4.8 5.5 5.0
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 9.8 percent for 1995, decreasing gradually to 5.3 percent through the year
2005 and remaining at that level thereafter. An annual increase in the assumed
medical care cost trend rate of 1 percent would increase the accumulated benefit
obligation as of December 31, 1995, by $39 million and the aggregate of the
service and interest cost components of the net postretirement cost by $8
million.
The components of the plans' net costs are shown below:
Pension
-----------------------------
1995 1994 1993
-----------------------------
(in millions)
Benefits earned during the year $ 33 $ 34 $ 33
Interest cost on projected
benefit obligation 78 71 69
Actual (return) loss on plan assets (317) 35 (194)
Net amortization and deferral 185 (160) 84
================================================================
Net pension cost $ (21) $ (20) $ (8)
================================================================
Net pension costs were negative in 1995, 1994 and 1993. Of net pension
amounts recorded, $15 million in 1995 and 1994, and $6 million in 1993 were
recorded as a
II-114
NOTES (continued)
Georgia Power Company 1995 Annual Report
reduction to operating expense, and the remainder was recorded as a reduction
to construction and other accounts.
Postretirement Benefits
--------------------------
1995 1994 1993
--------------------------
(in millions)
Benefits earned during the year $13 $15 $14
Interest cost on accumulated
benefit obligation 34 33 29
Amortization of transition
obligation 16 15 15
Actual (return) loss on plan
assets (8) 1 (4)
Net amortization and deferral 4 (3) 2
==================================================================
Net postretirement cost $59 $61 $56
==================================================================
Of the above net postretirement benefit costs recorded, $33 million in 1995,
$28 million in 1994, and $21 million in 1993 were charged to operating expenses.
In addition, $11 million in 1995, $18 million in 1994, and $21 million in 1993
were deferred, and the remainder was charged to construction and other accounts.
Work Force Reduction Programs
The Company has incurred additional costs for work force reduction programs. The
costs related to these programs were $11 million and $82 million for the years
1995 and 1994, respectively. Additionally, in 1994, the Company recognized $8
million for its share of costs associated with SCS's work force reduction
program.
3. REGULATORY AND LITIGATION MATTERS
Retail Rate Plan
On February 16, 1996, the GPSC approved a rate plan recommended by the
Commission staff which concludes the GPSC's review of the Company's earnings
initiated in early 1995 and addresses the Company's proposed alternative retail
rate plan. Under the three-year plan effective January 1, 1996, the Company's
earnings will be evaluated against a retail return on common equity range of 10
percent to 12.5 percent. Earnings in excess of 12.5 percent will be used to
accelerate the amortization of regulatory assets or depreciation of electric
plant. At its option, the Company may also recognize accelerated amortization or
depreciation of assets within the allowed return on common equity range. The
Company is required to absorb cost increases of approximately $29 million
annually during the plan's three-year operation, including $14 million annually
of accelerated depreciation of electric plant. During the plan's operation, the
Company will not file for a general base rate increase unless its projected
retail return on common equity falls below 10 percent. Under the approved plan,
on July 1, 1998 the Company will make a general rate case filing in response to
which the GPSC would be expected either to continue the rate plan or adopt a
different one.
Rocky Mountain Plant Status
In its 1985 financing order, the GPSC concluded that completion of the Rocky
Mountain pumped storage hydroelectric plant 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 plant. In
1988, the Company and OPC entered into a joint ownership agreement for OPC to
assume responsibility for the construction and operation of the plant, as
discussed in Note 6. However, full recovery of the Company's costs depends on
the GPSC's treatment of the plant's costs and disposition of the plant's
capacity output. In the event the GPSC does not allow full recovery of the
plant's costs, then the portion not allowed may have to be written off. AFUDC
accrued on the Rocky Mountain plant was not credited to income or included in
the plant's cost since December 1985. In 1995, the plant went into commercial
operation. At December 31, 1995, the Company's net investment in the plant was
approximately $190 million, and the Company's ownership was 25.4 percent.
The final outcome of this matter cannot now be determined. Accordingly, no
provision for any write-down of the investment in the plant has been made.
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 suspended collection of the demand-side conservation
II-115
NOTES (continued)
Georgia Power Company 1995 Annual Report
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 Superior Court's decision is reversed or until the
next general rate case proceedings.
After the Georgia Court of Appeals upheld the legality of the rate riders,
the Company resumed collection under the rate riders in December 1994. In August
1995, the GPSC ordered the Company to discontinue its current demand-side
conservation programs by the end of 1995. The rate riders will remain in effect
until costs deferred are collected.
Under the Retail Rate Plan approved February 16, 1996, the Company will
recognize approximately $29 million of deferred program costs over a three-year
period which will not be recovered through the riders.
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
change in the rate of return on common equity that could potentially require
refunds as a result of this proceeding would be substantially for the period
beginning in July 1991 and ending in October 1992.
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.
In August 1994, the FERC instituted another proceeding based on
substantially the same issues as in the 1991 proceeding. The second period under
review for possible refunds began in October 1994 and ended in December 1995. In
November 1995, a FERC administrative law judge issued an opinion that the FERC
staff failed to meet its burden of proof, and therefore no change in the equity
return was necessary. The FERC staff has filed exceptions to the administrative
law judge's opinion, and the matter remains pending before the FERC.
If the rates of return on common equity recommended by the FERC staff were
applied to all the schedules and contracts involved in both proceedings and
refunds were ordered, the amount of refunds could range up to approximately $49
million at December 31, 1995. However, management believes that rates are not
excessive, and that refunds are not justified.
Certain Environmental Contingencies
In January 1995, the Company and four other unrelated entities were notified by
the EPA that they have been designated as potentially responsible parties under
the Comprehensive Environmental Response, Compensation and Liability Act with
respect to a site in Brunswick, Georgia. As of December 31, 1995, the Company
has recognized $3.5 million in expenses associated with this site. While the
Company believes that the total amount of costs required for the clean up of
this site may be substantial, it is unable at this time to estimate either such
total or the portion for which the Company may ultimately be responsible.
The final outcome of this matter cannot now be determined. However, based on
the nature and extent of the Company's activities relating to the site,
management believes that the Company's portion of these costs should not be
material.
In compliance with the Georgia Hazardous Site Response Act of 1993, the State
of Georgia was required to compile an inventory of all known or suspected sites
where hazardous wastes, constituents or substances have been disposed of or
released in quantities deemed reportable by the State. In developing this list,
the State identified several hundred properties throughout the State, including
24 sites which may require environmental remediation by the Company. The
majority of these 24 sites are electrical power substations and power generation
facilities. The Company has recognized $10 million in expenses through December
31, 1995 for the anticipated clean-up cost for 18 sites that the Company plans
II-116
NOTES (continued)
Georgia Power Company 1995 Annual Report
to remediate. The Company will conduct studies at each of the remaining sites to
determine the extent of remediation and associated clean-up costs, if any, that
may be required. The Company has recognized $2.4 million in expenses for the
anticipated cost of completing such studies. Any cost of remediating the
remaining sites cannot presently be determined until such studies are completed
for each site and the State of Georgia determines whether remediation is
required. If all listed sites were required to be remediated, the Company could
incur expenses of up to approximately $15 million in additional clean-up costs
and construction expenditures of up to approximately $100 million to develop new
waste management facilities or install additional pollution control devices.
Wholesale Litigation
In July 1994, Oglethorpe Power Corporation (OPC) and the Municipal Electric
Authority of Georgia (MEAG) filed a joint complaint with the FERC seeking to
recover from the Company an aggregate of approximately $16.5 million in alleged
partial requirements rates overcharges, plus approximately $6.3 million in
interest. OPC and MEAG claimed that the Company improperly reflected in such
rates costs associated with capacity that had previously been sold to Gulf
States pursuant to a unit power sales contract or, alternatively, that they
should be allocated a portion of the proceeds received by the Company as a
result of a settlement with Gulf States of litigation arising out of such
contract. The Company's response sought dismissal of the complaint by the FERC.
Dismissal was ordered in November 1994. OPC and MEAG filed a request for
rehearing in December 1994, and the FERC denied such request in July 1995. In
September 1995, OPC appealed the FERC's decision on this issue to the Court of
Appeals for the District of Columbia Circuit.
In August 1994, OPC and MEAG also filed a complaint in the Superior Court of
Fulton County, Georgia, urging substantially the same claims and asking the
court to hear the matter in the event the FERC declines jurisdiction. Such court
proceeding was subsequently stayed pending resolution of the FERC filing.
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 amortized these costs (as
recovered through rates) as follows:
1995 1994 1993
-----------------------------
(in millions)
Deferred costs at beginning
of year $432 $507 $383
----------------------------------------------------------------
Deferred capacity buyback
expenses - 10 38
Amortization of previously
deferred costs (124) (85) (74)
----------------------------------------------------------------
Net amortization (124) (75) (36)
----------------------------------------------------------------
Effect of adoption of FASB
Statement No. 109 - - 160
================================================================
Deferred costs at end of year $308 $432 $507
================================================================
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 percent 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
II-117
NOTES (continued)
Georgia Power Company 1995 Annual Report
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. At December 31, 1995,
the remaining amount to be collected was $2.4 million.
4. COMMITMENTS
Construction Program
While the Company has no new baseload generating plants under construction, the
construction of one jointly owned combustion turbine peaking unit is planned to
be completed in 1996. In addition, significant construction of transmission and
distribution facilities, and projects to upgrade and extend the useful life of
generating plants will continue. The Company currently estimates property
additions to be approximately $530 million in 1996, $537 million in 1997, and
$529 million in 1998. These estimated additions include AFUDC of $12 million in
1996, $14 million in 1997, and $15 million in 1998. The estimates for property
additions for the three-year period include $67 million committed to meeting the
requirements of the Clean Air Act.
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.
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 fossil and nuclear fuel commitments at December 31,
1995 were as follows:
Minimum
Year Obligations
----------------------
(in millions)
1996 $ 831
1997 678
1998 534
1999 321
2000 231
2001 through 2010 1,624
===============================================================
Total minimum obligations $4,219
===============================================================
Additional commitments for coal and for nuclear fuel will be required in the
future to supply the Company's fuel needs.
Purchase Power Commitments
In connection with the joint ownership arrangement for Plant Vogtle, discussed
in Note 6, the Company has made commitments to purchase declining fractions of
OPC's and MEAG's capacity and energy from this plant. 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
$76 million, $129 million and $183 million in 1995, 1994, and 1993,
respectively. The current projected Plant Vogtle capacity payments for the next
five years are: $70 million in 1996, $59 million per year in 1997 through 1999,
and $60 million in 2000. 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.
II-118
NOTES (continued)
Georgia Power Company 1995 Annual Report
As discussed in Note 3, the Plant Vogtle declining capacity buyback expense
is being levelized over a six-year period which began in October 1991.
The Company and an affiliate, Alabama 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 1,020 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 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. The term of the contract extends automatically
for two-year periods, subject to either 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 Income, is as follows:
1995 1994 1993
---------------------------------
(in millions)
Energy $44 $43 $60
Capacity 29 33 30
==============================================================
Total $73 $76 $90
==============================================================
Kilowatt-hours 2,391 2,429 3,352
--------------------------------------------------------------
At December 31, 1995, the capitalization of SEGCO consisted of $54 million
of equity and $78 million of long-term debt on which the annual interest
requirement is $5 million.
The Company has entered into a 30-year purchase power agreement, scheduled to
begin in June 1998, for electricity during peaking periods from a planned 300
megawatt cogeneration facility. Payments are subject to reductions for failure
to meet minimum capacity output. Total estimated capacity and fixed operation
and maintenance (O&M) payments are as follows:
Fixed
Year Capacity O&M Total
-----------------------------------------
(in millions)
1998 $ 10 $ 3 $ 13
1999 11 4 15
2000 11 4 15
2001 and beyond 178 157 335
================================================================
Total $210 $168 $378
================================================================
Operating Leases
The Company has entered into coal rail car rental agreements with various terms
and expiration dates. These expenses totaled $12 million, $13 million, and $8
million for 1995, 1994, and 1993, respectively. At December 31, 1995, estimated
minimum rental commitments for noncancelable operating leases were as follows:
Year Amounts
-------------------
(in millions)
1996 $ 11
1997 10
1998 10
1999 10
2000 10
2001 and beyond 126
=========================================================
Total minimum payments $177
=========================================================
5. 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
II-119
NOTES (continued)
Georgia Power Company 1995 Annual Report
occurring at the Company's nuclear power plants. The act provides funds up to
$8.9 billion for 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. The 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, excluding any
applicable state premium taxes, -- based on its ownership and buyback interests
-- is $162 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 assessment in the event that losses exceed accumulated
reserve funds. The Company's maximum annual assessment is limited to $12 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 Insurance
Limited (NEIL), a mutual insurance company.
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 $2.8 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 the current policies for the
Company would be $24 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 $6 million.
All retrospective assessments, whether generated for liability, property or
replacement power, may be subject to applicable state premium taxes.
6. FACILITY SALES AND JOINT OWNERSHIP AGREEMENTS
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; 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 Company, an affiliate.
Additionally, in 1995 the Company completed the last 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 $808 million. FP&L now owns approximately 76.4 percent of the
unit, with JEA owning the remainder.
II-120
NOTES (continued)
Georgia Power Company 1995 Annual Report
The Scherer Unit 4 transactions were as follows:
Closing Date Percent After-Tax
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 16.55 133 11
June 1995 135 16.55 131 12
===============================================================
Total 818 100.00% $808 $55
===============================================================
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 3, the Company owns 25.4 percent of the Rocky Mountain
pumped storage hydroelectric plant, which began commercial operation in 1995.
OPC owns the remainder, and is the operator of the plant.
The Company owns six of eight 80 megawatt combustion turbine generating
units and 75 percent of the related common facilities at Plant McIntosh.
Savannah Electric and Power Company, an affiliate, owns the remainder and
operates the plant. Four of the Company's six units began commercial operation
during 1994, and the remaining two units began commercial operation in 1995.
In 1994, the Company and Florida Power Corporation (FPC) entered into a
joint ownership agreement regarding a 150 megawatt combustion turbine unit to be
constructed at Intercession City, Florida, near Orlando. The unit is scheduled
to begin commercial operation by the end of 1996, and will be constructed,
operated, and maintained by FPC. The Company will have a one-third interest in
the unit, with use of 100 percent of the unit's capacity from June through
September. FPC will have the capacity the remainder of the year. The Company's
investment in the project is expected to be approximately $14 million at
completion.
At December 31, 1995, the Company's percentage ownership and investment
(exclusive of nuclear fuel) in jointly owned facilities in commercial operation,
were as follows:
Total
Nameplate 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
Plant McIntosh
Common Facilities N/A 75.0
(combustion-turbine)
Rocky Mountain 848 25.4
(pumped storage)
-----------------------------------------------------------------
Accumulated
Facility (Type) Investment Depreciation
-----------------------------------------------------------------
(in millions)
Plant Vogtle (nuclear) $3,295* $730
Plant Hatch (nuclear) 842 394
Plant Wansley (coal) 297 132
Plant Scherer (coal)
Units 1 and 2 112 39
Unit 3 541 135
Plant McIntosh
Common Facilities
(combustion-turbine) 19 **
Rocky Mountain
(pumped storage) 200 10
----------------------------------------------------------------
* Investment net of write-offs.
** Less than $1 million.
II-121
NOTES (continued)
Georgia Power Company 1995 Annual Report
7. LONG-TERM POWER SALES AGREEMENTS
The Company and the operating subsidiaries of The Southern Company have
long-term contractual agreements for the sale of capacity and energy to
non-affiliated utilities located outside the system's service area. These
agreements consist of firm unit power sales pertaining to capacity from specific
generating units. The Company also had agreements for non-firm sales, which
expired in 1994, based on the capacity of the Southern system. Because energy is
generally sold at cost under these agreements, it is primarily the capacity
revenues that affect the Company's profitability.
The Company's capacity revenues have been as follows:
Year Unit Power Sales Non-firm Sales
-----------------------------------------------------------------
(in millions) (megawatts) (in millions) (megawatts)
1995 $ 53 248 $ - -
1994 75 403 9 101
1993 135 830 17 200
-----------------------------------------------------------------
Unit power from specific generating plants is being sold to FP&L, FPC, JEA,
and the City of Tallahassee, Florida. Under these agreements, the Company sold
approximately 248 megawatts of capacity in 1995 and is scheduled to sell
approximately 173 megawatts of capacity in 1996. Thereafter, these sales will
decline to an estimated 159 megawatts and remain at that level through 1999.
After 2000, capacity sales will decline to approximately 103 megawatts -- unless
reduced by FP&L, FPC, and JEA -- until the expiration of the contracts in 2010.
Long-term non-firm power of 200 megawatts was sold by the Southern
system in 1994 to FPC, of which the Company's share was 101 megawatts, under a
contract that expired at the end of 1994. Sales under these long-term non-firm
power sales agreements were made from available power pool energy, and the
revenues from the sales were shared by the operating affiliates.
8. INCOME TAXES
Effective January 1, 1993, the Company adopted FASB Statement No. 109,
Accounting for Income Taxes. The adoption resulted in the recording of
additional deferred income taxes and related regulatory assets and liabilities.
At December 31, 1995, the tax-related regulatory assets were $872 million and
the tax-related regulatory liabilities were $410 million. The assets are
attributable to tax benefits flowed through to customers in prior years and to
taxes applicable to capitalized AFUDC. The liabilities are attributable to
deferred taxes previously recognized at rates higher than current enacted tax
law and to unamortized investment tax credits.
Details of the federal and state income tax provisions are as follows:
1995 1994 1993
------------------------------
Total provision for income taxes: (in millions)
Federal:
Currently payable $349 $306 $223
Deferred -
Current year 84 86 181
Reversal of prior years (55) (57) (40)
Deferred investment tax
credits 1 (1) (18)
-----------------------------------------------------------------
379 334 346
-----------------------------------------------------------------
State:
Currently payable 60 52 41
Deferred -
Current year 15 15 31
Reversal of prior years (8) (10) (3)
-----------------------------------------------------------------
67 57 69
-----------------------------------------------------------------
Total 446 391 415
------------------------------------------------------------------
Less:
Income taxes charged
(credited) to other income (3) (8) (37)
=================================================================
Federal and state income
taxes charged to operations $449 $399 $452
=================================================================
II-122
NOTES (continued)
Georgia Power Company 1995 Annual Report
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:
1995 1994
--------------------
(in millions)
Deferred tax liabilities:
Accelerated depreciation $1,630 $1,541
Property basis differences 1,074 1,085
Deferred Plant Vogtle costs 100 141
Premium on reacquired debt 70 68
Deferred regulatory costs 38 48
Fuel clause underrecovered - 9
Other 29 23
------------------------------------------------------------------
Total 2,941 2,915
------------------------------------------------------------------
Deferred tax assets:
Other property basis differences 239 250
Federal effect of state deferred taxes 97 94
Other deferred costs 83 79
Disallowed Plant Vogtle buybacks 25 26
Accrued interest 13 10
Fuel clause overrecovered 6 -
Other 18 13
------------------------------------------------------------------
Total 481 472
------------------------------------------------------------------
Net deferred tax liabilities 2,460 2,443
Portion included in current assets 51 35
==================================================================
Accumulated deferred income taxes
in the Balance Sheets $2,511 $2,478
==================================================================
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 $22 million in 1995, $25 million in 1994, and $19 million in 1993.
At December 31, 1995, all investment tax credits available to reduce federal
income taxes payable had been utilized.
A reconciliation of the federal statutory tax rate to the effective income
tax rate is as follows:
1995 1994 1993
-----------------------------
Federal statutory rate 35% 35% 35%
State income tax, net of
federal deduction 4 4 4
Non-deductible book
depreciation 2 3 3
Difference in prior years'
deferred and current tax rate (1) (1) (1)
Other - - (1)
================================================================
Effective income tax rate 40% 41% 40%
================================================================
The Southern Company and its subsidiaries file a consolidated federal income
tax return. Under a joint consolidated income tax agreement, each subsidiary's
current and deferred tax expense is computed on a stand-alone basis. Tax
benefits from losses of the parent company are allocated to each subsidiary
based on the ratio of taxable income to total consolidated taxable income.
9. 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, 1995, retained earnings of $897 million 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, 1995, the
ratio as defined was 50.2 percent.
II-123
NOTES (continued)
Georgia Power Company 1995 Annual Report
Preferred Securities
In December 1994, Georgia Power Capital, L.P., of which the Company is the sole
general partner, issued $100 million of 9 percent mandatory redeemable preferred
securities. The sole asset of Georgia Power Capital is $103 million aggregate
principal amount of Georgia Power's 9 percent Junior Subordinated Deferrable
Interest Debentures due December 19, 2024. The Company considers that the
mechanisms and obligations relating to the preferred securities, taken together,
constitute a full and unconditional guarantee by the Company of Georgia Power
Capital's payment obligations with respect to the preferred securities.
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
$1.5 billion 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 $146 million 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 1995 1994
--------------------------------------------------------------
(in millions)
2000 4.375% $ 50 $ -
2004-2005 5% to 5.70% 143 85
2006-2008 6.375% to 6.75% 12 12
2011-2015 10.125% to 10.6%
& Variable 10 515
2016-2019 6% to 9.375% 282 282
2021-2025 5.40% to 7.25%
& Variable 1,181 784
==============================================================
Total pollution control bonds $ 1,678 $1,678
==============================================================
Bank Credit Arrangements
At the beginning of 1996, the Company had unused credit arrangements with banks
totaling $975 million, of which $514.7 million expires at various times during
1996, $60.3 million expires at May 1, 1998, and $400 million expires at June 30,
1998.
The $400 million expiring June 30, 1998, is under revolving credit
arrangements with several banks providing the Company, Alabama Power Company,
and The Southern Company up to a total credit amount of $400 million. To provide
liquidity support for commercial paper programs, $165 million, $135 million, and
$100 million are currently dedicated to the Company, Alabama Power Company, and
The Southern Company, respectively. However, the allocations can be changed
among the borrowers by notifying the respective banks.
During the term of the agreements expiring in 1998, 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.
Of the Company's total $975 million in unused credit arrangements, a portion
of the lines are dedicated to provide liquidity support to variable rate
pollution control bonds. The credit lines dedicated as of December 31, 1995,
were $475 million. In connection with all other lines of credit, the Company has
the option of paying fees or maintaining compensating balances. These balances
are not legally restricted from withdrawal.
In addition, the Company borrows under uncommitted lines of credit with
banks and through a $225 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 1995.
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
II-124
NOTES (continued)
Georgia Power Company 1995 Annual Report
long-term debt. At December 31, 1995 and 1994, the Company had a capitalized
lease obligation for its corporate headquarters building of $87 million and $88
million, respectively, with an interest rate of 8.1 percent. The maturity of
this capital lease obligation through 2000 is approximately as follows: $336
thousand in 1996, $365 thousand in 1997, $395 thousand in 1998, $429 thousand in
1999, and $672 thousand in 2000.
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 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, 1995, and 1994, the interest and lease
amortization deferred on the Balance Sheets are $49 million and $48 million,
respectively.
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:
1995 1994
-----------------
(in millions)
First mortgage bond maturity $150 $130
Other long-term debt - 37
================================================================
Total $150 $167
================================================================
The Company's first mortgage bond indenture includes an improvement fund
requirement that 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 June 1 of each year by depositing cash, reacquiring bonds, or by
pledging additional property equal to 1 2/3 times the requirement. The Company
currently plans to satisfy its 1996 improvement fund requirement by depositing
cash with the trustee or by pledging additional property.
Redemption of Securities
The Company plans to continue a program of redeeming or replacing debt and
preferred stock in cases where opportunities exist to reduce financing costs.
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 through 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.
10. QUARTERLY FINANCIAL DATA (UNAUDITED)
Summarized quarterly financial information for 1995 and 1994 is as follows:
Net Income
After
Dividends on
Operating Operating Preferred
Quarter Ended Revenues Income Stock
-------------------------------------------------------------------
(in millions)
March 1995 $ 974 $207 $ 116
June 1995 1,075 230 149
September 1995 1,374 337 245
December 1995 982 177 99
March 1994 $ 992 $157 $ 58
June 1994 1,030 227 140
September 1994 1,213 331 233
December 1994 927 179 95
-------------------------------------------------------------------
Earnings in 1994 declined by $55 million as a result of work force reduction
programs recorded primarily in the first quarter.
The Company's business is influenced by seasonal weather conditions.
II-125
II-126
II-127A
II-127B
II-127C
II-128
II-129A
II-129B
II-129C
II-130
II-131A
II-131B
II-131C
II-132
II-133A
II-133B
II-133C
II-134
II-135A
II-135B
II-135C
II-136
II-137A
II-137B
II-137C
GEORGIA POWER COMPANY
OUTSTANDING SECURITIES AT DECEMBER 31, 1995
First Mortgage Bonds
Amount Interest Amount
Series Issued Rate Outstanding Maturity
--------------------------------------------------------------------------------
(Thousands) (Thousands)
1993 $ 150,000 4-3/4% $ 150,000 3/1/96
1993 100,000 5-1/2% 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 6-5/8% 200,000 4/1/03
1993 75,000 6.35% 75,000 8/1/03
1993 50,000 6-7/8% 50,000 4/1/08
1992 100,000 8-5/8% 60,368 6/1/22
1993 160,000 7.95% 160,000 2/1/23
1993 100,000 7-5/8% 100,000 3/1/23
1993 75,000 7-3/4% 75,000 4/1/23
1993 125,000 7.55% 125,000 8/1/23
1995 75,000 7.70% 75,000 5/1/25
============= ==============
$ 1,755,000 $ 1,715,368
============= ==============
Pollution Control Bonds
Amount Interest Amount
Series Issued Rate Outstanding Maturity
--------------------------------------------------------------------------------
(Thousands) (Thousands)
1995 $ 50,000 4-3/8% $ 50,000 11/1/00
1992 38,800 5.70% 38,800 9/1/04
1993 46,790 5-3/8% 46,790 3/1/05
1995 57,000 5% 57,000 9/1/05
1976 40,800 6-3/4% 1,920 11/1/06
1977 24,100 6.40% 1,940 6/1/07
1978 21,600 6-3/8% 8,060 4/1/08
1991 10,450 Variable 10,450 7/1/11
1986 56,400 8% 56,400 10/1/16
1987 90,000 8-3/8% 90,000 7/1/17
1987 50,000 9-3/8% 50,000 12/1/17
1993 26,700 6% 26,700 3/1/18
1989 50,000 6.35% 50,000 5/1/19
1991 8,500 6.25% 8,500 7/1/19
1991 51,345 7.25% 51,345 7/1/21
1991 10,125 6.25% 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 5-3/4% 11,935 9/1/23
1993 60,000 5-3/4% 60,000 9/1/23
1994 28,065 5.40% 28,065 1/1/24
1994 175,000 Variable 175,000 7/1/24
1994 125,000 6.60% 125,000 7/1/24
1994 60,000 6-3/8% 60,000 8/1/24
1994 43,420 6-3/4% 43,420 10/1/24
1994 20,000 Variable 20,000 10/1/24
1994 20,000 Variable 20,000 10/1/24
1994 38,725 6-5/8% 38,725 10/1/24
1994 10,000 5.90% 10,000 12/1/24
1994 7,000 5.90% 7,000 12/1/24
1995 73,535 6.10% 73,535 4/1/25
1995 75,000 Variable 75,000 4/1/25
1995 45,000 Variable 45,000 7/1/25
1995 40,000 Variable 40,000 7/1/25
1995 71,580 6% 71,580 7/1/25
1995 35,585 Variable 35,585 9/1/25
1995 30,000 Variable 30,000 9/1/25
1995 27,000 Variable 27,000 9/1/25
============= ==============
$ 1,752,610 $ 1,678,030
============= ==============
II-138
GEORGIA POWER COMPANY
OUTSTANDING SECURITIES AT DECEMBER 31, 1995 (Continued)
Subsidiary Obligated Mandatorily Redeemable Preferred Securities(1)
Preferred Securities Interest Amount
Series Outstanding Rate Outstanding
--------------------------------------------------------------------------------
(Thousands)
1994 4,000,000 9% $ 100,000
Preferred Stock
Shares Dividend Amount
Series Outstanding Rate Outstanding
--------------------------------------------------------------------------------
(Thousands)
(2) 14,090 $5.00 $ 1,409
1953 100,000 $4.92 10,000
1954 433,774 $4.60 43,378
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
------------- ------------
21,027,864 $ 692,787
============= ============
(1) Issued by Georgia Power Capital, L.P., and guaranteed to the extent Georgia
Power Capital has funds by GEORGIA.
(2) Issued in exchange for $5.00 preferred outstanding at the time of
company formation.
II-139
GEORGIA POWER COMPANY
SECURITIES RETIRED DURING 1995
First Mortgage Bonds
Principal Interest
Series Amount Rate
------------------------------------------------------------------------------
(Thousands)
1989 $ 36,157 9.23%
1992 130,000 5-1/8%
1992 100,000 8-3/4%
1992 39,632 8-5/8%
1992 100,000 Variable
1992 100,000 Variable
===========
$ 505,789
===========
Pollution Control Bonds
Principal Interest
Series Amount Rate
------------------------------------------------------------------------------
(Thousands)
1976 $ 20 6-3/4%
1977 20 6.40%
1978 70 6-3/8%
1985 148,535 10-1/8%
1985 156,580 10-1/2%
1985 100,000 10.60%
1985 99,585 10-1/2%
-----------
$ 504,810
===========
II-140
GULF POWER COMPANY
FINANCIAL SECTION
II-141
MANAGEMENT'S REPORT
Gulf Power Company 1995 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 five 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 Gulf Power Company in conformity with generally accepted
accounting principles.
/s/ Travis J. Bowden
Travis J. Bowden
President and Chief Executive Officer
/s/ Arlan E. Scarbrough
Arlan E. Scarbrough
Chief Financial Officer
February 21, 1996
II-142
REPORT OF INDEPENDENT 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, 1995 and 1994, 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, 1995. These financial statements
are the responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements (pages II-152 through II-169)
referred to above present fairly, in all material respects, the financial
position of Gulf Power Company as of December 31, 1995 and 1994, and the
results of its operations and its cash flows for the periods stated, in
conformity with generally accepted accounting principles.
/s/ Arthur Andersen LLP
Atlanta, Georgia
February 21, 1996
II-143
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Gulf Power Company 1995 Annual Report
RESULTS OF OPERATIONS
Earnings
Gulf Power Company's 1995 net income after dividends on preferred stock was
$57.2 million, an increase of $2 million over the prior year. This improvement
is primarily attributable to higher retail revenues due to exceptionally hot
summer weather and lower interest charges on long-term debt. This improvement
was partially offset by higher maintenance expenses and reduced capacity
revenues from non-affiliated utilities under long-term contracts. Costs related
to a work force reduction program implemented in the fourth quarter of 1995
decreased earnings by $4.3 million. These costs are expected to be recovered
through future savings over approximately two years.
In 1994, earnings were $55.2 million, representing an increase of $0.9
million compared to the prior year. Earnings in 1994 were significantly affected
by lower financing costs, an increase in customers, and milder than normal
temperatures. Also, earnings decreased approximately $3.0 million, reflecting
the first full year of lower industrial sales due to the Company's largest
industrial customer, Monsanto, installing its own cogeneration facility in
August, 1993.
The return on average common equity for 1995 was 13.27 percent, a slight
increase from the 13.15 percent return earned in 1994.
Revenues
Operating revenues increased in 1995 and decreased in 1994 as a result of the
following factors:
Increase (Decrease)
From Prior Year
-------------------------------------
1995 1994 1993
-------------------------------------
(in thousands)
Retail --
Change in base rates $ - $ - $ 1,571
Sales growth 3,647 7,126 7,671
Weather 9,749 (4,631) 4,049
Regulatory cost
recovery and other 22,502 8,938 (3,079)
-----------------------------------------------------------------
Total retail 35,898 11,433 10,212
-----------------------------------------------------------------
Sales for resale--
Non-affiliates (5,698) (6,098) 2,131
Affiliates 1,266 (5,813) (909)
-----------------------------------------------------------------
Total sales for resale (4,432) (11,911) 1,222
Other operating
revenues 8,798 (3,851) 806
-----------------------------------------------------------------
Total operating
revenues $40,264 $(4,329) $12,240
=================================================================
Percent change 7.0% (0.7)% 2.1%
-----------------------------------------------------------------
Retail revenues of $519 million in 1995 increased $35.9 million or 7.4
percent from last year, compared with an increase of 2.4 percent in 1994 and 2.2
percent in 1993. Residential and commercial revenues surged upward as a result
of hotter-than-normal summer weather in 1995, compared with the extremely mild
summer of 1994. The Company set an all-time peak demand for energy in 1995.
The increase in regulatory cost recovery and other retail revenue is
primarily attributable to the recovery of increased fuel costs. Regulatory cost
recovery and other includes recovery provisions for fuel expense and the energy
component of purchased power costs; energy conservation costs; purchased power
capacity costs; and environmental compliance costs. The recovery provisions
equal the related expenses and have no material effect on net income. See Notes
1 and 3 to the financial statements under "Revenues and Regulatory Cost Recovery
Clauses" and "Environmental Cost Recovery," respectively, for further
information.
II-144
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 1995 Annual Report
Sales for resale were $79 million in 1995, decreasing $4.4 million or 5.3
percent from 1994. 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 under these long-term contracts were as follows:
1995 1994 1993
----------------------------------------
(in thousands)
Capacity $25,870 $30,926 $33,805
Energy 18,598 18,456 21,202
============================================================
Total $44,468 $49,382 $55,007
============================================================
Capacity revenues decreased in 1995 and 1994, reflecting the scheduled
decline in capacity under long-term contracts.
Sales to affiliated companies 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.
The increase in other operating revenues for 1995 is primarily due to
increased amounts collected to recover newly-imposed county franchise fees.
These collections are also included in taxes other than income taxes and have no
impact on earnings. Other changes for 1995 and the change in 1994 are primarily
attributable to adjustments in the regulatory cost recovery clauses for
differences between recoverable costs and the amounts actually reflected in
revenues. See Notes 1 and 3 to the financial statements under "Revenues and
Regulatory Cost Recovery Clauses" and "Environmental Cost Recovery,"
respectively, for further discussion.
Kilowatt-hour sales for 1995 and percent changes in sales since 1993 are
reported below.
KWH Percent Change
------------ ---------------------------
1995 1995 1994 1993
------------ ---------------------------
(millions)
Residential 4,014 7.0% 1.1% 3.2%
Commercial 2,708 6.3 4.8 2.7
Industrial 1,795 (2.8) (9.0) (6.9)
Other 17 (0.1) - -
------------
Total retail 8,534 4.5 (0.3) 0.4
Sales for resale
Non-affiliates 1,397 (1.6) (2.8) 2.0
Affiliates 759 (13.1) (15.2) (14.8)
------------
Total 10,690 2.2 (2.1) (1.1)
==================================================================
Retail sales increased in 1995 due to hot summer weather, a 0.9 percent
increase in residential customers, and a 2.2 percent increase in commercial
customers. Industrial sales were lower due to the reclassification of a major
customer from the industrial to commercial class and temporary production delays
of other industrial customers. In 1994, retail sales decreased from the prior
year primarily due to mild summer weather and a decline in sales in the
industrial class, which reflected the loss of Monsanto and a lengthy shutdown of
another major customer.
In 1995, energy sales for resale to non-affiliates decreased 1.6 percent and
are predominantly related to unit power sales under long-term contracts to
Florida utilities. Energy sales to affiliated companies vary from year to year
as mentioned previously.
Expenses
Total operating expenses for 1995 increased $41.3 million or 8.5 percent from
1994. The increase is due to higher fuel and purchased power expenses, higher
maintenance expenses, and higher taxes other than income taxes, offset by lower
depreciation and amortization expenses. In 1994, total operating expenses
decreased $4.0 million or 0.8 percent from 1993 primarily due to decreased fuel
and purchased power expenses, offset by an increase in other operation expenses
and taxes.
Fuel and purchased power expenses for 1995 increased $30.1 million or 15.5
percent from 1994. The change reflects the increase in generation due to the
extreme weather conditions during the summer of 1995 and slightly higher fuel
II-145
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 1995 Annual Report
costs. In 1994, fuel and purchased power expenses declined $13.4 million or 6.5
percent from 1993 reflecting the decrease in generation due to the mild weather
and the lower cost of fuel.
The amount and sources of generation and the average cost of fuel per net
kilowatt-hour generated were as follows:
1995 1994 1993
-----------------------------
Total generation
(millions of kilowatt-hours) 9,828 9,559 9,558
Sources of generation
(percent)
Coal 99.5 99.8 99.4
Oil and gas .5 .2 .6
Average cost of fuel per net
kilowatt-hour generated
(cents)
Coal 2.08 2.00 2.03
Oil and gas 3.56 6.93 4.50
Total 2.09 2.01 2.05
------------------------------------------------------------------
In 1995, other operation expenses decreased $0.5 million or 0.4 percent from
the 1994 level. The decrease is primarily attributable to a $9.4 million
reduction in the amortization costs of coal buyouts and renegotiation of coal
supply contracts. This was offset by a $7 million accrual for benefits to be
provided by the Company under a work force reduction program implemented during
the fourth quarter of 1995. These costs are further discussed in Notes 2 and 5
to the financial statements under "Work Force Reduction Programs" and "Fuel
Commitments," respectively. In 1994, other operation expenses increased $4.7
million due to additional costs related to the buyouts and renegotiation of coal
supply contracts and the Company's pro rata share of affiliated companies' work
force reduction costs.
Maintenance expense in 1995 increased $5.2 million or 11.2 percent from the
prior year. This is attributable to higher power production maintenance related
to non-recurring items and higher distribution maintenance. In 1994, maintenance
expense remained relatively flat reflecting no major changes in the scheduling
of maintenance of production facilities.
Depreciation and amortization expenses decreased $1.5 million or 2.7 percent
from 1994. The change is attributable to property which was fully amortized by
December 1994. Refer to Note 1 to the financial statements under "Depreciation
and Amortization" for further discussion.
Federal and state income taxes increased $0.1 million or 0.3 percent in 1995
due to a slight increase in taxable income. Taxes other than income taxes
increased $7.9 million or 18.9 percent due to an increase in county franchise
fees as mentioned previously. In 1994, federal income taxes increased $1.2
million due to an increase in taxable income. Other taxes increased $1.5 million
or 3.7 percent due to higher property taxes, gross receipt taxes, and franchise
fee collections. Changes in gross receipt taxes and franchise fee collections,
which are collected from customers, have no impact on earnings.
In 1995, interest expense decreased $2.5 million or 7.8 percent below the
prior year. The decline is mainly attributable to lower interest on long-term
debt reflecting a lower average principal balance outstanding. The decrease in
interest on long-term debt was partially offset by an increase in interest on
notes payable as a result of a higher average amount of short-term notes
outstanding. Interest expense in 1994 decreased $3.8 million or 10.5 percent
under the prior year. The decrease was a result of 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.
II-146
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 1995 Annual Report
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 energy sales growth to a less regulated more
competitive environment.
A work force reduction program was implemented in the fourth quarter of 1995
that reduced earnings by $4.3 million. This action will assist in efforts to
control growth in future operating expenses.
The Florida Public Service Commission (FPSC) approved the Company's request
in December to increase the amount of its annual accrual to the accumulated
provision for property damage account from $1.2 million to $3.5 million due to
significant hurricane-related charges to the account during 1995. The approved
accrual increase is intended to restore the account balance to a reasonable
level within five years. Refer to Note 1 to the financial statements under
"Provision for Property Damage" for further discussion.
Future earnings in the near term will depend upon growth in energy sales,
which is subject to a number of factors. Traditionally, these factors have
included weather, competition, changes in contracts with neighboring utilities,
energy conservation practiced by customers, the elasticity of demand, and the
rate of economic growth in the Company's service area. However, the Energy
Policy Act of 1992 (Energy Act) is beginning to have a dramatic 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 positioning the business to meet the challenge of this
major change in the traditional practice 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. This may enhance the
incentive for IPPs to build cogeneration plants for industrial and commercial
customers and sell excess energy generation to utilities. Also, electricity
sales for resale rates are being driven down by wholesale transmission access
and numerous potential new energy suppliers, including power marketers and
brokers. The Company is aggressively working to maintain and expand its share of
wholesale sales in the Southeastern power markets.
Currently, Florida law does not permit retail wheeling. Although the Energy
Act does not require transmission access to retail customers, retail wheeling
initiatives are rapidly evolving and becoming very prominent issues in several
states. Potential new federal legislation is being discussed, and legislation
allowing customer choice has already been introduced in Florida. In order to
address these initiatives, numerous questions must be resolved, with the most
complex ones relating to transmission pricing and recovery of stranded
investments. As the initiatives become a reality, the structure of the utility
industry could radically change. Therefore, unless the Company remains a
low-cost producer and provides quality service, the Company's retail energy
sales growth could be limited and this could significantly erode earnings.
Conversely, being the low-cost producer could provide significant opportunities
to increase market share and profitability by seeking new markets that evolve
with the changing regulation.
The future effect of cogeneration and small-power production facilities
cannot be fully determined at this time. One effect of cogeneration which the
Company has experienced was the loss in 1993 of its largest industrial customer,
Monsanto, which is discussed in "Earnings." The Company's strategy is to
identify and pursue profitable cogeneration projects in Northwest Florida.
The FPSC has set conservation goals for the Company, beginning in 1995, which
require programs to reduce 154 megawatts of summer peak demand and 65,000 KWH of
sales by the year 2004. In 1995, the FPSC approved the Company's programs to
accomplish these goals. The Company can experience net growth as long as the
filed programs achieve the intended reductions in peak demand and KWH sales. In
response to these goals and seeking to remain competitive with other electric
utilities, the Company has developed initiatives which emphasize price
flexibility and competitive offering of energy efficiency products and services.
These initiatives will enable customers to lower or alter their peak energy
requirements. Besides promoting energy efficiency, another benefit of these
initiatives could be the ability to defer the need to construct some generating
facilities further into the future.
II-147
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 1995 Annual Report
On September 27, 1995, the Company filed a petition with the FPSC which seeks
approval for a new optional Commercial/Industrial Service (CIS) rider, which
would be applicable to the rate schedules serving the Company's largest and most
at-risk customers who are able to show they have viable alternatives for
electric power supply. The CIS rider would provide the flexibility needed to
enable the Company to offer its services in a more competitive manner to these
customers. The FPSC approval process is expected to take approximately 8 months.
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." Also, state of Florida
legislation adopted in 1993 that provides for recovery of prudent environmental
compliance costs is discussed in Note 3 to the financial statements under
"Environmental Cost Recovery."
The Company is subject to the provisions of Financial Accounting Standards
Board (FASB) Statement No. 71, Accounting for the Effects of Certain Types of
Regulation. In the event that a portion of the Company's operations is no longer
subject to these provisions, the Company would be required to write off related
regulatory assets and liabilities and determine if any other assets have been
impaired. See Note 1 to the financial statements under "Regulatory Assets and
Liabilities" for additional information.
New Accounting Standards
The FASB has issued Statement No. 121, Accounting for the Impairment of
Long-Lived Assets and Long-Lived Assets to Be Disposed Of. This statement
requires that long-lived assets be reviewed for impairment whenever events or
changes in circumstances indicate that the carrying amount for an asset may not
be recoverable. This statement also imposes stricter criteria for regulatory
assets by requiring that such assets be probable of future recovery at each
balance sheet date. The Company adopted the new rules January 1, 1996, with no
material effect on the financial statements. However, this conclusion may change
in the future as competitive factors influence wholesale and retail pricing in
the utility industry.
FINANCIAL CONDITION
Overview
The principal changes in the Company's financial condition during 1995 were
gross property additions of $63.1 million and an increase of $27 million in
notes payable. Funds for the property additions were provided by internal
sources. The increase in short-term notes payable is primarily attributable to a
$22 million note issued in relation to a payment made to a coal supplier for a
new arrangement under an existing coal contract. See the Statements of Cash
Flows and Note 5 to the financial statements under "Fuel Commitments" for
further details.
Financing Activities
The Company continued to lower its financing costs by retiring issues in 1995.
Retirements, including maturities during 1995, totaled $1.8 million of first
mortgage bonds, $0.1 million of pollution control bonds, $13.3 million of bank
notes and other long-term debt, and $1 million of preferred stock. (See the
Statements of Cash Flows for further details.)
Composite financing rates for the years 1993 through 1995 as of year end were
as follows:
1995 1994 1993
------------------------------
Composite interest rate on
long-term debt 6.5% 6.5% 7.1%
Composite preferred stock
dividend rate 6.4% 6.6% 6.5%
----------------------------------------------------------------
The composite interest rate on long-term debt remained constant at 6.5% from
1994 primarily due to no new issues or refinancings during 1995. The decrease in
the composite interest rate from 1993 to 1994 reflects the Company's efforts to
refinance higher-cost debt. The decrease in the composite preferred dividend
rate in 1995 is primarily due to a decrease in dividends on the Company's
adjustable rate preferred stock, reflecting lower interest rates.
II-148
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 1995 Annual Report
Capital Requirements for Construction
The Company's gross property additions, including those amounts related to
environmental compliance, are budgeted at $209 million for the three years
beginning in 1996 ($71 million in 1996, $67 million in 1997, and $71 million in
1998). The estimates of property additions for the three-year period include $9
million committed to meeting the requirements of the Clean Air Act, the cost of
which is expected to be recovered through the Environmental Cost Recovery Clause
(ECRC), 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 changes in business conditions; changes in
environmental regulations; revised load projections; the cost and efficiency of
construction labor, equipment, and materials; and the cost of capital. In
addition, there can be no assurance that costs related to capital expenditures
for the Company will be fully recovered. The Company does not have any baseload
generating plants under construction, and current energy demand forecasts do not
indicate a need for any additional baseload facilities until well into the
future. However, significant construction related to maintaining and upgrading
transmission and distribution facilities and generating plants will continue.
Other Capital Requirements
In addition to the funds needed for the construction program, approximately $109
million will be required by the end of 1998 in connection with maturities of
long-term debt. Also, the Company plans to continue a program to retire
higher-cost debt and preferred stock and replace these obligations with
lower-cost capital as market conditions and terms of the instruments permit.
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 -- has significantly
impacted the Company. Specific reductions in sulfur dioxide and nitrogen oxide
emissions from fossil-fired generating plants are required in two phases. Phase
I compliance began in 1995 and initially affected 28 generating units of The
Southern Company. As a result of The Southern Company's compliance strategy, an
additional 22 generating units were brought into compliance with Phase I
requirements. Phase II compliance is required by 2000, and all fossil-fired
generating plants will be affected.
In 1993, the Florida Legislature adopted legislation that allows a utility to
petition the FPSC for recovery of prudent environmental compliance costs that
are not being recovered through base rates or any other recovery mechanism. The
legislation is discussed in Note 3 to the financial statements under
"Environmental Cost Recovery." Substantially all of the costs for the Clean Air
Act and other new legislation discussed below is expected to be recovered
through the ECRC.
In 1995, the Environmental Protection Agency (EPA) began issuing annual
sulfur dioxide emission allowances through the allowance trading program. An
emission allowance is the authority to emit one ton of sulfur dioxide during a
calendar year. The method for issuing 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 Southern Company's sulfur dioxide compliance strategy is
designed to use allowances as a compliance option.
The Southern Company achieved Phase I sulfur dioxide compliance at the
affected plants by switching to low-sulfur coal, which required some equipment
upgrades. This compliance strategy resulted in unused emission allowances being
banked for later use. Compliance with nitrogen oxide emission limits was
achieved by the installation of new control equipment at 22 generating units.
Construction expenditures for Phase I compliance totaled approximately $320
million for The Southern Company, including approximately $50 million for the
Company through 1995.
For Phase II 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 units as required to meet Phase II limits.
Therefore, during the period 1996 to 2000, the current compliance strategy could
II-149
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 1995 Annual Report
require total construction expenditures of approximately $150 million for The
Southern Company, including approximately $10 million for the Company. However,
the full impact of Phase II compliance cannot now be determined with certainty,
pending the continuing 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 FPSC 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 2 percent in revenue requirements from the
Company's customers could be necessary to fully recover the cost of compliance
for both Phase I and Phase II of Title IV of the Clean Air Act. Compliance costs
include construction expenditures, increased costs for switching to low-sulfur
coal, and costs related to emission allowances.
Title III of the Clean Air Act requires a multi-year EPA study of power plant
emissions of hazardous air pollutants. The EPA is scheduled to submit a report
to Congress on the results of this study in 1996. The report will include 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 is evaluating the need to revise the ambient air quality standards
for particulate matter 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 1996, the EPA may 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 cleanup costs and has recognized in the financial statements costs to
clean up known sites. Additional sites may require environmental remediation for
which the Company may be liable for a portion or all required cleanup costs. For
additional information, see Note 3 to the financial statements under
"Environmental Cost Recovery."
Several major pieces of environmental legislation are being considered for
reauthorization or amendment by Congress. These include: the Clean Air Act; the
Clean Water Act; the Comprehensive Environmental Response, Compensation, and
Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances
Control Act; and the Endangered Species 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 additional 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 exists for liability as the result of
lawsuits alleging damages caused by electromagnetic fields.
II-150
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 1995 Annual Report
Sources of Capital
At December 31, 1995, the Company had $0.7 million of cash and cash equivalents
and $25 million of unused committed lines of credit with banks to meet its
short-term cash needs. See Note 5 to the financial statements under "Bank Credit
Arrangements" for additional information.
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; bank notes; 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.
II-151
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II-157
II-158
NOTES TO FINANCIAL STATEMENTS
Gulf Power Company 1995 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, a system service company,
Southern Communications Services (Southern Communications), Southern Electric
International (Southern Electric), Southern Nuclear Operating Company (Southern
Nuclear), The Southern Development and Investment Group (Southern Development),
and other direct and indirect subsidiaries. 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. Gulf Power Company provides electric service to the
Northwest Panhandle of Florida. 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 subsidiary companies. Southern Communications provides digital wireless
communications services to the operating companies and also markets these
services to the public within the Southeast. Southern Electric designs, builds,
owns and operates power production and delivery 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. Southern Development develops
new business opportunities related to energy products and services.
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 the FPSC.
The preparation of financial statements in conformity with generally accepted
accounting principles requires the use of estimates, and the actual results may
differ from those estimates.
Certain prior years' data presented in the financial statements have been
reclassified to conform with current year presentation.
Regulatory Assets and Liabilities
The Company is subject to the provisions of Financial Accounting Standards Board
(FASB) Statement No. 71, Accounting for the Effects of Certain Types of
Regulation. Regulatory assets represent probable future revenues to the Company
associated with certain costs that are expected to be recovered from customers
through the ratemaking process. Regulatory liabilities represent probable future
reductions in revenues associated with amounts that are to be credited to
customers through the ratemaking process. Regulatory assets and (liabilities)
reflected in the Balance Sheets at December 31 relate to:
1995 1994
------------------------
(in thousands)
Current & deferred
coal contract costs $ 46,535 $ 40,690
Deferred income taxes 29,093 30,433
Deferred loss on reacquired debt 17,015 18,494
Environmental remediation 5,789 7,800
Vacation pay 4,419 4,172
Regulatory clauses under
recovery, net 632 1,042
Deferred income tax credits (67,481) (71,964)
Deferred storm charges 7,502 -
Accumulated provision for
property damage - (11,522)
Other, net (1,510) (2,691)
----------------------------------------------------------------
Total $ 41,994 $ 16,454
================================================================
In the event that a portion of the Company's operations is no longer subject
to the provisions of Statement No. 71, the Company would be required to write
off related regulatory assets and liabilities. In addition, the Company would be
required to determine any impairment to other assets, including plant, and write
down the assets, if impaired, to their fair values.
II-159
NOTES (continued)
Gulf Power Company 1995 Annual Report
Revenues and Regulatory Cost Recovery Clauses
The Company accrues revenues for service 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 periodically adjust billings for
fluctuations in fuel and the energy component of purchased power costs. The
Company also has similar cost recovery clauses for energy conservation costs,
purchased power capacity costs, and environmental compliance costs. Revenues are
adjusted monthly for differences between recoverable costs and amounts actually
reflected in current rates.
The Company has a diversified base of customers. No single customer or
industry comprises 10 percent or more of revenues. In 1995, uncollectible
accounts continued to average significantly less than 1 percent of revenues.
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
3.6 percent in 1995 and 3.8 percent in 1994 and 1993. 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. Also, the provision for depreciation expense includes an amount
for the expected cost of removal of facilities. The decrease in 1995 is
attributable to property which was fully amortized by December 1994.
Income Taxes
The Company uses the liability method of accounting for deferred income taxes
and 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. The Company is included
in the consolidated federal income tax return of The Southern Company. See Note
8 for further information related to income taxes.
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 FPSC-approved composite rate used to calculate AFUDC
was 7.27 percent for 1995, 1994, and the second half of 1993 and 8.03 percent
for the first half of 1993. AFUDC amounts for 1995, 1994, and 1993 were $223
thousand, $1.1 million, and $966 thousand, respectively. The decrease in 1995 is
primarily due to the completion of major construction projects at Plant Daniel
at the end of 1994.
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.
II-160
NOTES (continued)
Gulf Power Company 1995 Annual Report
Financial Instruments
In accordance with FASB Statement No. 107, Disclosure About Fair Values of
Financial Instruments, financial instruments of the Company, for which the
carrying amounts do not approximate fair value, are shown in the table below as
of December 31:
1995
----------------------------
Carrying Fair
Amount Value
----------------------------
(in thousands)
Long-term debt $354,924 $365,305
-------------------------------------------------------------
1994
----------------------------
Carrying Fair
Amount Value
----------------------------
(in thousands)
Long-term debt $369,832 $355,019
Preferred stock subject to
mandatory redemption 1,000 1,030
-------------------------------------------------------------
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.
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 provides 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 $1.7 million and $2.5 million
at December 31, 1995 and 1994, respectively, is included in miscellaneous
current liabilities in the accompanying Balance Sheets.
Provision for Property Damage
The Company is self-insured for the full cost of storm and other damage to its
transmission and distribution property. At December 31, 1995, in accordance with
the FPSC's order, the accumulated provision for property damage had a negative
balance of $7.5 million as the result of charges for expenses relating to
Hurricanes Erin and Opal. The negative balance was reclassified to deferred
storm charges in the accompanying Balance Sheets. The FPSC approved the
Company's request in December to increase the amount of its annual accrual to
the accumulated provision for property damage account from $1.2 million to $3.5
million, effective October 1, 1995. The approved accrual increase is intended to
restore the account balance to a reasonable level within five years. The FPSC
also ordered the Company to file within six months a study addressing the
appropriate accumulated provision account balance and annual accrual amount. At
December 31, 1994, the accumulated provision for property damage amounted to
$11.5 million. The expense of repairing damages from major storms and other
uninsured property damages are charged to the provision account.
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 one of the
following 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.
II-161
NOTES (continued)
Gulf Power Company 1995 Annual Report
Postretirement Benefits
The Company provides certain medical care and life insurance benefits for
retired employees. Substantially all employees may become eligible for these
benefits when they retire. Trusts are funded to the extent deductible under
federal income tax regulations or to the extent required by the Company's
regulatory commissions. Amounts funded are primarily invested in equity and
fixed-income securities. FASB Statement No. 106, Employers' Accounting for
Postretirement Benefits Other Than Pensions, 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."
Funded Status and Cost of Benefits
The following tables show actuarial results and assumptions for pension and
postretirement insurance benefits as computed under the requirements of FASB
Statement Nos. 87 and 106, respectively. The funded status of the plans at
December 31 was as follows:
Pension
-------------------------
1995 1994
-------------------------
(in thousands)
Actuarial present value of
benefit obligation:
Vested benefits $ 87,652 $ 73,552
Non-vested benefits 4,284 3,016
------------------------------------------------------------------
Accumulated benefit obligation 91,936 76,568
Additional amounts related to
projected salary increases 29,073 29,451
------------------------------------------------------------------
Projected benefit obligation 121,009 106,019
Less:
Fair value of plan assets 180,980 151,337
Unrecognized net gain (48,438) (36,599)
Unrecognized prior service cost 2,578 2,802
Unrecognized transition asset (7,187) (8,034)
------------------------------------------------------------------
Prepaid asset recognized in
the Balance Sheets $ 6,924 $ 3,487
==================================================================
Postretirement Benefits
---------------------------
1995 1994
---------------------------
(in thousands)
Actuarial present value of
benefit obligation:
Retirees and dependents $ 9,759 $10,800
Employees eligible to retire 4,921 4,043
Other employees 17,646 19,639
----------------------------------------------------------------
Accumulated benefit obligation 32,326 34,482
Less:
Fair value of plan assets 7,050 5,740
Unrecognized net loss (gain) 1,538 (458)
Unrecognized transition
obligation 7,437 15,520
----------------------------------------------------------------
Accrued liability recognized in
the Balance Sheets $16,301 $13,680
================================================================
In 1995, the Company announced a cost sharing program for postretirement
benefits. The program establishes limits on amounts the Company will pay to
provide future retiree postretirement benefits. This change reduced the 1995
accumulated postretirement benefit obligation by approximately $7.1 million.
The weighted average rates assumed in the actuarial calculations were:
1995 1994 1993
-----------------------------
Discount 7.3% 8.0% 7.5%
Annual salary increase 4.8% 5.5% 5.0%
Long-term return on plan
assets 8.5% 8.5% 8.5%
---------------------------------------------------------------
An additional assumption used in measuring the accumulated postretirement
benefit obligation was a weighted average medical care cost trend rate of 9.8
percent for 1995, decreasing to 5.3 percent through the year 2005 and remaining
at that level thereafter. An annual increase in the assumed medical care cost
trend rate of 1 percent would increase the accumulated benefit obligation at
December 31, 1995, by $2.5 million and the aggregate of the service and interest
cost components of the net retiree cost by $610 thousand.
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NOTES (continued)
Gulf Power Company 1995 Annual Report
Components of the plans' net costs are shown below:
Pension
------------------------------------
1995 1994 1993
------------------------------------
(in thousands)
Benefits earned during
the year $ 3,867 $ 3,775 $ 3,710
Interest cost on projected
benefit obligation 8,042 7,484 7,319
Actual (return) loss on
plan assets (33,853) 3,721 (20,672)
Net amortization
and deferral 19,619 (17,054) 8,853
------------------------------------------------------------------
Net pension cost (income) $ (2,325) $(2,074) $ (790)
==================================================================
Of the above net pension amounts, pension income of $1.8 million in 1995,
$1.5 million in 1994, and $601 thousand in 1993 were recorded in operating
expenses, and the remainder was recorded in construction and other accounts.
Postretirement Benefits
--------------------------------
1995 1994 1993
--------------------------------
(in thousands)
Benefits earned during the year $1,259 $1,362 $1,166
Interest cost on accumulated
benefit obligation 2,520 2,535 2,339
Amortization of transition
obligation 853 854 854
Actual (return) loss on plan (1,268) 129 (731)
assets
Net amortization and deferral 742 (591) 310
-------------------------------------------------------------------
Net postretirement cost $4,106 $4,289 $3,938
===================================================================
Of the above net postretirement costs recorded, $3.1 million in 1995 and 1994
and $3.0 million in 1993 were charged to operating expenses, and the remainder
was recorded in construction and other accounts.
Work Force Reduction Programs
The Company implemented a voluntary work force reduction program in the fourth
quarter of 1995 and recorded $7 million in December for the total cost related
to the program. These costs are expected to be recovered through future savings
over approximately two years. The Company has also incurred its pro rata share
for the costs of affiliated companies' programs. The costs related to these
programs were $1 million, $1.3 million, and $109 thousand for the years 1995,
1994, and 1993, respectively.
3. LITIGATION AND REGULATORY MATTERS
FERC Reviews Equity Returns
In May 1991, the FERC ordered that hearings be conducted concerning the
reasonableness of the operating companies' 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
change in the rate of return on common equity that may require refunds as a
result of this proceeding would be substantially for the period beginning in
July 1991 and ending in October 1992. 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.
In August 1994, the FERC instituted another proceeding based on substantially
the same issues as in the 1991 proceeding. The second period under review for
possible refunds was substantially from October 1994 through December 1995. In
November 1995, a FERC administrative law judge issued an opinion that the FERC
staff failed to meet its burden of proof, and therefore, no change in the equity
return was necessary. The FERC staff has filed exceptions to the administrative
law judge's opinion, and the matter remains pending before the FERC.
If the rates of return on common equity recommended by the FERC staff were
applied to all of the schedules and contracts involved in both proceedings and
refunds were ordered, the amount of refunds could range up to approximately $120
million for The Southern Company, including approximately $8 million for the
Company at December 31, 1995. However, management believes that rates are not
excessive and that refunds are not justified.
II-163
NOTES (continued)
Gulf Power Company 1995 Annual Report
FPSC Review of Earnings
As a result of an investigation of Gulf's 1995 earnings by the FPSC, Gulf
presented a 1995 earnings proposal, which required deferring any jurisdictional
revenues contributing to annual earnings in excess of a 12.75%
jurisdictional-adjusted return on equity. The proposal was approved by the FPSC
in August 1995. Gulf was to petition the FPSC to determine the disposition of
any deferred revenues by April 1996. Based on 1995 actual results, no revenues
were deferred.
Environmental Cost Recovery
In April 1993, the Florida Legislature adopted legislation for an Environmental
Cost Recovery Clause (ECRC), 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 recovery mechanism. Such environmental
costs include operation and maintenance expense, emission allowance expense,
depreciation, and a return on invested capital.
On January 12, 1994, the FPSC approved the Company's initial petition under
the ECRC for recovery of environmental costs that were projected to be incurred
from July 1993 through September 1994. Since this initial period, recovery under
the ECRC has been determined semi-annually and includes a true-up of the prior
period and a projection of the ensuing six month period. During 1995 and 1994,
the Company recorded ECRC revenues of $11.8 million and $7.2 million,
respectively.
At December 31, 1995, the Company's liability for the estimated costs of
environmental remediation projects for known sites was $5.8 million. These
estimated costs are expected to be expended during the period 1996 to 1999.
These projects have been approved by the FPSC for recovery through the ECRC
discussed above. Therefore, the Company recorded $2.0 million in current assets
and $3.8 million in deferred charges representing the future recoverability of
these costs.
4. CONSTRUCTION PROGRAM
The Company is engaged in a continuous construction program, the cost of which
is currently estimated to total $71 million in 1996, $67 million in 1997, and
$71 million in 1998. 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. At
December 31, 1995, significant purchase commitments were outstanding in
connection with the construction program. The Company does not have any new
baseload generating plants under construction. However, 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, pollution control
bonds, and preferred stock; bank notes; 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. If the attractiveness of current
short-term interest rates continues, the Company may maintain a higher level of
short-term indebtedness than has historically been true.
Bank Credit Arrangements
At December 31, 1995, the Company had $20 million in revolving credit lines that
expire May 31, 1998, $5 million in revolving credit lines subject to renewal
June 1, 1997, and $21.5 million of lines of credit with banks subject to renewal
June 1 of each year, of which $25 million remained unused. In connection with
these credit lines, the Company has agreed to pay commitment fees and/or to
II-164
NOTES (continued)
Gulf Power Company 1995 Annual Report
maintain compensating balances with the banks. The compensating balances, which
represent substantially all of 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 fourteen major money center banks that
total $250 million, of which $37 million was committed at December 31, 1995.
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 at December 31, 1995, were as follows:
Year Fuel
------- ---------------
(in millions)
1996 $ 125
1997 126
1998 95
1999 86
2000 80
2001 - 2007 557
-------------------------------------------------------
Total commitments $1,069
=======================================================
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 this payment was $60 million. This
amount is being amortized to expense on a per ton basis over a nine-year period.
The remaining unamortized amount was $1.5 million at December 31, 1995.
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 was $23 million
at December 31, 1995.
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 was amortized to expense on a per ton basis during 1993,
1994, and the first quarter of 1995.
In December 1995, the Company made a payment of $22 million to a coal
supplier under an arrangement to lower the cost of future coal and/or to suspend
the purchase of coal under an existing contract for 25 months. This amount is to
be amortized to expense on a per ton basis during 1996, 1997, and the first
quarter of 1998.
The amortization expense of these contract buyouts and renegotiations is
being recovered through the fuel cost recovery clause discussed under "Revenues
and Regulatory Cost Recovery Clauses" in Note 1.
Lease Agreements
In 1989, the Company and Mississippi Power jointly entered into a twenty-two
year operating lease agreement for the use of 495 aluminum railcars. In 1994, a
second lease agreement for the use of 250 additional aluminum railcars was
entered into for twenty-two years. Both of these leases are for the
transportation of coal to Plant Daniel. The Company, as a joint owner of Plant
Daniel, is responsible for one half of the lease costs. The lease costs are
charged to fuel inventory and are allocated to fuel expense as the fuel is used.
The Company's share of the lease costs charged to fuel inventory was $1.7
million in 1995 and $1.2 million in 1994 and 1993. The Company's annual lease
payments for 1996 through 2000 will be approximately $1.7 million and after
2000, lease payments total approximately $22.4 million. The Company has the
option after three years from the date of the original contract on the second
lease agreement to purchase the railcars at the greater of the termination value
or the fair market value. Additionally, at the end of each lease term, the
Company has the option to renew the lease.
II-165
NOTES (continued)
Gulf Power Company 1995 Annual Report
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, an operating affiliate, jointly own Plant
Scherer Unit No. 3. Plant Scherer is 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, 1995, the Company's percentage ownership and its investment
in these jointly owned facilities were as follows:
Plant Scherer Plant
Unit No. 3 Daniel
(coal-fired) (coal-fired)
------------------------------
(in thousands)
Plant In Service $185,755(1) $222,515
Accumulated Depreciation $49,982 $97,033
Construction Work in Progress $288 $683
Nameplate Capacity (2)
(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
7. LONG-TERM POWER SALES AGREEMENTS
The Company and the other operating affiliates have long-term contractual
agreements for the sale of capacity and energy to certain non-affiliated
utilities located outside the system's service area. The agreements for non-firm
capacity expired in 1994. The unit power sales agreements, expiring at various
dates discussed below, 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 capacity revenues have been as follows:
Other
Unit Long-
Year Power Term Total
---------- ------------------------------------
(in thousands)
1995 $25,870 $ - $25,870
1994 29,653 1,273 30,926
1993 31,162 2,643 33,805
----------------------------------------------------------
Unit power from specific generating plants of The Southern Company is
currently being sold to Florida Power Corporation (FPC), Florida Power & Light
Company (FP&L), Jacksonville Electric Authority (JEA), and the city of
Tallahassee, Florida. Under these agreements, 210 megawatts of net dependable
capacity were sold by the Company during 1995, and sales will remain at that
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 $25.4 million in 1995, $29.3 million in 1994, and $39.5
million in 1993, or 4.1 percent, 5.1 percent, and 6.8 percent of operating
revenues, respectively.
II-166
NOTES (continued)
Gulf Power Company 1995 Annual Report
8. INCOME TAXES
Effective January 1, 1993, the Company adopted FASB Statement No. 109,
Accounting for Income Taxes. The adoption resulted in the recording of
additional deferred income taxes and related regulatory assets and liabilities.
At December 31, 1995, the tax-related regulatory assets to be recovered from
customers were $29.1 million. These assets are attributable to tax benefits
flowed through to customers in prior years and to taxes applicable to
capitalized AFUDC. At December 31, 1995, the tax-related regulatory liabilities
to be refunded to customers were $67.5 million. These liabilities are
attributable to deferred taxes previously recognized at rates higher than
current enacted tax law and to unamortized investment tax credits.
At December 31, 1995, the Company's current federal and state income taxes
accrued, including the current portion of deferred income taxes, were equal to a
debit balance of $4.2 million as a result of the early settlement of taxes owed.
This amount was reclassified to current assets to reflect the tax prepayment and
will be used to satisfy taxes accrued during 1996.
Details of the federal and state income tax provisions are as follows:
1995 1994 1993
----------------------------------
(in thousands)
Total provision for
income taxes:
Federal--
Currently payable $29,018 $34,941 $24,354
Deferred--current year 23,172 18,556 26,396
--reversal of
prior years (23,116) (24,787) (22,102)
------------------------------------------------------------------
29,074 28,710 28,648
------------------------------------------------------------------
State--
Currently payable 4,778 5,907 3,950
Deferred--current year 3,313 2,549 3,838
--reversal of
prior years (2,979) (3,304) (2,785)
------------------------------------------------------------------
5,112 5,152 5,003
------------------------------------------------------------------
Total 34,186 33,862 33,651
Less income taxes charged
(credited) to other income 121 (95) 921
------------------------------------------------------------------
Federal and state income
taxes charged
to operations $34,065 $33,957 $32,730
==================================================================
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:
1995 1994
-----------------------
(in thousands)
Deferred tax liabilities:
Accelerated depreciation $146,926 $146,686
Property basis differences 19,976 18,468
Coal contract buyouts 3,838 6,896
Property insurance 3,039 -
Other 10,573 11,846
-------------------------------------------------------------------
Total 184,352 183,896
-------------------------------------------------------------------
Deferred tax assets:
Federal effect of state deferred taxes 10,212 9,732
Postretirement benefits 5,494 4,383
Property insurance - 5,200
Other 6,313 7,566
-------------------------------------------------------------------
Total 22,019 26,881
-------------------------------------------------------------------
Net deferred tax liabilities 162,333 157,015
Less current portion, net (12) 5,334
-------------------------------------------------------------------
Accumulated deferred income
taxes in the Balance Sheets $162,345 $151,681
===================================================================
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 1995, 1994 and 1993. At December 31, 1995, 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:
1995 1994 1993
-----------------------------
Federal statutory rate 35% 35% 35%
State income tax,
net of federal deduction 4 4 3
Non-deductible book
depreciation 1 1 1
Difference in prior years'
deferred and current tax rate (3) (2) (2)
Other (2) (2) (1)
---------------------------------------------------------------
Effective income tax rate 35% 36% 36%
===============================================================
The Company and the other subsidiaries of The Southern Company file a
consolidated federal tax return. Under a joint consolidated income tax
agreement, each subsidiary's current and deferred tax expense is computed
II-167
NOTES (continued)
Gulf Power Company 1995 Annual Report
on a stand-alone basis. Tax benefits from losses of the parent company are
allocated to each subsidiary based on the ratio of taxable income to total
consolidated taxable income.
9. POLLUTION CONTROL OBLIGATIONS AND OTHER LONG-TERM DEBT
Details of pollution control bonds and other long-term debt at December 31 are
as follows:
1995 1994
--------------------------
(in thousands)
Obligations incurred in
connection with the sale by
public authorities of
tax-exempt pollution control
revenue bonds:
Collateralized
6% due 2006* $ 12,075 $ 12,200
8.25% due 2017 32,000 32,000
7.125% due 2021 21,200 21,200
6.75% due 2022 8,930 8,930
5.70% due 2023 7,875 7,875
5.80% due 2023 32,550 32,550
6.20% due 2023 13,000 13,000
6.30% due 2024 22,000 22,000
Variable Rate
Remarketable daily 20,000 20,000
---------------------------------------------------------------
$169,630 $169,755
---------------------------------------------------------------
Notes payable:
5.39% due 1995 - 4,500
5.72% due 1995 - 4,500
4.69% due 1996 25,000 25,000
6.44% due 1994-1998 12,074 16,388
---------------------------------------------------------------
37,074 50,388
---------------------------------------------------------------
Total $206,704 $220,143
===============================================================
* Sinking fund requirement applicable to the 6 percent pollution control
bonds is $200 thousand for 1996 with increasing increments periodically
thereafter through 2005, with the remaining balance due in 2006.
Pollution control obligations represent installment purchases of pollution
control facilities financed by funds derived from sales by public authorities of
revenue bonds. 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.
The 5.39 percent and 5.72 percent notes payable were the Company's portion of
notes payable issued in connection with the termination of Plant Daniel coal
contracts (see Note 5 under "Fuel Commitments" for further information). The
estimated annual maturities of the notes payable through 2000 are as follows:
$29.6 million in 1996, $4.9 million in 1997, $2.6 million in 1998, and none in
1999 and 2000.
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 at December 31 is as follows:
1995 1994
----------------------
(in thousands)
Bond improvement fund requirement $ 1,750 $ 1,750
Less: Portion to be satisfied by cash
or certifying property
additions - 1,750
---------------------------------------------------------------
Cash sinking fund requirement 1,750 -
Current portion of notes payable 29,598 13,314
(Note 9)
Pollution control bond maturity 200 125
(Note 9)
---------------------------------------------------------------
Total $31,548 $13,439
===============================================================
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.
II-168
NOTES (continued)
Gulf Power Company 1995 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, 1995, retained earnings of $101 million were
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 of 12 months 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, 1995, the ratio was 48.7 percent.
12. QUARTERLY FINANCIAL DATA (Unaudited)
Summarized quarterly financial data for 1995 and 1994 are as follows:
Net Income
After Dividends
Operating Operating on Preferred
Quarter Ended Revenues Income Stock
------------------------------------------------------------------
(in thousands)
March 31, 1995 $140,918 $19,503 $10,880
June 30, 1995 153,057 23,390 14,096
Sept. 30, 1995 184,251 35,187 26,588
Dec. 31, 1995 140,851 13,082 5,590
March 31, 1994 $138,088 $19,154 $10,117
June 30, 1994 146,769 19,957 8,886
Sept. 30, 1994 162,143 31,123 21,831
Dec. 31, 1994 131,813 21,979 14,395
------------------------------------------------------------------
The Company's business is influenced by seasonal weather conditions and the
timing of rate changes, among other factors.
II-169
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II-171A
II-171B
II-171C
II-172
II-173A
II-173B
II-173C
II-174