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, 1994
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)
64 Perimeter Center East
Atlanta, Georgia 30346
(404) 393-0650
1-3164 Alabama Power Company 63-0004250
(An Alabama Corporation)
600 North 18th Street
Birmingham, Alabama 35291
(205) 250-1000
1-6468 Georgia Power Company 58-0257110
(A Georgia Corporation)
333 Piedmont Avenue, N.E.
Atlanta, Georgia 30308
(404) 526-6526
0-2429 Gulf Power Company 59-0276810
(A Maine Corporation)
500 Bayfront Parkway
Pensacola, Florida 32501
(904) 444-6111
0-6849 Mississippi Power Company 64-0205820
(A Mississippi Corporation)
2992 West Beach
Gulfport, Mississippi 39501
(601) 864-1211
1-5072 Savannah Electric and Power Company 58-0418070
(A Georgia Corporation)
600 Bay Street, East
Savannah, Georgia 31401
(912) 232-7171
Securities registered pursuant to Section 12(b) of the Act:
Each of the following securities registered pursuant to Section 12(b) of the Act
are registered on the New York Stock Exchange.
Title of each class Registrant
Common Stock, $5 par value The Southern Company
---------------------------
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
Preferred securities, cumulative, $25 liquidation preference (Note)
9% Monthly Income Preferred Security, Series A
First mortgage bonds
6 1/8% Series due 1999 6 7/8% Series due 2002
---------------------------
Preferred stock, cumulative, $100 par value Mississippi Power Company
Depositary Preferred Shares, each representing one-fourth of a share of:
7.25% Series 6.32% Series 6.65% Series
---------------------------
Preferred stock, cumulative, $25 par value Savannah Electric and Power Company
6.64% Series
(Note) Issued by Georgia Power Capital, L.P., and unconditionally guaranteed 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 4.60% Series 4.72% Series 5.96% Series
4.52% Series 4.64% Series 4.92% Series 6.88% Series
Class A preferred, cumulative, $100,000 stated capital
Auction (1993 Series)
Class A preferred, cumulative, $100 stated capital
Auction (1988 Series)
---------------------------
Preferred stock, cumulative, $100 stated value Georgia Power Company
$4.60 Series $4.60 Series (1964) $4.96 Series $6.48 Series
$4.60 Series (1962) $4.72 Series $5.00 Series $6.60 Series
$4.60 Series (1963) 4.92 Series $5.64 Series
---------------------------
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
7.00% Series 7.30% Series 6.72% 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. ( )
Aggregate market value of voting stock held by non-affiliates of The
Southern Company at February 28, 1995: $13.7 billion. Each of such other
registrants are wholly-owned subsidiaries of The Southern Company and have no
voting stock other than their common stock. A description of registrants' common
stock follows:
Description of Shares Outstanding
Registrant Common Stock at February 28, 1995
The Southern Company Par Value $5 Per Share 661,856,138
Alabama Power Company Par Value $40 Per Share 5,608,955
Georgia Power Company No Par Value 7,761,500
Gulf Power Company No Par Value 992,717
Mississippi Power Company Without Par Value 1,121,000
Savannah Electric and Power Company Par Value $5 Per Share 10,844,635
Documents incorporated by reference: specified portions of The Southern
Company's Proxy Statement relating to the 1995 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-4
Fuel Supply.......................................................................................... I-7
Territory Served..................................................................................... I-8
Competition.......................................................................................... I-12
Regulation........................................................................................... I-13
Rate Matters......................................................................................... I-16
Employee Relations................................................................................... I-16
Item 2 Properties............................................................................................. I-18
Item 3 Legal Proceedings...................................................................................... I-23
Item 4 Submission of Matters to a Vote of Security Holders.................................................... I-25
Executive Officers of SOUTHERN......................................................................... I-26
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....................................... Empressa, Electrica del Norte Grande, S.A. (Chile)
Energy Act.................................... Energy Policy Act of 1992
EMF........................................... Electromagnetic field
EPA .......................................... United States Environmental Protection Agency
FERC ......................................... Federal Energy Regulatory Commission
FPC .......................................... Florida Power Corporation
FP&L ......................................... Florida Power & Light Company
Freeport...................................... Freeport Power Company (Bahamas)
GEORGIA ...................................... Georgia Power Company
GULF ......................................... Gulf Power Company
Gulf States .................................. Gulf States Utilities Company
Holding Company Act .......................... Public Utility Holding Company Act of 1935, as amended
IBEW ......................................... International Brotherhood of Electrical Workers
IRS........................................... Internal Revenue Service
JEA .......................................... Jacksonville Electric Authority
MEAG ......................................... Municipal Electric Authority of Georgia
MISSISSIPPI .................................. Mississippi Power Company
NRC ......................................... Nuclear Regulatory Commission
OPC .......................................... Oglethorpe Power Corporation
operating affiliates.......................... ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH
PSC .......................................... Public Service Commission
REA .......................................... Rural Electrification Administration
RICO.......................................... Racketeer Influenced and Corrupt Organizations Act
SAVANNAH ..................................... Savannah Electric and Power Company
SCS .......................................... Southern Company Services, Inc.
SDIG.......................................... The Southern Development and Investment Group, Inc.
SEC .......................................... Securities and Exchange Commission
SEGCO ........................................ Southern Electric Generating Company
SEI .......................................... Southern Electric International, Inc.
SEPA ......................................... Southeastern Power Administration
SERC ......................................... Southeastern Electric Reliability Council
SMEPA ........................................ South Mississippi Electric Power Association
SOUTHERN...................................... The Southern Company
Southern Nuclear.............................. Southern Nuclear Operating Company, Inc.
SOUTHERN system............................... SOUTHERN, the operating affiliates, SEGCO, SEI
Southern Nuclear, SCS, Communications, SDIG and
............................... other subsidiaries
T & TEC....................................... Trinidad and Tobago Electricity Commission
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), SDIG and various other
subsidiaries related to foreign operations and domestic non-utility operations
(see Exhibit 21 herein). At this time, the operations of the other subsidiaries
are not material. SEI designs, builds, owns and operates power production
facilities and provides a broad range of technical services to industrial
companies and utilities in the United States and a number of international
markets. A further description of SEI's business and organization follows later
in this section. Communications, beginning in mid-1995, will provide digital
wireless communications services -- over the 800-megahertz frequency band -- to
SOUTHERN's subsidiaries and also will market these services to the public within
the Southeast. Southern Nuclear provides services to the Southern electric
system's nuclear plants. SDIG develops new business opportunities related to
energy products and services.
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
I-1
and sales, transfers of economy energy and other similar transactions.
Additionally, the operating affiliates have entered into voluntary reliability
agreements with the subsidiaries of Entergy Corporation, Florida Electric Power
Coordinating Group and TVA and with Carolina Power & Light Company, Duke Power
Company, South Carolina Electric & Gas Company and Virginia Electric 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, SDIG 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 would authorize Southern Nuclear to become the operator. See Item 1 -
BUSINESS - "Regulation - Atomic Energy Act of 1954" herein.
New Business Development
SOUTHERN continues to consider new business opportunities, particularly those
which allow use of the expertise and resources developed through its regulated
utility experience. These endeavors began in 1981 and are conducted through SEI
and other existing subsidiaries.
SEI's primary business focus is international and domestic cogeneration, the
independent power market, and the privatization and development of generation
facilities in the international market. SEI currently operates three domestic
independent power production projects totaling 280 megawatts and is one-third
owner of one of these (which produces 180 megawatts). SEI (through subsidiaries)
has a contract to sell electric energy to Virginia Electric and Power Company
from a facility it is constructing in King George, Virginia. Upon completion,
currently planned for 1996, SEI will operate the 220 megawatt coal-fired plant.
SOUTHERN owns 50% of the project.
In April 1993, SOUTHERN completed the purchase of a 50% interest in
Freeport, an electric utility on the Island of Grand Bahama, for a purchase
price of $35.5 million. Freeport has generating capacity of about 112 megawatts.
In August 1993, SOUTHERN completed the purchase of a 55% interest in Alicura, an
entity that owns the right to use the generation from a 1,000 megawatt
hydroelectric generating facility in Argentina, for a net purchase price of
approximately $188 million. In 1993, SOUTHERN completed the purchase of a 38%
interest in Edelnor for the purchase price of $73 million. In December 1994,
SOUTHERN purchased an additional 27% interest in Edelnor for $80 million.
Edelnor is a utility located in Northern Chile that owns and operates a
transmission grid and 96 megawatts of generating facilities and is building an
additional 150 megawatt facility.
I-2
Also in December 1994, SOUTHERN completed the acquisition of a 39% interest
in a partnership that acquired the generation operations of the T&TEC,
comprising approximately 1,178 megawatts of generating capacity for a purchase
price of $85.6 million. Additionally, SOUTHERN purchased a 100% interest in an
energy and recovery complex from Scott Paper Company for a purchase price of
$350 million, which included the assumption of $85 million of outstanding
tax-exempt debt. This complex is used to generate substantially all of the steam
and electricity requirements of Scott's integrated pulp and paper mill located
in Mobile, Alabama and has a generating capacity of 105 megawatts. Most of the
facility's fuel needs are met from waste and by-products generated by Scott's
pulping and woodlands operations.
SEI and SDIG 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. In addition, SDIG engages
in energy management-related services and activities.
At year-end, the SEC authorized SOUTHERN to form a new subsidiary,
Communications, and to invest up to $179 million in Communications.
Communications has contracted with a prime vendor for the installation and
construction of a wireless communications system in order to provide services to
the general public, including SOUTHERN subsidiaries. The technology selected is
new and still under development. Communications will be subject to both market
and technology risks. It is anticipated that the operations of Communications,
at least in its early years, will negatively affect earnings and cash flow.
Furthermore, there can be no assurance that Communications will ultimately
recover the cost of constructing its wireless communications system.
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
1995-1997 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, 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 1995 through
1997 by the operating affiliates, SEGCO, SCS and Southern Nuclear are estimated
as follows: (in millions)
===========================================================
1995 1996 1997
----------------------------
ALABAMA $ 604 $ 500 $ 502
GEORGIA 579 626 724
GULF 62 76 84
MISSISSIPPI 78 73 72
SAVANNAH 34 27 26
SEGCO 10 11 11
SCS 26 19 14
Southern Nuclear 2 2 1
----------------------------------------------------------
SOUTHERN system* $1,395 $1,267 $1,362
==========================================================
*System totals for years 1996 and 1997 are less than the sum of the
subsidiaries due to changes made in GEORGIA's construction budget subsequent to
approval of the SOUTHERN system construction budget. However, GEORGIA's
management has adopted an initiative to reduce its 1996 and 1997 construction
expenditures by approximately 10% from currently estimated amounts. There can be
no assurance that such reductions will be achieved.
Reference is made to Note 4 to the financial statements of each registrant
in Item 8 herein for the amounts of AFUDC included in the above estimates. The
construction estimates do not include amounts which may be spent by
Communications or SEI (or the subsidiary(s) created to effect such project(s))
on future power production projects or the projects discussed earlier under "New
Business Development." (See also Item 1 - BUSINESS - "Financing Programs"
herein.)
I-3
Estimated construction costs in 1995 are expected to be apportioned
approximately as follows: (in millions)
============================================================================================================================
SOUTHERN
system* ALABAMA GEORGIA GULF MISSISSIPPI SAVANNAH
-----------------------------------------------------------------------------------------
Combustion turbines $ 135 $100 $ 35 $ - $ - $ -
Other generating
facilities including
associated plant substations 246 98 90 20 16 12
New business 323 134 155 14 13 7
Transmission 214 91 105 2 15 1
Joint line and substation 30 - 28 1 1 -
Distribution 155 77 41 11 18 8
Nuclear fuel 99 40 59 - - -
General plant 193 64 66 14 15 6
----------------------------------------------------------------------------------------
$1,395 $604 $579 $62 $78 $34
========================================================================================
*SCS and Southern Nuclear plan capital additions to general plant in 1995
of $26 million and $2 million, respectively, while SEGCO plans capital additions
of $10 million to 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
growth estimates; changes in environmental regulations; changes in existing
nuclear plants to meet new regulatory requirements; increasing cost of labor,
equipment and materials; and cost of capital. Also, the SOUTHERN system
construction estimates do not reflect expenditures by Communications or the
possibility of SEI securing a contract(s) to buy or build additional generating
facilities.
The operating affiliates do not have any baseload generating plants under
construction. However, within the service area, the construction of combustion
turbine peaking units with an aggregate capacity of approximately 1,100
megawatts is planned to be completed by 1997. In addition, significant
construction will continue related to transmission and distribution facilities
and the upgrading and extension of the useful lives of generating plants.
During 1991, the Georgia legislature passed legislation which requires
GEORGIA and SAVANNAH each to file an Integrated Resource Plan for approval by
the Georgia PSC. Under the plan rules, the Georgia PSC must pre-certify the
construction of new power plants. (See Item 1 - BUSINESS - "Rate Matters
-Integrated Resource Planning" herein.)
See Item 1 - BUSINESS - "Regulation - Environmental Regulation" herein for
information with respect to certain existing and proposed environmental
requirements and Item 2 - PROPERTIES - "Jointly-Owned Facilities" herein for
additional information concerning ALABAMA's and GEORGIA's joint ownership of
certain generating units and related facilities with certain non-affiliated
utilities.
Rocky Mountain Hydroelectric Project
For information regarding GEORGIA's Rocky Mountain Project, including a joint
ownership agreement with OPC and the uncertain recovery of GEORGIA's costs in
this project, reference is made to Note 4 to SOUTHERN's and to GEORGIA's
financial statements in Item 8 herein.
Stockholder Suit
For information concerning a suit against certain current and former directors
and officers of SOUTHERN involving allegations related to Plant Vogtle, the
Rocky Mountain project and other matters, see Item 3 - LEGAL PROCEEDINGS herein.
Financing Programs
In early 1995, SOUTHERN sold - through a public offering - common stock for
proceeds totaling approximately $103 million. SOUTHERN may require additional
I-4
equity capital during the remainder of 1995. The amount and timing of additional
equity capital to be raised in 1995, as well as subsequent years, will be
contingent on SOUTHERN's investment opportunities. Equity capital can be
provided from any combination of public offerings, private placements, or
SOUTHERN's stock plans. The operating affiliates' construction programs are
expected to be financed primarily from internal sources. Short-term debt will be
utilized if necessary. The operating affiliates may issue additional long-term
debt and preferred stock primarily for the purposes of debt maturities and for
redeeming higher-cost securities 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 expect to
have adequate coverage ratios for anticipated requirements through at least
1997.
The amounts of securities representing short-term unsecured indebtedness
allowable under the respective charters, and the maximum amounts of short-term
indebtedness authorized by the appropriate regulatory authorities, are shown in
the following table:
======================================================
Short-term Unsecured Indebtedness
------------------------------------------------------
Allowable
Under Charter
at December 31, 1994
--------------------
Percent of
Secured
Indebtedness
and Other
Amount Capital (2)
-------- -------------------
(Millions)
ALABAMA $ 1,108 20%
GEORGIA 1,752 20
GULF 89 10
MISSISSIPPI 146 20
SAVANNAH 70 20
SOUTHERN (1) (1)
------------------------------------------------------
======================================================
Short-term Indebtedness
------------------------------------------------------
Maximum Regulatory
Authorization
-------------
Outstanding
at
Amount December 31, 1994
------ -----------------
(Millions)
ALABAMA $530 (3) $180
GEORGIA 900 (3) 425
GULF 150 (3) 54
MISSISSIPPI 140 (3) -
SAVANNAH 70 (3) 3
SOUTHERN 500 (3) 305
------------------------------------------------------
Notes:
(1) No limitation.
(2) Under the provisions of the respective charters, GEORGIA's,
MISSISSIPPI's and SAVANNAH's preferred stockholders have approved increases in
the amounts of securities representing short-term unsecured indebtedness which
the companies may have outstanding until July 1 in 2003, 1999 and 1999,
respectively. Such limitations were raised from 10% of secured indebtedness and
other capital to 20% thereof. These approved increases are reflected in the
above table.
I-5
(3) ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SOUTHERN have received
SEC authorization to issue from time to time short-term and/or term loan notes
to banks and commercial paper to dealers in the amounts shown through March 31,
1996, except for GULF, which date is December 31, 1996.
Reference is made to Note 5, 5, 8, 5, 5 and 5 to the financial statements
for SOUTHERN, ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH, respectively, in
Item 8 herein for information regarding the registrants' credit arrangements.
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 1992 through
1994 and the estimates for 1995 are shown below:
Oil
and
ALABAMA Coal Nuclear Hydro Gas Total
-----------------------------------------
1992 70% 21% 9% *% 100%
1993 70 22 8 * 100
1994 68 23 9 * 100
1995 74 19 7 * 100
GEORGIA
1992 76 21 3 * 100
1993 77 20 3 * 100
1994 75 22 3 * 100
1995 76 21 2 1 100
GULF
1992 100 ** ** * 100
1993 99 ** ** 1 100
1994 100 ** ** * 100
1995 100 ** ** * 100
MISSISSIPPI
1992 91 ** ** 9 100
1993 90 ** ** 10 100
1994 85 ** ** 15 100
1995 83 ** ** 17 100
SAVANNAH
1992 81 ** ** 19 100
1993 83 ** ** 17 100
1994 91 ** ** 9 100
1995 89 ** ** 11 100
SEGCO
1992 100 ** ** * 100
1993 100 ** ** * 100
1994 100 ** ** * 100
1995 100 ** ** * 100
SOUTHERN
system
1992 77 17 5 1 100
1993 78 17 4 1 100
1994 75 19 5 1 100
1995 78 17 4 1 100
-------------------------------------------------------------
*Less than 0.5%
**Not applicable
The average costs of fuel in cents per net kilowatt-hour generated are shown
below:
Oil
and Weighted
ALABAMA Coal Nuclear Gas Average
-------------------------------------------
1992 1.99 0.44 * 1.64
1993 2.11 0.51 * 1.73
1994 1.92 0.49 * 1.56
GEORGIA
1992 1.75 0.63 * 1.52
1993 1.75 0.58 * 1.52
1994 1.67 0.63 * 1.44
GULF
1992 2.07 ** * 2.07
1993 2.03 ** 4.50 2.05
1994 2.00 ** * 2.01
MISSISSIPPI
1992 1.59 ** 3.05 1.60
1993 1.66 ** 2.97 1.71
1994 1.67 ** 2.60 1.71
SAVANNAH
1992 2.28 ** 3.55 2.53
1993 2.02 ** 4.70 2.49
1994 2.19 ** 4.72 2.42
SEGCO
1992 1.81 ** * 1.81
1993 1.80 ** * 1.81
1994 1.83 ** * 1.83
SOUTHERN
system
1992 1.86 0.54 4.81 1.62
1993 1.90 0.54 4.34 1.67
1994 1.80 0.56 3.99 1.56
----------------------------------------------------------------
*Not meaningful because of minimal generation from
fuel source.
**Not applicable.
***See SELECTED FINANCIAL DATA in Item 6 herein for each registrant's source
of energy supply.
I-7
At March 3, 1995, the operating affiliates and SEGCO had stockpiles of coal
on hand at their respective coal-fired plants which represented an estimated 38
day recoverable supply, based on projected 1995 nameplate burn requirements. It
is estimated that approximately 56.8 million tons of coal will be consumed in
1995 by the operating affiliates and SEGCO (including those units GEORGIA owns
jointly with OPC, MEAG, Dalton, FP&L and JEA and the units ALABAMA owns jointly
with AEC). The operating affiliates and SEGCO currently have 32 coal contracts.
These contracts cover remaining terms of up to 16 years. Approximately 20% of
1995 estimated coal requirements will be purchased in the spot market.
Management has set a goal whereby the spot market should be utilized, absent the
transition from coal contract expirations, for 20 to 25% of the SOUTHERN
system's coal supply. Additionally, it has been determined that approximately 35
days of recoverable supply of coal is the appropriate level for coal stockpiles.
During 1994, the operating affiliates' and SEGCO's average price of coal
delivered was approximately $42 per ton. The typical sulfur content of coal
purchased under contracts ranges from approximately 0.7% to 3.0% sulfur by
weight. Fuel sulfur restrictions and other environmental limitations have
increased significantly and may increase further the difficulty and cost of
obtaining an adequate coal supply. See Item 1 - BUSINESS - "Regulation -
Environmental Regulation" herein.
Changes in fuel prices are generally reflected in fuel adjustment clauses
contained in rate schedules. See Item 1 - BUSINESS - "Rate Matters -
Rate Structure" 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 an agreement with a
non-affiliated industrial and mining firm to mine coal from ALABAMA's reserves,
as well as its own reserves, for supply to ALABAMA's generating units.
The operating affiliates have renegotiated, bought out or otherwise
terminated various coal supply contracts. For more information on certain of
these transactions see Note 5 to the financial statements of SOUTHERN, GULF and
MISSISSIPPI in Item 8 herein.
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 up to the year
2014, but 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, which was scheduled to begin in 1998.
However, the actual year this service will begin is uncertain. Sufficient
storage capacity currently is available to permit operation into 2003 at Plant
Hatch, into 2009 at Plant Vogtle, and into 2012 and 2014 at Plant Farley units 1
and 2, respectively.
The Energy Act imposed upon utilities with nuclear plants, including ALABAMA
and GEORGIA, obligations for the decontamination and decommissioning of federal
nuclear fuel enrichment facilities. See Note 1 to SOUTHERN's, ALABAMA's and
GEORGIA's financial statements in Item 8 herein.
Territory Served
The territory in which the operating affiliates provide electric service
comprises most of the states of Alabama and Georgia together with the
northwestern portion of Florida and southeastern Mississippi. In this territory
there are non-affiliated electric distribution systems which obtain some or all
of their power requirements either directly or indirectly from the operating
affiliates. The territory has an area of approximately 120,000 square miles and
an estimated population of approximately 11 million.
ALABAMA is engaged, within the State of Alabama, in the generation and
purchase of electricity and the distribution and sale of such electricity at
retail in over 1,000 communities (including Anniston, Birmingham, Gadsden,
Mobile, Montgomery and Tuscaloosa), and at wholesale to 15 municipally-owned
electric distribution systems, 11 of which are served indirectly through sales
to AMEA, and two rural distributing cooperative associations. ALABAMA also
supplies steam service in downtown Birmingham. ALABAMA owns coal reserves near
I-8
its steam-electric generating plant at Gorgas and uses the output of coal from
these reserves in its generating plants. ALABAMA also sells, and cooperates with
dealers in promoting the sale of, electric appliances.
GEORGIA is engaged in the generation and purchase of electricity and the
distribution and sale of such electricity within the State of Georgia at retail
in over 600 communities (including Athens, Atlanta, Augusta, Columbus, Macon,
Rome and Valdosta), as well as in rural areas, and at wholesale currently to 39
electric cooperative associations through OPC, a corporate cooperative of
electric membership cooperatives in Georgia, and to 50 municipalities, 47 of
which are served through MEAG, a public corporation and an instrumentality of
the State of Georgia.
GULF is engaged, within the northwestern portion of Florida, in the
generation and purchase of electricity and the distribution and sale of such
electricity at retail in 71 communities (including Pensacola, Panama City and
Fort Walton Beach), as well as in rural areas, and at wholesale to a
non-affiliated utility and a municipality. GULF also sells electric appliances.
MISSISSIPPI is engaged in the generation and purchase of electricity and the
distribution and sale of such energy within the 23 counties of southeastern
Mississippi, at retail in 123 communities (including Biloxi, Gulfport,
Hattiesburg, Laurel, Meridian and Pascagoula), as well as in rural areas, and at
wholesale to one municipality and four rural electric cooperative associations.
SAVANNAH is engaged, within a five-county area in eastern Georgia, in the
generation and purchase of electricity and the distribution and sale of such
electricity at retail and, as a member of the SOUTHERN system power pool, the
transmission and sale of wholesale energy.
I-9
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,
1994, the registrants derived their respective industrial revenues as shown in
the following table.
======================================================================================================================
SOUTHERN
system ALABAMA GEORGIA GULF MISSISSIPPI SAVANNAH
----------------------------------------------------------------------------------------------------------------------
Textiles 13% 10% 19% *% 3% *%
Chemical 10 14 6 21 14 36
Paper 10 10 10 11 5 28
Primary metal 7 13 5 1 2 *
Stone, clay, glass
and concrete 6 6 8 2 1 4
Utility services 8 8 8 3 9 6
Food 5 3 6 1 5 9
Government 5 2 5 38 10 *
Transportation equipment 3 1 4 1 7 10
Lumber and wood products 4 5 3 2 8 2
Other** 29 28 26 20 36 5
----------------------------------------------------------------------------------------------------------------------
100% 100% 100% 100% 100% 100%
======================================================================================================================
* Less than 0.5%
**Other major sources (5% or more) of industrial revenues were: ALABAMA, coal
mining (5%); GULF, oil and gas extraction (8%); and MISSISSIPPI, petroleum
refining (23%) and electric machinery (5%).
A portion of the area served by SOUTHERN's operating affiliates adjoins the
area served by TVA and its municipal and cooperative distributors. An Act of
Congress limits the distribution of TVA power, unless otherwise authorized by
Congress, to specified areas or customers which generally were those served on
July 1, 1957.
The REA has authority to make loans to cooperative associations or
corporations to enable them to provide electric service to customers in rural
sections of the country. There are 70 electric cooperative organizations
operating in the territory in which the operating affiliates provide electric
service at retail or wholesale.
One of these, AEC, is a generating and transmitting cooperative selling
power to several distributing cooperatives, municipal systems and other
customers in south Alabama and northwest Florida. AEC owns generating units with
approximately 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 REA loans secured by long-term contracts requiring
distributing cooperatives to take their requirements from AEC to the extent such
energy is available. Two of the 14 distributing cooperatives operating in
ALABAMA's service territory obtain a portion of their power requirements
directly from ALABAMA.
Four electric cooperative associations, financed by the REA, operate within
GULF's service area. These cooperatives purchase their full requirements from
AEC and SEPA. A non-affiliated utility also operates within GULF's service area
and purchases a portion of its requirements from GULF.
ALABAMA and GULF have entered into separate agreements with AEC involving
interconnection between the respective systems and, in the case of ALABAMA, the
delivery of capacity and energy from AEC to certain distributing cooperatives.
The rates for the various services provided by ALABAMA and GULF to AEC are based
on formulary approaches which result in the charges by each company being
updated annually, subject to FERC approval. See Item 2 - PROPERTIES -
"Jointly-Owned Facilities" herein for details of ALABAMA's joint-ownership with
AEC of a portion of Plant Miller.
Another of the 70 electric cooperatives is SMEPA, also a generating and
transmitting cooperative. SMEPA has a generating capacity of 739,000 kilowatts
I-10
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, OPC gave GEORGIA notice of its intent to
decrease its purchases of capacity by 250 megawatts beginning in the fall of
1996.
There are 65 municipally-owned electric distribution systems operating in
the territory in which SOUTHERN's operating affiliates provide electric service
at retail or wholesale.
AMEA was organized under an act of the Alabama legislature and is comprised
of 11 municipalities. In 1986, ALABAMA entered into a firm power purchase
contract with AMEA entitling AMEA to scheduled amounts of capacity (to a maximum
of 100 megawatts) for a period of 15 years commencing September 1, 1986. In
October 1991, ALABAMA entered into a second firm power purchase contract with
AMEA entitling AMEA to scheduled amounts of additional capacity (to a maximum 80
megawatts) for a period of 15 years beginning October 1, 1991. In both contracts
the power is being sold to AMEA for its member municipalities that previously
were served directly by ALABAMA as wholesale customers. Under the terms of the
contracts, ALABAMA received payments from AMEA representing the net present
value of the revenues associated with the respective capacity entitlements. See
Note 7 to ALABAMA's financial statements to Item 8 herein for further
information on these contracts.
Forty-six municipally-owned electric distribution systems formerly served on
a full requirements wholesale basis by GEORGIA and one county-owned system now
receive their requirements through MEAG, which was established by a state
statute in 1975. MEAG serves these requirements from self-owned generation
facilities acquired from GEORGIA and through purchases of capacity and energy
from GEORGIA under partial requirements rates. Similarly, since 1977 Dalton has
filled its requirements from generation facilities acquired from GEORGIA and
through partial requirements purchases. The full requirements of two
municipally-owned electric distribution systems are still served at wholesale by
GEORGIA. (See Item 2 - PROPERTIES - "Jointly-Owned Facilities" herein.)
GULF and MISSISSIPPI provide wholesale requirements for one municipal system
each.
GEORGIA has entered into substantially similar agreements with OPC, MEAG and
Dalton providing for the establishment of an integrated transmission system to
carry the power and energy of each. The agreements require an investment by each
party in the integrated transmission system in proportion to its respective
share of the aggregate system load. (See Item 2 - PROPERTIES - "Jointly-Owned
Facilities" herein.)
ALABAMA, GEORGIA, GULF and MISSISSIPPI also have contracts with SEPA (a
federal power marketing agency) providing for the use of those companies'
facilities at government expense to deliver to certain cooperatives and
municipalities, entitled by federal statute to preference in the purchase of
power from SEPA, quantities of power equivalent to the amounts of power
allocated to them by SEPA from certain United States Government hydroelectric
projects.
The 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
I-11
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.
Under and subject to the provisions of its franchises and concessions and
the 1973 State Territorial Electric Service Act, SAVANNAH has the full but
nonexclusive right to serve the City of Savannah, the Towns of Bloomingdale,
Pooler, Garden City, Guyton, Newington, Oliver, Port Wentworth, Rincon, Tybee
Island, Springfield, Thunderbolt, Vernonburg, and in conjunction with a
secondary supplier, the Town of Richmond Hill. In addition, SAVANNAH has been
assigned certain unincorporated areas in Chatham, Effingham, Bryan, Bulloch and
Screven Counties by the Georgia PSC. No other electric utility operates in
competition with SAVANNAH in its service area.
Pursuant to the 1956 Utility Act, the Mississippi PSC issued "Grandfather
Certificates" of convenience and necessity to MISSISSIPPI and to six
distribution rural cooperatives operating in southeastern Mississippi, then
served in whole or in part by MISSISSIPPI, authorizing them to distribute
electricity in certain specified geographically described areas of the state.
The six cooperatives serve approximately 290,000 retail customers in a
certificated area of approximately 10,300 square miles. In areas included in a
"Grandfather Certificate", the utility holding such certificate may, without
further certification, extend its lines up to five miles; other extensions
within that area by such utility, or by other utilities, may not be made except
upon a showing of, and a grant of a certificate of, public convenience and
necessity. Areas included in such a certificate which are subsequently annexed
to municipalities may continue to be served by the holder of the certificate,
irrespective of whether it has a franchise in the annexing municipality. On the
other hand, the holder of the municipal franchise may not extend service into
such newly annexed area without authorization by the Mississippi PSC.
Long-Term Power Sales Agreements
Reference is made to Note 8, 7, 6, 7, 7 and 6 to the financial statements for
SOUTHERN, ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH, respectively, 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. Reference is
made to each registrant's "Management's Discussion and Analysis - Future
Earnings Potential" in Item 7 herein for further discussion of competition.
ALABAMA currently has cogeneration contracts in effect with nine industrial
customers. Under the terms of these contracts, ALABAMA purchases excess
generation of such companies. During 1994, ALABAMA purchased 82.1 million
kilowatt-hours from such companies at a cost of $1.5 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 1994, GEORGIA purchased 4.1 million
kilowatt-hours from such companies at a cost of $56,000. GEORGIA has also
reached an agreement on major terms and conditions of a purchase power
I-12
arrangement whereby GEORGIA would buy electricity during peak periods from a
proposed 200 megawatt cogeneration facility, starting in June 1998. A final
agreement is expected to be completed and filed with the Georgia PSC for
certification during 1995.
GULF currently has cogeneration agreements for "as available" energy in
effect with two industrial customers. During 1994, GULF purchased 237 million
kilowatt-hours from such companies for $3.8 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 1994, SAVANNAH purchased 2.0 million
kilowatt-hours from such companies at a cost of $43,000.
The competition for retail energy sales among competing suppliers of energy
is influenced by various factors, including price, availability, technological
advancements and reliability. These factors are, in turn, affected by, among
other influences, political and environmental considerations, taxation and
supply.
The operating affiliates have experienced, and expect to continue to
experience, competition in their respective retail service territories in
varying degrees as the result of self-generation (as described above) and fuel
switching by customers and other factors. (See also Item 1 - BUSINESS -
"Territory Served" herein for information concerning suppliers of electricity
operating within or near the areas served at retail by the operating
affiliates.) In addition, while the Energy Act does not provide for "retail
wheeling" (i.e., the transmission and distribution by an electric utility to
retail customers within its service territory of energy produced by another
entity), applicable legislative and regulatory bodies may consider imposing such
a requirement in the future, the effect of which may be adverse or, conversely,
prove to be beneficial. Some form of retail wheeling has been mandated in the
states of 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.
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 light of heightened competition in the electric utility
industry and development of the "information superhighway", public debate has
increasingly suggested enacting legislation which would repeal, in whole or in
part, the Holding Company Act.
Federal Power Act
The Federal Power Act subjects the operating affiliates and SEGCO to regulation
by the FERC as companies engaged in the transmission or sale at wholesale of
electric energy in interstate commerce, including regulation of accounting
policies and practices.
ALABAMA and GEORGIA are also subject to the provisions of the Federal Power
Act or the earlier Federal Water Power Act applicable to licensees with respect
to their hydroelectric developments. Among the hydroelectric projects subject to
licensing by the FERC are 14 existing ALABAMA generating stations having an
aggregate installed capacity of 1,582,725 kilowatts and 17 existing GEORGIA
generating stations having an aggregate installed capacity of 859,440 kilowatts.
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 2023. Each of the remaining projects are operating on
annual licenses under the same terms and conditions as their original licenses.
Additionally, the FERC has issued an order granting a combined, 40-year license
for the Yates and Thurlow projects. ALABAMA appealed the FERC order to the U.S.
Court of Appeals for the District of Columbia Circuit with respect to certain
provisions of this license. However, in December 1994 the FERC, in a separate
proceeding, issued an order deleting the contested provisions, but ALABAMA's
appeal remains pending before the Court. 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 will file 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 is
undertaking 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 Project, a pure pumped storage facility of 847,800 kilowatt capacity
scheduled to begin commercial operation in 1995. In 1988, the FERC approved an
amendment to GEORGIA's license for the project, adding OPC as co-licensee and
extending the commercial operation date to 1996. (See Item 1 - BUSINESS -
"Construction Programs - Rocky Mountain Hydroelectric Project" and Item 2 -
PROPERTIES - "Jointly-Owned Facilities" herein.)
Licenses for all projects, excluding those discussed above, expire in the
period 2007-2023 in the case of ALABAMA's projects and in the period 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. In
addition, the FERC recently has issued a policy statement addressing
decommissioning of a licensed project. What may be required to decommission a
project has not been determined.
Atomic Energy Act of 1954
ALABAMA, GEORGIA and Southern Nuclear are subject to the provisions of the
Atomic Energy Act of 1954, as amended, which vests jurisdiction in the NRC over
the construction and operation of nuclear reactors, particularly with regard to
certain public health and safety and antitrust matters. The National
Environmental Policy Act has been construed to expand the jurisdiction of the
NRC to consider the environmental impact of a facility licensed under the Atomic
Energy Act of 1954, as amended.
Reference is made to Notes 1 and 13 to SOUTHERN's, Notes 1 and 11 to
ALABAMA's and Notes 1 and 4 to GEORGIA's financial statements in Item 8 herein
for information on nuclear decommissioning costs and nuclear insurance.
I-14
Additionally, Note 3 to GEORGIA's financial statements contains information
regarding nuclear performance standards imposed by the Georgia PSC that may
impact retail rates.
Environmental Regulation
The operating affiliates and SEGCO are subject to federal, state and local
environmental requirements which, among other things, control emissions of
particulates, sulfur dioxide and nitrogen oxides into the air; the use,
transportation, storage and disposal of hazardous and toxic waste; and
discharges of pollutants, including thermal discharges, into waters of the
United States. The operating affiliates and SEGCO expect to comply with such
requirements, which generally are becoming increasingly stringent, through
technical improvements, the use of appropriate combinations of low-sulfur fuel
and chemicals, addition of environmental control facilities, changes in control
techniques and reduction of the operating levels of generating facilities.
Failure to comply with such requirements could result in the complete shutdown
of individual facilities not in compliance as well as the imposition of civil
and criminal penalties.
Reference is made to each registrant's "Management's Discussion and
Analysis" in Item 7 herein for a discussion of the Clean Air Act and other
environmental legislation and proceedings.
Possible adverse health effects of EMFs from various
sources, including transmission and distribution lines, have been the subject of
a number of studies and increasing public discussion. The scientific research
currently is inconclusive as to whether EMFs may cause adverse health effects.
However, there is the possibility of passage of legislation and promulgation of
rulemaking that would require measures to mitigate EMFs, with resulting
increases in capital and operating costs. In addition, the potential exists for
public liability with respect to lawsuits brought by plaintiffs alleging damages
caused by EMFs.
The operating affiliates' and SEGCO's estimated capital expenditures for
environmental quality control facilities for the years 1995, 1996 and 1997 are
as follows: (in millions)
========================================================
1995 1996 1997
-------------------------------
ALABAMA $28.4 $26.4 $33.4
GEORGIA 21.5 30.7 40.3
GULF 1.4 13.7 17.2
MISSISSIPPI 6.3 0.8 2.1
SAVANNAH 0.5 1.6 0.3
SEGCO 6.5 5.8 3.2
-------------------------------
SOUTHERN
system $64.6 $79.0 $96.5
========================================================
*Such estimates are included in the current construction programs. (See
Item 1 - BUSINESS - "Construction Programs" herein.)
Additionally, each operating affiliate (excluding SAVANNAH) and SEGCO have
incurred costs for environmental remediation of various sites. Reference is made
to each applicable registrant's "Management's Discussion and Analysis" in Item 7
herein for information regarding the registrants' environmental remediation
efforts. Also, see Note 3 to SOUTHERN's and Note 4 to GEORGIA's financial
statements in Item 8 herein for information regarding the identification of
sites that may require environmental remediation by GEORGIA.
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.
I-15
Rate Matters
Rate Structure
The rates and service regulations of the operating affiliates are uniform for
each class of service throughout their respective service areas. Rates for
residential electric service are generally of the block type based upon
kilowatt-hours used and include minimum charges.
Residential and other rates contain separate customer charges. Rates for
commercial service are presently of the block type and, for large customers, the
billing demand is generally used to determine capacity and minimum bill charges.
These large customers' rates are generally based upon usage by the customer
(without differentiation between industrial and commercial classifications)
including those with special features to encourage off-peak usage. Additionally,
the operating affiliates are allowed by their respective PSCs to negotiate the
terms and compensation of service to large customers. With respect to GULF's and
MISSISSIPPI's retail rates, fuel and purchased power costs above base levels
included in the various rate schedules are billed to such customers under the
fuel and energy adjustment clauses. ALABAMA, GEORGIA and SAVANNAH are allowed by
state law to recover fuel and net purchased energy costs through fuel cost
recovery provisions which are adjusted to reflect increases or decreases in such
costs. GULF's recovery of such costs is based upon projections thereof for
six-month periods; any over/under recovery during any such period is reflected
in the subsequent six-month period. The adjustment factors for MISSISSIPPI's
retail and wholesale rates are levelized based on the estimated energy cost for
the year, adjusted for any actual over/under collection from the previous year.
Revenues are adjusted for differences between recoverable fuel costs and amounts
actually recovered in current rates.
Integrated Resource Planning
During 1991, the Georgia legislature passed certain legislation under which both
GEORGIA and SAVANNAH must file Integrated Resource Plans for approval by the
Georgia PSC. The plans must specify how GEORGIA and SAVANNAH each intend to meet
the future electrical needs of their customers through a combination of
demand-side and supply-side resources. The Georgia PSC must pre-certify these
new resources. Once certified, all prudently incurred construction costs will be
recoverable through rates.
In 1992, the Georgia PSC approved Integrated Resource Plans for GEORGIA and
SAVANNAH. See Note 3 to SOUTHERN's and GEORGIA's financial statements in Item 8
herein for information regarding the recovery of GEORGIA's costs incurred from
various demand-side option programs.
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 notes to the financial statements in Item 8 herein.
Rate Increase Applications
Reference is made to Note 3 to each registrant's notes to the financial
statements in Item 8 herein for a discussion of retail and wholesale rate
proceedings. Also discussed therein are the 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.
Employee Relations
The companies of the SOUTHERN system had a total of 27,826 employees on their
payrolls at December 31, 1994.
==========================================================
Employees
at
December 31, 1994
--------------------
ALABAMA 7,996
GEORGIA 11,765
GULF 1,540
MISSISSIPPI 1,535
SAVANNAH 616
SCS 2,612
Southern Nuclear 1,401
Other 361
----------------------------------------------------------
Total 27,826
==========================================================
I-16
The operating affiliates have separate agreements with local unions of the
IBEW generally covering wages, working conditions and procedures for handling
grievances and arbitration. These agreements apply with certain exceptions to
operating, maintenance and construction employees.
ALABAMA has agreements with the IBEW on a three-year contract extending to
August 15, 1995. Upon notice given at least 60 days prior to that date,
negotiations may be initiated with respect to agreement terms to be effective
after such date.
GEORGIA has an agreement with the IBEW covering wages and working conditions
which is in effect through June 30, 1996. GEORGIA also has a contract with the
United Plant Guard Workers of America with respect to Plant Hatch which extends
through September 30, 1995.
GULF has an agreement with a local union of the IBEW on a three-year
contract extending to August 15, 1995.
MISSISSIPPI has agreements with local unions of the IBEW on a contract
extending to August 16, 1995.
Southern Nuclear has an agreement with the IBEW on a three-year contract
extending to August 15, 1995. Upon notice given at least 60 days prior to that
date, negotiations may be initiated with respect to agreement terms to be
effective after such date.
The agreements also subject the terms of the pension plans for the companies
discussed above to collective bargaining with the unions at five-year intervals.
SAVANNAH has three-year labor agreements with the IBEW and the Office and
Professional Employees International Union that expire April 15, 1996 and
December 1, 1996, respectively.
SEI has agreements with local unions of the IBEW and the United Paperworkers
International Union which covers employees of its energy and recovery complex in
Mobile, Alabama. These agreements extend to May 31, 1997.
I-17
Item 2. PROPERTIES
Electric Properties
The operating affiliates and SEGCO, at December 31, 1994, operated 33
hydroelectric generating stations, 31 fossil fuel generating stations and three
nuclear generating stations. The amounts of capacity owned by each company are
shown in the table below.
============================================================
Nameplate
Generating Station Location Capacity
------------------------------------------------------------
(Kilowatts)
Fossil Steam
Gadsden Gadsden, AL 120,000
Gorgas Jasper, AL 1,221,250
Barry Mobile, AL 1,525,000
Chickasaw Chickasaw, AL 40,000
Greene County Demopolis, AL 300,000 (1)
Gaston Unit 5 Wilsonville, AL 880,000
Miller Birmingham, AL 2,532,288 (2)
---------
ALABAMA Total 6,618,538
---------
Arkwright Macon, GA 160,000
Atkinson Atlanta, GA 180,000
Bowen Cartersville, GA 3,160,000
Branch Milledgeville, GA 1,539,700
Hammond Rome, GA 800,000
McDonough Atlanta, GA 490,000
McManus Brunswick, GA 115,000
Mitchell Albany, GA 170,000
Scherer Macon, GA 886,303 (3)
Wansley Carrollton, GA 925,550 (4)
Yates Newnan, GA 1,250,000
---------
GEORGIA Total 9,676,553
---------
Crist Pensacola, FL 1,045,000
Lansing Smith Panama City, FL 305,000
Scholz Chattahoochee, FL 80,000
Daniel Pascagoula, MS 500,000 (5)
Scherer Unit 3 Macon, GA 204,500 (3)
---------
GULF Total 2,134,500
---------
Eaton Hattiesburg, MS 67,500
Sweatt Meridian, MS 80,000
Watson Gulfport, MS 1,012,000
Daniel Pascagoula, MS 500,000 (5)
Greene County Demopolis, AL 200,000 (1)
---------
MISSISSIPPI Total 1,859,500
---------
============================================================
============================================================
Nameplate
Generating Station Location Capacity
------------------------------------------------------------
(Kilowatts)
McIntosh Effingham County, GA 163,117
Kraft Port Wentworth, GA 281,136
Riverside Savannah, GA 102,278
-----------
SAVANNAH Total 546,531
----------
Gaston Units 1-4 Wilsonville, AL
(SEGCO) 1,000,000 (6)
----------
Total Fossil Steam 21,835,622
----------
Nuclear Steam
Farley Dothan, AL
(ALABAMA) 1,720,000
----------
Hatch Baxley, GA 816,630 (7)
Vogtle Augusta, GA 1,060,240 (8)
----------
GEORGIA Total 1,876,870
----------
Total Nuclear Steam 3,596,870
----------
Combustion Turbines
Arkwright Macon, GA 30,580
Atkinson Atlanta, GA 78,720
Bowen Cartersville, GA 39,400
McDonough Atlanta, GA 78,800
McIntosh
Units 3, 4, 7, 8 Effingham County, GA 320,000
McManus Brunswick, GA 481,700
Mitchell Albany, GA 118,200
Wilson Augusta, GA 354,100
Wansley Carrollton, GA 26,322 (4)
----------
GEORGIA Total 1,527,822
----------
Lansing Smith
Unit A (GULF) Panama City, FL 39,400
----------
Chevron Cogenerating
Station Pascagoula, MS 147,292 (9)
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 (6)
----------
Total Combustion Turbines 2,054,054
----------
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
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 (10)
----------
GEORGIA Total 862,480
----------
Total Hydroelectric Facilities 2,445,205
----------
Total Generating Capacity 29,931,751
==========
============================================================
Notes:
(1) Owned by ALABAMA and MISSISSIPPI as
tenants in common in the proportions of 60% and 40%, respectively.
(2) Excludes the capacity owned by AEC. (See Item 2- PROPERTIES -
"Jointly-Owned Facilities" herein.)
(3) Capacity shown is GEORGIA's or GULF's (Unit 3 only) current portion:
8.4% of Units 1 and 2, 75% (25% for GULF) for Unit 3 and 16.55% for
Unit 4 of total plant capacity. See Item 2 - PROPERTIES - "Proposed
Sale of Property" and "Jointly-Owned Facilities" herein.
(4) Capacity shown is GEORGIA's portion (53.5%) of total plant capacity.
(5) Represents 50% of the plant which is owned as tenants in common by
GULF and MISSISSIPPI.
(6) SEGCO is jointly-owned by ALABAMA and GEORGIA. (See Item 1 -
BUSINESS herein.)
(7) Capacity shown is GEORGIA's portion (50.1%) of total plant capacity.
(8) Capacity shown is GEORGIA's portion (45.7%) of total plant capacity.
(9) Generation is dedicated to a single industrial customer.
(10) Includes 5,400 megawatts of capacity for the Flint River Project
damaged by flooding. See Item 1 - BUSINESS - "Regulation -
Federal Power Act" herein.
Except as discussed below under "Titles to Property", the principal plants
and other important units of the SOUTHERN system are owned in fee by the
operating affiliates and SEGCO. It is the opinion of management of each such
company that its operating properties are adequately maintained and are
substantially in good operating condition.
MISSISSIPPI owns a 79-mile length of 500-kilovolt transmission line which is
leased to Gulf States. The line, completed in 1984, extends from Plant Daniel to
the Louisiana state line. Gulf States is paying a use fee over a forty-year
period covering all expenses and the amortization of the original $57 million
cost of the line.
The all-time maximum demand on the SOUTHERN system was 25,936,900 kilowatts
and occurred in July 1993. This amount excludes demand served by generation
retained by MEAG and Dalton and excludes demand associated with power purchased
from OPC and SEPA by its preference customers. At that time, 27,342,700
kilowatts were supplied by SOUTHERN system generation and 1,405,800 kilowatts
(net) were sold to other parties through net purchased and interchanged power.
I-19
The reserve margin for the Southern electric system at that time was 13.2%. The
SOUTHERN system's maximum demand for 1994 of 24,545,700 kilowatts occurred in
August. For information on the other registrant's peak demands, reference is
made to Item 6 - SELECTED FINANCIAL DATA herein.
ALABAMA and GEORGIA will incur significant costs in decommissioning their
nuclear units at the end of their useful lives. (See Item 1 - BUSINESS -
"Regulations - Atomic Energy Act of 1954" and Note 1 to SOUTHERN's, ALABAMA's
and GEORGIA's financial statements in Item 8 herein.)
I-20
Other Electric Generation Facilities
Through special purpose subsidiaries, SOUTHERN owns interests in or operates
independent power production facilities and foreign utility companies. For
further discussion of other SEI projects, see Item 1 - BUSINESS - "New Business
Development" herein. The generating capacity of these utilities (or facilities)
at December 31, 1994, was as follows:
Facilities in Operation
--------------------------------------------------------------------------------------------------------------------
Megawatts of Capacity
------------------------
Facility Location Units Owned Operated Fuel
-------- -------- ----- ----- ---------- ------
Alicura' Argentina 4 551 (1) 1,000 Hydro
Edelnor Chile 22 41 64 Oil
Edelnor Chile 1 14 22 Diesel
Edelnor Chile 2 7 10 Hydro
Freeport Grand Bahama 5 56 113 Oil & Gas
Goodyear New York 1 - 50 Coal (2)
Kalaeloa Hawaii 1 60 180 Oil (2)
Las Vegas Nevada 1 - 50 Gas (2)
Mobile Alabama 3 105 105 Waste &
by-products (2)
Penal Trinidad and Tobago 5 92 236 Gas
Port of Spain Trinidad and Tobago 6 120 308 Gas
Pt. Lisas Trinidad and Tobago 10 247 634 Gas
--------------------------------------------------------------------------------------------------------------------
Total Capacity 1,293 2,772
====================================================================================================================
Facilities Under Development
--------------------------------------------------------------------------------------------------------------------
Megawatts of Capacity
--------------------------------
Facility Location Owned Operated Fuel
-------- -------- ------- ---------- ------
Birchwood Virginia 110 220 Coal (2)
Edelnor Chile 98 150 Coal
--------------------------------------------------------------------------------------------------------------------
Total Capacity 208 370
====================================================================================================================
Notes: (1) Represents megawatts of capacity under a concession agreement
expiring in the year 2023.
(2) Cogeneration facility.
I-21
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:
Total Percentage Ownership
Capacity ALABAMA AEC GEORGIA OPC MEAG DALTON FP&L JEA FPC
-------- -----------------------------------------------------------------------------
(Megawatts)
Plant Miller
Units 1 and 2 1,320 91.8% 8.2% -% -% -% -% -% -% -%
Plant Hatch 1,630 - - 50.1 30.0 17.7 2.2 - - -
Plant Vogtle 2,320 - - 45.7 30.0 22.7 1.6 - - -
Plant Scherer
Units 1 and 2 1,636 - - 8.4 60.0 30.2 1.4 - - -
Unit 4 818 - - 16.6 - - - 65.7 17.7 -
Plant Wansley 1,779 - - 53.5 30.0 15.1 1.4 - - -
Rocky Mountain 848 - - 25.0* 75.0 - - - - -
Intercession City, FL 150 - - 33.3* - - - - - 66.7
*Estimated ownership at completion.
==========================================================================================================================
ALABAMA and GEORGIA have contracted to operate and maintain the respective
units in which each has an interest (other than Rocky Mountain and Intercession
City, as described below) as agent for the joint owners. See "Proposed Sale of
Property" below for a description of the proposed sale of GEORGIA's remaining
unsold ownership interest in Plant Scherer Unit 4.
In connection with the joint ownership arrangements for Plant Vogtle,
GEORGIA has remaining commitments to purchase declining fractions of OPC's and
MEAG's capacity and energy until 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 in the Statements of Income in Item 8 herein.
In December 1988, GEORGIA and OPC completed a joint ownership agreement for
the Rocky Mountain project under which GEORGIA will retain its present
investment in the project and OPC will finance, complete and operate the
facility. Upon completion (scheduled for 1995), GEORGIA will own an undivided
interest in the project equal to the proportion its investment bears to the
total investment in the project (excluding each party's cost of funds and ad
valorem taxes). For purposes of the ownership formula, GEORGIA's investment will
be expressed in nominal dollars and OPC's investment will be expressed in
constant 1987 dollars. Based on current cost estimates, GEORGIA's final
ownership is estimated at approximately 25% of the project at completion.
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 in early 1996, and will be constructed, operated, and
maintained by FPC. GEORGIA will have a one-third interest in the 150-megawatt
unit, with retention 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.
I-22
Proposed Sale of Property
GEORGIA has completed three of four separate transactions to sell Unit 4 of
Plant Scherer to FP&L and JEA for a total price of approximately $808 million,
including any gains on these transactions. FP&L would eventually own
approximately 76.4% of this unit, with JEA owning the remainder. GEORGIA will
continue to operate the unit.
The completed and scheduled remaining transactions are as follows:
========================================================
Percentage
Closing of Sales
Date Capacity Ownership Price
--------------------------------------------------------
(Megawatts) (in millions)
July 1991 290 35.46% $291
June 1993 258 31.44 253
June 1994 135 16.55 133
June 1995 135 16.55 131
--------------------------------------------------------
Total 818 100.00% $808
========================================================
Plant Scherer, a jointly owned coal-fired generating plant, has four units
with a total capacity of 3,272 megawatts. Unit 4 was completed in 1989.
Titles to Property
The operating affiliates' and SEGCO's interests in the principal plants (other
than certain pollution control facilities, one small hydroelectric generating
station leased by GEORGIA and the land on which four combustion turbine
generators of MISSISSIPPI are located, which is held by easement) and other
important units of the respective companies are owned in fee by such companies,
subject only to the liens of applicable mortgage indentures (except for SEGCO)
and to excepted encumbrances as defined therein. The operating affiliates own
the fee interests in certain of their principal plants as tenants in common.
(See Item 2 - PROPERTIES - "Jointly-Owned Facilities" herein.) Properties such
as electric transmission and distribution lines and steam heating mains are
constructed principally on rights-of-way which are maintained under franchise or
are held by easement only. A substantial portion of lands submerged by
reservoirs is held under flood right easements. In substantially all of its coal
reserve lands, SEGCO owns or will own the coal only, with adequate rights for
the mining and removal thereof.
Property Additions and Retirements
During the period from January 1, 1990, to December 31, 1994, the operating
affiliates, SEGCO, and others (i.e. SCS, Southern Nuclear and, beginning in
1993, various of the special purpose subsidiaries) recorded gross property
additions and retirements as follows:
============================================================
Gross Property
Additions Retirements
-------------- -----------
(in millions)
ALABAMA (1) $2,182 $ 336
GEORGIA (2) 2,928 2,030
GULF 349 118
MISSISSIPPI 415 69
SAVANNAH 173 15
SEGCO 81 12
Other (3) 262 87
------------------------------------------------------------
SOUTHERN
system $6,390 $2,667
============================================================
(1) Includes approximately $62 million attributable to property sold to AEC
in 1992.
(2) Includes approximately $612 million attributable to property sold to
OPC, FP&L and JEA, but excludes $231 million from the write-off of
certain Plant Vogtle costs in 1990.
(3) Net of intercompany eliminations.
Item 3. LEGAL PROCEEDINGS
(1) Stepak v. certain SOUTHERN officials
(U.S. District Court for the Southern District of Georgia)
In April 1991, two SOUTHERN stockholders filed a derivative action suit
against certain current and former directors and officers of SOUTHERN.
The suit alleges violations of RICO by officers and breaches of
fiduciary duty and gross negligence by all defendants resulting from
alleged fraudulent accounting for spare parts, illegal political
campaign contributions, violations of federal securities laws involving
misrepresentations and omissions in SEC filings, and concealment of the
I-23
foregoing acts. The complaint seeks damages, including treble damages
pursuant to RICO, in an unspecified amount, which if awarded, would be
payable to SOUTHERN. The plaintiffs' amended complaint was dismissed by
the court in March 1992. The court ruled the plaintiffs had failed to
present adequately their allegation that the SOUTHERN board of
directors' refusal of an earlier demand by the plaintiffs was wrongful.
In April 1994, the U. S. Court of Appeals for the Eleventh 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. This action is still pending.
(2) Johnson v. ALABAMA
(Circuit Court of Shelby County, Alabama)
In September 1990, two customers of ALABAMA filed a civil complaint in
the Circuit Court of Shelby County, Alabama, against ALABAMA seeking to
represent all persons who, prior to June 23, 1989, entered into
agreements with ALABAMA for the financing of heat pumps and other
merchandise purchased from vendors other than ALABAMA. The plaintiffs
contended that ALABAMA was required to obtain a license under the
Alabama Consumer Finance Act to engage in the business of making
consumer loans. The plaintiffs were seeking an order declaring these
agreements null and void and requiring ALABAMA to refund all payments,
principal and interest, made under these agreements. The aggregate
amount under these agreements, together with interest paid, currently is
estimated to be $40 million.
In June 1993, the court ordered ALABAMA to refund or forfeit interest
of approximately $10 million because of ALABAMA's failure to obtain such
license. However, the court's order did not require any refund or
forfeiture with respect to any principal payments under the agreements
at issue. ALABAMA has appealed the court's order to the Supreme Court of
Alabama.
The final outcome of this matter cannot be determined; however, in
management's opinion, the final outcome will not have a material adverse
effect on SOUTHERN's or ALABAMA's financial statements.
(3) In January 1995, GEORGIA 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. While
GEORGIA 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 may be ultimately
responsible.
The final outcome of this matter cannot now be determined; however,
in management's opinion, based on the nature and extent of GEORGIA's
activities relating to the site, the final outcome will not have a
material adverse effect on SOUTHERN's or GEORGIA's financial statements.
(4) 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 $28 million
and $32 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 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.
I-24
The final outcome of this matter cannot now be determined; however,
in management's opinion, the final outcome will not have a material
adverse effect on SOUTHERN's or GEORGIA's financial statements.
See Item 1 - BUSINESS - "Construction Programs," "Fuel Supply," "Regulation
- Federal Power Act" and "Rate Matters" for a description of certain other
administrative and legal proceedings discussed therein.
Additionally, each of the operating affiliates, SEI, SCS, Southern Nuclear,
SDIG 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. In management's opinion these various actions will not
have a material adverse effect on any of the registrants' financial statements.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
I-25
EXECUTIVE OFFICERS OF SOUTHERN
(Inserted in Part I in accordance with Regulation S-K, Item 401(b),
Instruction 3)
A. W. Dahlberg
Chairman, President and Chief Executive Officer
Age 54 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 46
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 50
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 55
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 46
Elected in 1995; President and Chief Executive Officer of
MISSISSIPPI since 1991. 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 and Chief Financial Officer
Age 55
Elected in 1986; responsible primarily for all aspects of
financing for SOUTHERN. He has served as Executive
Vice President of SCS since 1986.
Bill M. Guthrie
Vice President
Age 61
Elected in 1991; serves as Chief Production Officer for
the SOUTHERN system. Senior Executive Vice
President of SCS effective January 1994. He has also
served as Executive Vice President of ALABAMA since
1988.
Each of the above is currently an officer of SOUTHERN, serving a term running
from the last annual meeting of the directors (May 25, 1994) for one year until
the next annual meeting or until his successor is elected and qualified.
I-26
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
------ -----
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
1993
First Quarter $21-3/8 $18-3/8
Second Quarter 22-1/2 19-3/8
Third Quarter 23 20-1/2
Fourth Quarter 23-5/8 20-3/4
---------------------------------------------------
There is no market for the other registrants' common stock, all of
which is owned by SOUTHERN. On February 28, 1995, the closing price
of SOUTHERN's common stock was $20-5/8.
(b) Number of SOUTHERN's common stockholders at December 31, 1994:
234,927
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 1994 1993
----------------------------------------------------
SOUTHERN First $191,262 $180,381
Second 191,262 180,948
Third 191,475 181,892
Fourth 192,758 182,351
ALABAMA First 66,500 62,900
Second 67,000 63,100
Third 66,900 63,400
Fourth 67,600 63,500
GEORGIA First 106,600 100,100
Second 107,200 100,400
Third 107,200 100,800
Fourth 108,300 101,100
GULF First 10,900 10,400
Second 11,000 10,400
Third 11,000 10,500
Fourth 11,100 10,500
MISSISSIPPI First 8,500 7,200
Second 8,500 7,200
Third 8,500 7,300
Fourth 8,600 7,300
SAVANNAH First 4,100 4,500
Second 4,100 5,500
Third 4,100 5,500
Fourth 4,000 5,500
-----------------------------------------------------
In January 1994, SOUTHERN's board of directors authorized a two-for-one
common stock split in the form of a stock distribution for each share held as of
February 7, 1994. For all reported common stock data, the number of common
shares outstanding and per share amounts for earnings, dividends, and market
price have been adjusted to reflect the stock distribution.
II-1
The dividend paid per share by SOUTHERN was 28.5(cent) for each quarter of
1993 and 29.5(cent) for each quarter of 1994. The dividend paid on SOUTHERN's
common stock for the first quarter of 1995 was raised to 30.5(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, 1994, were as follows:
========================================================
Retained Restricted
Earnings Amount
---------- -----------
(in millions)
ALABAMA $1,085 $ 807
GEORGIA 1,413 742
GULF 169 101
MISSISSIPPI 144 94
SAVANNAH 99 57
Consolidated 3,191 1,805
--------------------------------------------------------
Item 6. SELECTED FINANCIAL DATA
SOUTHERN. Reference is made to information under the heading "Selected
Consolidated Financial and Operating Data," contained herein at pages II-38
through II-49.
ALABAMA. Reference is made to information under the heading "Selected
Financial and Operating Data," contained herein at pages II-79 through II-92.
GEORGIA. Reference is made to information under the heading "Selected
Financial and Operating Data," contained herein at pages II-127 through II-141.
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-247 through II-260.
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND
FINANCIAL CONDITION
SOUTHERN. Reference is made to information under the heading "Management's
Discussion and Analysis of Results of Operations and Financial Condition,"
contained herein at pages II-8 through II-15.
ALABAMA. Reference is made to information under the heading "Management's
Discussion and Analysis of Results of Operations and Financial Condition,"
contained herein at pages II-53 through II-59.
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-145 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 1994 FINANCIAL STATEMENTS
Page
The Southern Company and Subsidiary Companies:
Report of Independent Public Accountants (in which their opinion on the
financial statements includes an explanatory paragraph which states that an
uncertainty exists with respect to the actions of the regulators regarding
recoverability of the investment in the Rocky Mountain pumped storage
hydroelectric project) II-7
Consolidated Statements of Income for the Years Ended December 31, 1994, 1993 and 1992 II-16
Consolidated Statements of Retained Earnings for the Years Ended
December 31, 1994, 1993 and 1992 II-16
Consolidated Statements of Cash Flows for the Years Ended December 31, 1994, 1993 and 1992 II-17
Consolidated Balance Sheets at December 31, 1994 and 1993 II-18
Consolidated Statements of Capitalization at December 31, 1994 and 1993 II-20
Consolidated Statements of Paid-In Capital for the Years Ended December 31, 1994, 1993 and 1992 II-21
Notes to Financial Statements II-22
ALABAMA:
Report of Independent Public Accountants II-52
Statements of Income for the Years Ended December 31, 1994, 1993 and 1992 II-60
Statements of Cash Flows for the Years Ended December 31, 1994, 1993 and 1992 II-61
Balance Sheets at December 31, 1994 and 1993 II-62
Statements of Capitalization at December 31, 1994 and 1993 II-64
Statements of Retained Earnings for the Years Ended December 31, 1994, 1993 and 1992 II-65
Notes to Financial Statements II-66
GEORGIA:
Report of Independent Public Accountants (in which their opinion on the
financial statements includes an explanatory paragraph which states that
an uncertainty exists with respect to the actions of the regulators
regarding the recoverability of Georgia Power's investment in the Rocky
Mountain pumped storage hydroelectric project) II-95
Statements of Income for the Years Ended December 31, 1994, 1993 and 1992 II-104
Statements of Cash Flows for the Years Ended December 31, 1994, 1993 and 1992 II-105
Balance Sheets at December 31, 1994 and 1993 II-106
Statements of Capitalization at December 31, 1994 and 1993 II-108
Statements of Retained Earnings for the Years Ended December 31, 1994, 1993 and 1992 II-109
Statements of Paid-In Capital for the Years Ended December 31, 1994, 1993 and 1992 II-109
Notes to Financial Statements II-110
II-3
Page
GULF:
Report of Independent Public Accountants II-144
Statements of Income for the Years Ended December 31, 1994, 1993 and 1992 II-152
Statements of Cash Flows for the Years Ended December 31, 1994, 1993 and 1992 II-153
Balance Sheets at December 31, 1994 and 1993 II-154
Statements of Capitalization at December 31, 1994 and 1993 II-156
Statements of Retained Earnings for the Years Ended December 31, 1994, 1993 and 1992 II-158
Statements of Paid-In Capital for the Years Ended December 31, 1994, 1993 and 1992 II-158
Notes to Financial Statements II-159
MISSISSIPPI:
Report of Independent Public Accountants II-186
Statements of Income for the Years Ended December 31, 1994, 1993 and 1992 II-194
Statements of Cash Flows for the Years Ended December 31, 1994, 1993 and 1992 II-195
Balance Sheets at December 31, 1994 and 1993 II-196
Statements of Capitalization at December 31, 1994 and 1993 II-198
Statements of Retained Earnings for the Years Ended December 31, 1994, 1993 and 1992 II-199
Statements of Paid-In Capital for the Years Ended December 31, 1994, 1993 and 1992 II-199
Notes to Financial Statements II-200
SAVANNAH:
Report of Independent Public Accountants II-226
Statements of Income for the Years Ended December 31, 1994, 1993 and 1992 II-233
Statements of Cash Flows for the Years Ended December 31, 1994, 1993 and 1992 II-234
Balance Sheets at December 31, 1994 and 1993 II-235
Statements of Capitalization at December 31, 1994 and 1993 II-237
Statements of Retained Earnings for the Years Ended December 31, 1994, 1993 and 1992 II-238
Statements of Paid-In Capital for the Years Ended December 31, 1994, 1993 and 1992 II-238
Notes to Financial Statements II-239
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 1994 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 four directors
who are not employees, provides a broad overview of management's financial
reporting and control functions. Periodically, this committee meets with
management, the internal auditors, and the independent public accountants to
ensure that these groups are fulfilling their obligations and to discuss
auditing, internal controls, and financial reporting matters. The internal
auditors and independent public accountants have access to the members of the
audit committee at any time.
Management believes that its policies and procedures provide reasonable
assurance that the company's operations are conducted according to a high
standard of business ethics.
In management's opinion, the 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. As discussed in Note 4
to the financial statements, an uncertainty exists with respect to the actions
of regulators regarding recoverability of the investment in the Rocky Mountain
pumped storage hydroelectric project. The outcome of this uncertainty cannot be
determined until a regulatory review is completed. Accordingly, no provision for
any write-down of the costs associated with the Rocky Mountain project resulting
from the potential actions of the Georgia Public Service Commission has been
made in the accompanying financial statements.
/s/ A. W. Dahlberg
A. W. Dahlberg
Chairman, President, and Chief Executive Officer
/s/ W. L. Westbrook
W. L. Westbrook
Financial Vice President and Chief Financial Officer
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, 1994 and 1993, 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, 1994. These
financial statements are the responsibility of the company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements (pages 11-16 through II-37)
referred to above present fairly, in all material respects, the financial
position of The Southern Company and subsidiary companies as of December 31,
1994 and 1993, and the results of their operations and their cash flows for the
periods stated, in conformity with generally accepted accounting principles.
As explained in Notes 2 and 9 to the financial statements, effective January
1, 1993, The Southern Company changed its methods of accounting for
postretirement benefits other than pensions and for income taxes.
As more fully discussed in Note 4 to the financial statements, an
uncertainty exists with respect to the actions of the regulators regarding
recoverability of the investment in the Rocky Mountain pumped storage
hydroelectric project. The outcome of this uncertainty cannot be determined
until a regulatory review is completed. Accordingly, no provision for any
write-down of the costs associated with the Rocky Mountain project resulting
from the potential actions of the Georgia Public Service Commission has been
made in the accompanying financial statements.
/s/ Arthur Andersen LLP
Atlanta, Georgia
February 15, 1995
II-7
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
The Southern Company and Subsidiary Companies 1994 Annual Report
RESULTS OF OPERATIONS
Earnings and Dividends
The Southern Company's 1994 earnings were $989 million or $1.52 per share, a
decrease of $13 million or 5 cents per share from the year 1993. Earnings were
significantly affected in 1994 by efforts related to the company's strategy to
remain a low-cost producer of electricity and a high-quality investment.
These efforts included work force reduction programs in 1994 and additional
investments in companies related to the core business of electricity. These
investments have put downward pressure on earnings and return on equity, and
that trend will continue in the near term. However, the investments should
support growth and strength in the financial condition of the company as it
emerges into a more competitive and global environment.
Costs related to the work force reduction programs decreased earnings by $61
million or 9 cents per share. These costs should be recovered through future
savings in about two years. Additional non-operating or non-recurring items
affected earnings in 1994 and 1993. After excluding these items in both years,
1994 earnings from operations of the ongoing business of selling electricity
were $1.0 billion -- or $1.58 per share -- an increase of $11 million compared
with 1993. The non-operating items that affected earnings were as follows:
Consolidated Earnings
Net Income Per Share
----------------- -----------------
1994 1993 1994 1993
----------------- -----------------
(in millions)
Earnings as reported $ 989 $1,002 $1.52 $1.57
-----------------------------------------------------------------
Work force reduction
programs in 1994 61 - .09 -
Sale of facilities (28) (18) (.04) (.03)
Environmental
cleanup 5 25 .01 .04
Transportation fleet
reduction - 13 - .02
Gulf States related - (6) - (.01)
-----------------------------------------------------------------
Total non-operating 38 14 .06 .02
-----------------------------------------------------------------
Earnings from
operations $1,027 $1,016 $1.58 $1.59
=================================================================
Amount and
percent change $11 1.1% $(0.01) (0.6)%
-----------------------------------------------------------------
In 1994, non-operating items -- both positive and negative -- had an impact
on earnings, which resulted in a net reduction of $38 million. These items were:
(1) Costs associated with work force reduction programs implemented in 1994
decreased earnings. (2) The third in a series of four separate transactions to
sell Plant Scherer Unit 4 to two Florida utilities and the sale of a 50 percent
interest in a cogeneration facility in Virginia increased earnings. (3)
Environmental cleanup costs decreased earnings.
Items not discussed above that affected 1993 earnings were: (1)
Costs associated with a transportation fleet reduction program decreased
earnings. (2) Transactions related to a 1991 settlement agreement with Gulf
States Utilities Company increased earnings.
In January 1994, The Southern Company board of directors approved a
two-for-one common stock split in the form of a stock distribution. All common
stock data reported reflect the stock distribution. Dividends paid on common
stock during 1994 were $1.18 per share or 29 1/2 cents per quarter. During 1993
and 1992, dividends paid per share were $1.14 and $1.10, respectively. In
January 1995, The Southern Company board of directors raised the quarterly
dividend to 30 1/2 cents per share or an annual rate of $1.22 per share.
Revenues
Operating revenues decreased in 1994 and increased in 1993 and 1992 as a result
of the following factors:
Increase (Decrease)
From Prior Year
----------------------------
1994 1993 1992
----------------------------
(in millions)
Retail --
Change in base rates $ 3 $ 3 $ 137
Sales growth 153 104 138
Weather (177) 198 (113)
Fuel recovery and other (107) 199 (55)
---------------------------------------------------------------
Total retail (128) 504 107
---------------------------------------------------------------
Sales for resale --
Within service area (87) 38 (8)
Outside service area (108) (184) (87)
---------------------------------------------------------------
Total sales for resale (195) (146) (95)
Other operating revenues 131 58 11
---------------------------------------------------------------
Total operating revenues $(192) $416 $ 23
==============================================================
Percent change (2.3)% 5.2% 0.3%
--------------------------------------------------------------
Retail revenues of $7.1 billion in 1994 decreased 1.8 percent from last
year, compared with an increase of 7.4 percent in 1993. Under fuel cost recovery
II-8
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
The Southern Company and Subsidiary Companies 1994 Annual Report
provisions, fuel revenues generally equal fuel expense -- including the fuel
component of purchased energy -- and do not affect net income.
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. Sales for resale
revenues within the service area were $447 million in 1993, up 9.2 percent from
the prior year. This increase resulted primarily from the prolonged hot summer
weather, which increased the demand for electricity.
Revenues from sales to utilities outside the service area under long-term
contracts consist of capacity and energy components. Capacity revenues reflect
the recovery of fixed costs and a return on investment under the contracts.
Energy is generally sold at variable cost. The capacity and energy components
were as follows:
1994 1993 1992
--------------------------------
(in millions)
Capacity $276 $350 $457
Energy 176 230 330
-----------------------------------------------------
Total $452 $580 $787
=====================================================
Capacity revenues decreased in 1994 and 1993 because the amount of capacity
under contract declined by some 400 megawatts and 500 megawatts, respectively.
In 1995, the contracted capacity will decline another 100 megawatts. 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 1994 and the percent change by year were as
follows:
(billions of Amount Percent Change
kilowatt-hours) ------ ------------------------
1994 1994 1993 1992
---- ------------------------
Residential 35.8 (2.6)% 9.5% 0.0%
Commercial 34.1 3.8 5.9 2.1
Industrial 50.3 3.2 1.9 3.8
Other 0.9 3.8 4.6 (4.8)
-----
Total retail 121.1 1.6 5.3 2.1
Sales for resale --
Within service area 8.1 (38.5) 9.5 (1.7)
Outside service area 10.8 (13.5) (25.2) (16.2)
-----
Total 140.0 (3.4) 2.1 (0.7)
=================================================================
The rate of increase in 1994 retail energy sales was suppressed by the
impact of weather. Residential energy sales registered the first annual decrease
in more than a decade as a result of milder-than-normal summer weather in 1994,
compared with the extremely hot summer of 1993. 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 1995 through 2005.
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 continue to decrease,
primarily as a result of the scheduled decline in megawatts of capacity under
contract.
Expenses
Total operating expenses of $6.6 billion for 1994 declined 2.1 percent compared
with the prior year. The costs to produce and deliver electricity in 1994
declined by $297 million, primarily as a result of less energy being sold and
continued effective cost controls. However, certain other expenses in 1994
increased compared with expenses in 1993. Depreciation expenses and property
taxes increased by $41 million as a result of additional utility plant being
placed into service. The work force reduction programs in 1994 increased
expenses by $100 million. The amortization of deferred expenses related to Plant
Vogtle increased by $39 million in 1994 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 1993, operating expenses of $6.7 billion were up 6.5 percent compared
with 1992. The increase was attributable to higher production expenses of $75
million to meet increased energy demands and an additional $50 million in
depreciation expenses and property taxes. The transportation fleet reduction
program and environmental cleanup costs discussed earlier increased expenses by
some $62 million. Also, a $67 million change in deferred Plant Vogtle expenses
compared with the amount in 1992 contributed to the rise in total operating
expenses.
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
II-9
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
The Southern Company and Subsidiary Companies 1994 Annual Report
nuclear generating units. The amount and sources of generation and the average
cost of fuel per net kilowatt-hour generated were as follows:
1994 1993 1992
----------------------
Total generation
(billions of kilowatt-hours) 142 144 140
Sources of generation
(percent) --
Coal 75 78 77
Nuclear 19 17 17
Hydro 5 4 5
Oil and gas 1 1 1
Average cost of fuel per net
kilowatt-hour generated
(cents) --
Coal 1.80 1.90 1.86
Nuclear 0.56 0.54 0.54
Oil and gas 3.99 4.34 4.81
Total 1.56 1.67 1.62
------------------------------------------------------------
Fuel and purchased power costs of $2.3 billion in 1994 decreased $266 million
or 10 percent compared with 1993, primarily because 3.1 billion fewer
kilowatt-hours were needed to meet customer requirements. Also, the decrease in
these costs was attributable to a lower average cost of fuel per net
kilowatt-hour generated. Fuel and purchased power expenses of $2.6 billion in
1993 increased 1.3 percent compared with the prior year because of increased
energy demands and a slightly higher average cost of fuel per net kilowatt-hour
generated.
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 discussed earlier. For 1993, income taxes increased
$69 million compared with the prior year. The increase was primarily
attributable to a 1 percent increase in the corporate federal income tax rate
effective January 1993, and the increase in taxable income from operations.
Total gross interest charges and preferred stock dividends continued to
decline from amounts reported in the previous year. The declines are
attributable to lower interest rates and significant refinancing activities in
1993 and 1992. In 1994, these costs were $765 million -- down $66 million or 8.0
percent. These costs for 1993 decreased $21 million. As a result of favorable
market conditions, $1.0 billion in 1994, $3.0 billion in 1993, and $2.4 billion
in 1992 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.
Future Earnings Potential
The results of operations for the past three years are not necessarily
indicative of future earnings potential. The level of future earnings depends on
numerous factors ranging from growth in energy sales to a less regulated, more
competitive environment.
Georgia Power has completed three of four separate transactions to sell Unit
4 of Plant Scherer to two Florida utilities. The remaining transaction is
scheduled to take place in 1995 with the after-tax gain currently estimated to
total approximately $12 million. See Note 7 to the financial statements for
additional information.
In 1994, work force reduction programs were implemented, reducing earnings by
$61 million. These actions will assist in efforts to control growth in future
operating expenses.
See Note 4 to the financial statements for information on an uncertainty
regarding full recovery of an investment in the Rocky Mountain pumped storage
hydroelectric project scheduled to be in commercial operation in 1995.
Future earnings in the near term will depend upon growth in energy sales,
which are subject to a number of factors. Traditionally, these factors have
included changes in contracts with neighboring utilities, energy conservation
practiced by customers, the elasticity of demand, weather, competition, and the
rate of economic growth in the company's service area. However, the Energy
Policy Act of 1992 (Energy Act) 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
II-10
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
The Southern Company and Subsidiary Companies 1994 Annual Report
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 may enhance the incentive for IPPs to build cogeneration plants
for a utility's large industrial and commercial customers and sell excess energy
generation to other utilities. Although the Energy Act does not require
transmission access to retail customers, retail wheeling initiatives are rapidly
evolving and becoming very prominent issues in several states. 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.
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 International (Southern Electric) -- founded in
1981 -- is focusing on international and domestic cogeneration, the independent
power market, and the privatization of generating facilities in the
international market. During 1994, additional investments were made in entities
that own and operate generating facilities in domestic and various international
markets. At December 31, 1994, Southern Electric's investment in these
facilities amounted to $436 million. In the near term, Southern Electric is
expected to have minimal effect on earnings, but the potential exists that it
could be a prime contributor to future earnings growth.
Southern Communications Services is constructing a wireless communications
system to provide services beginning in 1995 to Southern Company subsidiaries
and to other parties. It is anticipated that the operations of this new
subsidiary, at least in its early years, will negatively affect earnings and
cash flow.
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.
The ability to defer major construction projects in conjunction with
regulatory precertification approval processes for both new plant additions and
purchase power contracts should minimize the possibility of not being able to
fully recover additional costs.
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.
The Southern 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. 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 nuclear decommissioning. If current electric utility industry
accounting practices for decommissioning are changed: (1) Annual provisions for
decommissioning could increase. (2) The estimated cost for decommissioning may
be required to be recorded as a liability in the Consolidated Balance Sheets. In
II-11
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
The Southern Company and Subsidiary Companies 1994 Annual Report
management's opinion -- should these changes be required -- the changes would
not have a significant adverse effect on results of operations because of the
company's current and expected future ability to recover decommissioning costs
through rates. See Note 1 to the financial statements under "Depreciation and
Nuclear Decommissioning" for additional information.
The 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."
FINANCIAL CONDITION
Overview
The Southern Company's financial condition continues to remain at the strongest
level since the mid-1980s. Earnings from operations continued to increase in
1994 and exceeded $1 billion. Based on this performance, in January 1995, The
Southern Company board of directors increased the common stock dividend for the
fourth consecutive year.
Another major change in The Southern Company's financial condition was gross
property additions of $1.5 billion to utility plant. The majority of funds
needed for gross property additions since 1991 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, 1994, the
credit risk for derivatives outstanding was not material.
Capital Structure
The company achieved a ratio of common equity to total capitalization --
including short-term debt -- of 44.4 percent in 1994, compared with 43.8 percent
in 1993 and 42.8 percent in 1992. The company's goal is to maintain the common
equity ratio generally within a range of 40 percent to 45 percent.
During 1994, the operating companies sold $185 million of first mortgage
bonds and, through public authorities, $749 million of pollution control revenue
bonds. Preferred securities of $100 million were issued in 1994. The operating
companies continued to reduce financing costs by retiring higher-cost bonds.
Retirements, including maturities, of bonds totaled $973 million during 1994,
$2.5 billion during 1993, and $2.8 billion during 1992. Retirements of preferred
stock totaled $1 million during 1994, $516 million during 1993, and $326 million
during 1992. As a result, the composite interest rate on long-term debt
decreased from 8.8 percent at December 31, 1991, to 7.2 percent at December 31,
1994. During this same period, the composite dividend rate on preferred stock
declined from 7.7 percent to 6.7 percent.
In 1994, The Southern Company raised $159 million from the issuance of new
common stock under the company's various stock plans. An additional $120 million
of new common stock was issued through a public offering in early 1994. At the
close of 1994, the company's common stock had a market value of $20.00 per
share, compared with a book value of $12.47 per share. The market-to-book value
ratio was 160 percent at the end of 1994, compared with 184 percent at year-end
1993 and 168 percent at year-end 1992.
Capital Requirements for Construction
The construction program of the operating companies is budgeted at $1.4 billion
for 1995, $1.3 billion for 1996, and $1.3 billion for 1997. The total is $4.0
billion for the three years. Actual construction costs may vary from this
estimate because of factors such as changes in environmental regulations;
changes in existing nuclear plants to meet new regulations; revised load
projections; the cost and efficiency of construction labor, equipment, and
materials; and the cost of capital. In addition, there can be no assurance that
costs related to capital expenditures will be fully recovered.
II-12
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
The Southern Company and Subsidiary Companies 1994 Annual Report
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
1,100 megawatts of capacity is planned to be completed by 1997 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 $718
million will be required by the end of 1997 for present sinking fund
requirements and maturities of long-term debt. Also, the operating 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 -- will have a
significant impact on The Southern Company. Specific reductions in sulfur
dioxide and nitrogen oxide emissions from fossil-fired generating plants will be
required in two phases. Phase I compliance began in 1995 and affected eight
generating plants -- some 10,000 megawatts of capacity or 35 percent of total
capacity -- in the Southern electric system. Phase II compliance is required in
2000, and all fossil-fired generating plants in the Southern electric system
will be affected.
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 expects to achieve Phase I sulfur dioxide compliance at
the eight affected plants by switching to low-sulfur coal, which has required
some equipment upgrades. This compliance strategy is expected to result in
unused emission allowances being banked for later use. Additional construction
expenditures were required to install equipment for the control of nitrogen
oxide emissions at these eight plants. Also, continuous emissions monitoring
equipment will be installed on all fossil-fired units. Construction expenditures
for Phase I compliance are estimated to total approximately $300 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. 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 2 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.
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 has issued
II-13
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
The Southern Company and Subsidiary Companies 1994 Annual Report
rules for the application of reasonably available control technology to reduce
nitrogen oxide emissions by May 31, 1995. The results of these new rules require
nitrogen oxide controls, above Title IV requirements, on some Georgia Power
plants. Final attainment rules, based on modeling studies, could require
installation of additional controls for nitrogen oxide emissions to meet the
1999 deadline. A decision on new requirements is expected in 1996. 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 by November 1995. 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.
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.
The EPA continues to evaluate the need for a new short-term ambient air
quality standard for sulfur dioxide. Preliminary results from an EPA study on
the impact of a new standard indicate that a number of plants could be required
to install sulfur dioxide controls. These controls would be in addition to the
controls already required to meet the acid rain provision of the Clean Air Act.
The EPA issued proposed rules in November 1994 and is required to take final
action on this issue in 1996. The impact of any new standard will depend on the
level chosen for the standard and cannot be determined at this time.
In addition, the EPA is evaluating the need to revise the ambient air
quality standards for particulate matter, nitrogen oxides, and ozone. The impact
of any new standard will depend on the level chosen for the standard and cannot
be determined at this time.
In 1995, 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 subsidiaries 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 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, $41 million, and $3 million in 1994, 1993, and
1992, 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 Brunswick, Georgia.
Several major pieces of environmental legislation are being considered for
reauthorization or amendment by Congress. These include: 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.
II-14
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
The Southern Company and Subsidiary Companies 1994 Annual Report
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
In early 1995, The Southern Company sold -- through a public offering -- common
stock with proceeds totaling $103 million. The company may require additional
equity capital during the remainder of 1995. The amount and timing of additional
equity capital to be raised in 1995 -- 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 1995
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 subsidiaries 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.
Completing the sale of Unit 4 of Plant Scherer in 1995 will provide some
$130 million of cash.
To meet short-term cash needs and contingencies, the system companies had
approximately $139 million of cash and cash equivalents and $1.4 billion of
unused credit arrangements with banks at the beginning of 1995.
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 1997.
II-15
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 1994, 1993, and 1992
The Southern Company and Subsidiary Companies 1994 Annual Report
==========================================================================================================================
1994 1993 1992
--------------------------------------------------------------------------------------------------------------------------
(in millions)
Operating Revenues $8,297 $8,489 $8,073
--------------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
Fuel 2,058 2,265 2,114
Purchased power 277 336 454
Other 1,505 1,445 1,310
Maintenance 660 653 613
Depreciation and amortization 821 793 768
Amortization of deferred Plant Vogtle expenses, net (Note 1) 75 36 (31)
Taxes other than income taxes 475 462 436
Federal and state income taxes 711 734 647
--------------------------------------------------------------------------------------------------------------------------
Total operating expenses 6,582 6,724 6,311
--------------------------------------------------------------------------------------------------------------------------
Operating Income 1,715 1,765 1,762
Other Income (Expense):
Allowance for equity funds used during construction 11 9 10
Interest income 32 30 32
Other, net (48) (41) (50)
Income taxes applicable to other income 26 57 39
--------------------------------------------------------------------------------------------------------------------------
Income Before Interest Charges 1,736 1,820 1,793
--------------------------------------------------------------------------------------------------------------------------
Interest Charges and Preferred Dividends:
Interest on long-term debt 568 595 684
Allowance for debt funds used during construction (18) (13) (12)
Interest on notes payable 33 30 16
Amortization of debt discount, premium, and expense, net 30 26 14
Other interest charges 47 87 34
Preferred dividends of subsidiary companies 87 93 104
--------------------------------------------------------------------------------------------------------------------------
Net interest charges and preferred dividends 747 818 840
--------------------------------------------------------------------------------------------------------------------------
Consolidated Net Income $ 989 $1,002 $ 953
==========================================================================================================================
Common Stock Data: (Note 10)
Average number of shares of common stock outstanding (in millions) 650 637 632
Earnings per share of common stock $ 1.52 $1.57 $1.51
Cash dividends paid per share of common stock $ 1.18 $1.14 $1.10
--------------------------------------------------------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
For the Years Ended December 31, 1994, 1993, and 1992
==========================================================================================================================
1994 1993 1992
--------------------------------------------------------------------------------------------------------------------------
(in millions)
Balance at Beginning of Year $2,968 $2,721 $2,490
Consolidated net income 989 1,002 953
--------------------------------------------------------------------------------------------------------------------------
3,957 3,723 3,443
Cash dividends on common stock 766 726 695
Capital and preferred stock transactions, net - 29 27
--------------------------------------------------------------------------------------------------------------------------
Balance at End of Year (Note 10) $3,191 $2,968 $2,721
==========================================================================================================================
The accompanying notes are an integral part of these statements.
II-16
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1994, 1993, and 1992
The Southern Company and Subsidiary Companies 1994 Annual Report
=================================================================================================
1994 1993 1992
-------------------------------------------------------------------------------------------------
(in millions)
Operating Activities:
Consolidated net income $ 989 $1,002 $ 953
Adjustments to reconcile consolidated net income
to net cash provided by operating activities --
Depreciation and amortization 1,050 1,011 969
Deferred income taxes and investment tax credits (4) 189 215
Allowance for equity funds used during construction (11) (9) (10)
Deferred Plant Vogtle costs (Note 1) 75 36 (31)
Gain on asset sales (52) (36) --
Other, net 45 (9) (32)
Changes in certain current assets and liabilities --
Receivables, net 114 (55) (10)
Fossil fuel stock (110) 138 53
Materials and supplies (18) (2) (76)
Accounts payable 81 43 35
Other (48) (61) (71)
-------------------------------------------------------------------------------------------------
Net cash provided from operating activities 2,111 2,247 1,995
-------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (1,536) (1,441) (1,105)
Southern Electric's investments (405) (465) --
Sales of property 171 262 44
Other (87) (37) 61
-------------------------------------------------------------------------------------------------
Net cash used for investing activities (1,857) (1,681) (1,000)
-------------------------------------------------------------------------------------------------
Financing Activities:
Proceeds --
Common stock 279 205 30
Preferred securities 100 -- --
Preferred stock -- 426 410
First mortgage bonds 185 2,185 1,815
Other long-term debt 1,188 592 256
Retirements --
Preferred stock (1) (516) (326)
First mortgage bonds (241) (2,178) (2,575)
Other long-term debt (1,039) (450) (296)
Increase in notes payable, net 37 114 525
Payment of common stock dividends (766) (726) (695)
Miscellaneous (35) (137) (148)
-------------------------------------------------------------------------------------------------
Net cash used for financing activities (293) (485) (1,004)
-------------------------------------------------------------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents (39) 81 (9)
Cash and Cash Equivalents at Beginning of Year 178 97 106
-------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 139 $ 178 $ 97
=================================================================================================
Supplemental Cash Flow Information:
Cash paid during the year for --
Interest (net of amount capitalized) $618 $673 $743
Income taxes 716 530 458
-------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
II-17
CONSOLIDATED BALANCE SHEETS
At December 31, 1994 and 1993
The Southern Company and Subsidiary Companies 1994 Annual Report
=============================================================================================
Assets 1994 1993
---------------------------------------------------------------------------------------------
(in millions)
Utility Plant:
Plant in service (Note 1) $29,209 $27,687
Less accumulated provision for depreciation 9,577 8,934
---------------------------------------------------------------------------------------------
19,632 18,753
Nuclear fuel, at amortized cost 238 229
Construction work in progress (Note 4) 1,247 1,031
---------------------------------------------------------------------------------------------
Total 21,117 20,013
---------------------------------------------------------------------------------------------
Other Property and Investments:
Argentine operating concession, being amortized (Note 5) 446 469
Nuclear decommissioning trusts 125 88
Miscellaneous 224 179
---------------------------------------------------------------------------------------------
Total 795 736
---------------------------------------------------------------------------------------------
Current Assets:
Cash and cash equivalents 139 178
Special deposits 36 -
Receivables, less accumulated provisions for uncollectible accounts
of $9 million in 1994 and in 1993 1,022 1,147
Fossil fuel stock, at average cost 354 254
Materials and supplies, at average cost 553 535
Prepayments 194 148
Vacation pay deferred (Note 1) 70 73
---------------------------------------------------------------------------------------------
Total 2,368 2,335
---------------------------------------------------------------------------------------------
Deferred Charges:
Deferred charges related to income taxes (Note 9) 1,454 1,546
Deferred Plant Vogtle costs (Note 1) 432 507
Debt expense, being amortized 48 33
Premium on reacquired debt, being amortized 298 288
Miscellaneous 530 453
---------------------------------------------------------------------------------------------
Total 2,762 2,827
---------------------------------------------------------------------------------------------
Total Assets $27,042 $25,911
=============================================================================================
The accompanying notes are an integral part of these balance sheets.
II-18
CONSOLIDATED BALANCE SHEETS (continued)
At December 31, 1994 and 1993
The Southern Company and Subsidiary Companies 1994 Annual Report
=============================================================================================
Capitalization and Liabilities 1994 1993
---------------------------------------------------------------------------------------------
(in millions)
Capitalization (See accompanying statements):
Common stock equity $ 8,186 $ 7,684
Preferred stock 1,332 1,333
Preferred securities 100 -
Long-term debt 7,593 7,412
---------------------------------------------------------------------------------------------
Total 17,211 16,429
---------------------------------------------------------------------------------------------
Current Liabilities:
Amount of securities due within one year 229 157
Notes payable 978 941
Accounts payable 806 698
Customer deposits 102 103
Taxes accrued-
Federal and state income - 34
Other 153 172
Interest accrued 190 186
Vacation pay accrued 87 90
Miscellaneous 233 190
---------------------------------------------------------------------------------------------
Total 2,778 2,571
---------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes (Note 9) 4,007 3,979
Deferred credits related to income taxes (Note 9) 987 1,051
Accumulated deferred investment tax credits 858 900
Prepaid capacity revenues 138 144
Department of Energy assessments 92 98
Disallowed Plant Vogtle capacity buyback costs 60 63
Storm damage reserves 53 22
Miscellaneous 858 654
---------------------------------------------------------------------------------------------
Total 7,053 6,911
---------------------------------------------------------------------------------------------
Commitments and Contingent Matters (Notes 1, 2, 3, 4, 5, 6, 7, 8, and 13)
Total Capitalization and Liabilities $27,042 $25,911
=============================================================================================
The accompanying notes are an integral part of these balance sheets.
II-19
CONSOLIDATED STATEMENTS OF CAPITALIZATION
At December 31, 1994 and 1993
The Southern Company and Subsidiary Companies 1994 Annual Report
================================================================================================
1994 1993 1994 1993
------------------------------------------------------------------------------------------------
(in millions) (percent of total)
Common Stock Equity:
Common stock, par value $5 per share --
Authorized -- 1 billion shares
Outstanding -- 1994: 657 million shares,
1993: 643 million shares (Note 10) $ 3,283 $ 3,213
Paid-in capital 1,712 1,503
Retained earnings (Note 10) 3,191 2,968
-------------------------------------------------------------------------------------------------
Total common stock equity 8,186 7,684 47.6 % 46.8 %
-------------------------------------------------------------------------------------------------
Cumulative Preferred Stock of Subsidiaries:
$100 par or stated value --
4.20% to 5.96% 199 199
6.32% to 7.88% 205 205
11.36% -- 1
$25 par or stated value --
$1.90 to $2.125 295 295
6.40% to 7.60% 323 323
Auction rates -- at January 1, 1995:
4.59% to 4.64% 70 70
Adjustable rates -- January 1, 1995:
6.07% to 6.86% 240 240
-------------------------------------------------------------------------------------------------
Total (annual dividend requirement -- $90 million) 1,332 1,333 7.7 8.1
-------------------------------------------------------------------------------------------------
Cumulative Preferred Securities of Subsidiaries:
$25 stated value -- 9% 100 --
-------------------------------------------------------------------------------------------------
Total (annual distribution requirement -- $9 million) 100 -- 0.6 --
-------------------------------------------------------------------------------------------------
II-20
CONSOLIDATED STATEMENTS OF CAPITALIZATION (continued)
At December 31, 1994 and 1993
The Southern Company and Subsidiary Companies 1994 Annual Report
=========================================================================================================
1994 1993 1994 1993
---------------------------------------------------------------------------------------------------------
(in millions) (percent of total)
Long-Term Debt of Subsidiaries:
First mortgage bonds --
Maturity Interest Rates
-------- --------------
1994 4 5/8% -- 26
1995 4 3/4 % -- 11
1995 5 1/8 % 130 130
1996 4 1/2 % to 6% 210 235
1997 5 7/8 % 25 25
1998 5% to 9.2% 230 249
1999 6 1/8% to 6 3/8% 365 365
2000 through 2004 6% to 7% 1,250 1,215
2005 through 2009 6 7/8% to 9% 228 230
2015 through 2019 9.23% to 10 5/8% 65 215
2020 through 2024 7.3% to 9 3/8% 1,921 1,779
2032 Variable rates 200 200
---------------------------------------------------------------------------------------------------------
Total first mortgage bonds 4,624 4,680
Other long-term debt (Note 11) 3,261 2,962
Unamortized debt premium (discount), net (63) (74)
---------------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
requirement -- $570 million) 7,822 7,568
Less amount due within one year (Note 12) 229 156
--------------------------------------------------------------------------------------------------------
Long-term debt excluding amount due within one year 7,593 7,412 44.1 45.1
---------------------------------------------------------------------------------------------------------
Total Capitalization $17,211 $16,429 100.0 % 100.0%
=========================================================================================================
CONSOLIDATED STATEMENTS OF PAID-IN CAPITAL
For the Years Ended December 31, 1994, 1993, and 1992
=========================================================================================================
1994 1993 1992
---------------------------------------------------------------------------------------------------------
(in millions)
Balance at Beginning of Year $1,503 $2,931 $2,908
Proceeds from sales of common stock over the par value -- 13.9 million,
9.7 million, and 1.6 million shares in 1994, 1993, and 1992, respectively 209 179 23
Two-for-one stock split (Note 10) -- (1,607) --
-----------------------------------------------------------------------------------------------------------
Balance at End of Year $1,712 $1,503 $2,931
===========================================================================================================
The accompanying notes are an integral part of these statements.
II-21
NOTES TO FINANCIAL STATEMENTS
The Southern Company and Subsidiary Companies 1994 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), and The Southern Development and Investment Group
(SDIG). 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, beginning in mid-1995, will provide digital wireless
communications services -- over the 800-megahertz frequency band -- to The
Southern Company's subsidiaries and also will market these services to the
public within the Southeast. Southern Electric designs, builds, owns, and
operates power production facilities and provides a broad range of technical
services to industrial companies and utilities in the United States and a number
of international markets. Southern Nuclear provides services to The Southern
Company's nuclear power plants. SDIG 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.
All material intercompany items have been eliminated in consolidation.
Consolidated retained earnings at December 31, 1994, include $2.8 billion of
undistributed retained earnings of subsidiaries.
Certain prior years' data presented in the consolidated financial statements
have been reclassified to conform with current year presentation.
Regulatory Assets and Liabilities
The Southern 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 Consolidated Balance Sheets at December 31 relate
to:
1994 1993
----------------
(in millions)
Deferred income taxes $1,454 $1,546
Deferred Plant Vogtle costs 432 507
Premium on reacquired debt 298 288
Demand-side programs 97 49
Department of Energy assessments 79 87
Vacation pay 70 73
Deferred fuel charges 51 83
Postretirement benefits 41 22
Work force reduction costs 15 5
Deferred income tax credits (987) (1,051)
Storm damage reserve (53) (22)
Other, net 108 91
-------------------------------------------------------------
Total $1,605 $1,678
=============================================================
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 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 1994, uncollectible
accounts continued to average less than 1 percent of revenues.
II-22
NOTES (continued)
The Southern Company and Subsidiary Companies 1994 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 $152
million in 1994, $137 million in 1993, and $132 million in 1992. Alabama Power
and Georgia Power have contracts with the U.S. Department of Energy (DOE) that
provide for the permanent disposal of spent nuclear fuel, which was scheduled to
begin in 1998. However, the actual year this service will begin is uncertain.
Sufficient storage capacity currently is available to permit operation into 2003
at Plant Hatch, into 2009 at Plant Vogtle, and into 2012 and 2014 at Plant
Farley units 1 and 2, respectively.
Also, the Energy Policy Act of 1992 required the establishment in 1993 of a
Uranium Enrichment Decontamination and Decommissioning Fund, which is to be
funded in part by a special assessment on utilities with nuclear plants. This
assessment will be paid over a 15-year period, which began in 1993. This fund
will be used by the DOE for the decontamination and decommissioning of its
nuclear fuel enrichment facilities. The law provides that utilities will recover
these payments in the same manner as any other fuel expense. Alabama Power and
Georgia Power -- based on its ownership interests -- estimate their remaining
liability at December 31, 1994, under this law to be approximately $43 million
and $33 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
3.2 percent in 1994 and 3.3 percent in both 1993 and 1992. 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.
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 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, 1994, 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 $409 $241 $193
Non-radiated structures 75 34 43
Other 94 60 49
--------------------------------------------------------------
Total $578 $335 $285
==============================================================
(in millions)
Ultimate costs:
Radiated structures $1,258 $641 $ 843
Non-radiated structures 231 91 190
Other 289 160 215
--------------------------------------------------------------
Total $1,778 $892 $1,248
==============================================================
II-23
NOTES (continued)
The Southern Company and Subsidiary Companies 1994 Annual Report
Plant Plant Plant
Farley Hatch Vogtle
---------------------------
(in millions)
Amount expensed in 1994 $18 $6 $6
Accumulated provisions:
Balance in external trust
funds $ 71 $33 $22
Balance in internal reserves 51 29 10
----------------------------------------------------------------
Total $122 $62 $32
================================================================
Assumed in ultimate costs:
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. The decommissioning costs approved for ratemaking are $578 million
for Plant Farley, $184 million for Plant Hatch, and $155 million for Plant
Vogtle. These amounts for Georgia Power are the costs to decommission the
radioactive portions of the plants based on 1990 site studies. Georgia Power's
estimated ultimate costs, based on the 1990 studies, were $872 million and $1.4
billion for plants Hatch and Vogtle, respectively. Georgia Power 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 regulatory requirements, changes in technology, and
changes in costs of labor, materials, and equipment.
Income Taxes
The companies provide deferred income taxes for all significant income tax
temporary differences. Investment tax credits utilized are deferred and
amortized to income over the average lives of the related property.
Effective January 1, 1993, The Southern Company adopted FASB Statement No.
109, Accounting for Income Taxes. Statement No. 109 required, among other
things, conversion to the liability method of accounting for accumulated
deferred income taxes. See Note 9 for additional information about Statement No.
109.
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. Under these plans, Georgia Power deferred
financing costs and depreciation expense until the allowed investment was fully
reflected in rates as of October 1991. In 1991, the GPSC modified the Plant
Vogtle phase-in plan to begin earlier amortization of the costs deferred under
the plan. Also, the GPSC levelized capacity buyback expense from co-owners of
Plant Vogtle. See Note 3 for additional information regarding Georgia Power's
1991 rate order. Previously, pursuant to two separate interim accounting orders
by the GPSC, Georgia Power deferred substantially all operating expenses and
financing costs related to Plant Vogtle. 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:
1994 1993 1992
-------------------------------
(in millions)
Deferred capacity buybacks $ 10 $ 38 $100
Amortization of
deferred costs (85) (74) (69)
Income taxes - - (23)
-------------------------------------------------------------------
Net (amortization) deferred (75) (36) 8
Effect of adoption of FASB
Statement No. 109 - 160 -
Deferred costs
at beginning of year 507 383 375
------------------------------------------------------------------
Deferred costs
at end of year $432 $507 $383
==================================================================
Each GPSC order called for recovery of deferred costs within 10 years. Also,
the orders authorized Georgia Power to impute a return similar to allowance for
funds used during construction (AFUDC) on its investment in Plant Vogtle units 1
and 2 after the units began commercial operation.
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
II-24
NOTES (continued)
The Southern Company and Subsidiary Companies 1994 Annual Report
depreciation expense. The composite rates used by the operating companies to
calculate AFUDC during the years 1992 through 1994 ranged from a
before-income-tax rate of 5.0 percent to 11.3 percent. AFUDC, net of income tax,
as a percent of consolidated net income was 2.3 percent in 1994, 1.7 percent in
1993, and 1.8 percent in 1992.
Utility Plant
Utility plant is stated at original cost less regulatory disallowances. Original
cost includes: materials; labor; minor items of property; appropriate
administrative and general costs; payroll-related costs such as taxes, pensions,
and other benefits; and the estimated cost of funds used during construction.
The cost of maintenance, repairs, and replacement of minor items of property is
charged to maintenance expense. The cost of replacements of property (exclusive
of minor items of property) is charged to utility plant.
Cash and Cash Equivalents
For purposes of the Consolidated Statements of Cash Flows, temporary cash
investments are considered cash equivalents. Temporary cash investments are
securities with original maturities of 90 days or less.
Financial Instruments
In accordance with FASB Statement No. 107, Disclosure About Fair Value of
Financial Instruments, The Southern Company's only financial instrument that the
carrying amount did not approximate fair value at December 31 was as follows:
Long-Term Debt
-----------------------
Carrying Fair
Year Amount Value
---- -------- -----
(in millions)
1994 $7,674 $7,373
1993 7,321 7,729
----------------------------------------------------------------
The fair value of 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.
Vacation Pay
The operating companies' employees earn their vacation in one year and take it
in the subsequent year. However, for ratemaking purposes, vacation pay is
recognized as an allowable expense only when paid. Consistent with this
ratemaking treatment, the companies accrue a current liability for earned
vacation pay and record a current regulatory asset representing the future
recoverability of this cost. The amount was $70 million and $73 million at
December 31, 1994 and 1993, respectively. In 1995, an estimated 69 percent of
the 1994 deferred vacation cost will be expensed, and the balance will be
charged to construction and other accounts.
2. RETIREMENT BENEFITS
Pension Plan
The system companies have defined benefit, trusteed, non-contributory pension
plans that cover substantially all regular employees. Benefits are based on the
greater of amounts resulting from two different formulas: years of service and
final average pay or years of service and a flat-dollar benefit. Primarily, the
companies use the "entry age normal method with a frozen initial liability"
actuarial method for funding purposes, subject to limitations under federal
income tax regulations. Amounts funded to the pension 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 system companies also provide certain medical care and life insurance
benefits for retired employees. Substantially all employees may become eligible
for these benefits when they retire. Qualified 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.
Effective January 1, 1993, the system companies adopted FASB Statement No.
106, Employers' Accounting for Postretirement Benefits Other Than Pensions, on a
prospective basis. Statement No. 106 requires that medical care and life
insurance benefits for retired employees be accounted for on an accrual basis
II-25
NOTES (continued)
The Southern Company and Subsidiary Companies 1994 Annual Report
using a specified actuarial method, "benefit/years-of-service." In October 1993,
the GPSC ordered Georgia Power to phase in the adoption of Statement No. 106 to
cost of service over a five-year period, whereby one-fifth of the additional
costs would be expensed in 1993 and the remaining costs would be deferred. An
additional one-fifth of the costs would be expensed each succeeding year until
the costs are fully reflected in cost of service in 1997. The costs deferred
during the five-year period will be amortized to expense over a 15-year period
beginning in 1998. For the other operating companies, the cost of postretirement
benefits is reflected in rates on a current basis.
Prior to 1993, the system companies, except for Georgia Power and Savannah
Electric, recognized these benefit costs on an accrual basis using the
"aggregate cost" actuarial method, which spreads the expected cost of such
benefits over the remaining periods of employees' service as a level percentage
of payroll costs. Consistent with regulatory treatment in those years, Georgia
Power and Savannah Electric recognized these costs on a cash basis as payments
were made. The total costs of such benefits recognized by system companies in
1992 were $42 million.
Funded Status and Cost of Benefits
Shown in the following tables are actuarial results and assumptions for pension
and postretirement medical and life insurance benefits as computed under the
requirements of FASB Statement Nos. 87 and 106, respectively. The funded status
of the plans at December 31 was as follows:
Pension
--------------------
1994 1993
--------------------
(in millions)
Actuarial present value of
benefit obligation:
Vested benefits $1,593 $1,534
Non-vested benefits 68 76
----------------------------------------------------------------------
Accumulated benefit obligation 1,661 1,610
Additional amounts related to
projected salary increases 638 558
----------------------------------------------------------------------
Projected benefit obligation 2,299 2,168
Less:
Fair value of plan assets 3,171 3,337
Unrecognized net gain (789) (1,060)
Unrecognized prior service cost 64 72
Unrecognized transition asset (139) (152)
----------------------------------------------------------------------
Prepaid asset recognized in the
Consolidated Balance Sheets $ 8 $ 29
======================================================================
Postretirement Medical
-----------------------
1994 1993
-----------------------
(in millions)
Actuarial present value of
benefit obligation:
Retirees and dependents $293 $243
Employees eligible to retire 40 48
Other employees 367 389
-------------------------------------------------------------------
Accumulated benefit obligation 700 680
Less:
Fair value of plan assets 128 95
Unrecognized net loss (gain) 22 76
Unrecognized transition
obligation 394 419
-------------------------------------------------------------------
Accrued liability recognized in the
Consolidated Balance Sheets $156 $ 90
===================================================================
Postretirement Life
--------------------
1994 1993
--------------------
(in millions)
Actuarial present value of benefit obligation:
Retirees and dependents $ 82 $ 75
Employees eligible to retire - -
Other employees 92 96
-------------------------------------------------------------------
Accumulated benefit obligation 174 171
Less:
Fair value of plan assets 12 2
Unrecognized net loss (gain) (19) (13)
Unrecognized transition
obligation 106 113
-------------------------------------------------------------------
Accrued liability recognized in the
Consolidated Balance Sheets $ 75 $ 69
===================================================================
The weighted average rates assumed in the actuarial calculations were:
1994 1993 1992
--------------------------------------
Discount 8.0% 7.5% 8.0%
Annual salary increase 5.5 5.0 6.0
Long-term return on
plan assets 8.5 8.5 8.5
--------------------------------------------------------------------
An additional assumption used in measuring the accumulated postretirement
medical benefit obligation was a weighted average medical care cost trend rate
of 10.5 percent for 1994 decreasing gradually to 6.0 percent through the year
2000 and remaining at that level thereafter. An annual increase in the assumed
II-26
NOTES (continued)
The Southern Company and Subsidiary Companies 1994 Annual Report
medical care cost trend rate of 1 percent would increase the accumulated medical
benefit obligation at December 31, 1994, by $130 million and the aggregate of
the service and interest cost components of the net retiree medical cost by $18
million.
Components of the plans' net costs are shown below:
Pension
-----------------------
1994 1993 1992
------------------------
(in millions)
Benefits earned during the year $ 77 $ 76 $ 75
Interest cost on projected
benefit obligation 160 156 146
Actual (return) loss on plan assets 75 (432) (135)
Net amortization and deferral (351) 186 (85)
----------------------------------------------------------------
Net pension cost (income) $ (39) $ (14) $ 1
================================================================
Of the above net pension amounts, pension income of $29 million in 1994 and
$9 million in 1993, and pension expense of $2 million in 1992, were recorded in
operating expenses, and the remainder was recorded in construction and other
accounts.
Postretirement Medical
----------------------
1994 1993
----------------------
(in millions)
Benefits earned during the year $ 26 $ 21
Interest cost on accumulated
benefit obligation 51 43
Amortization of transition obligation 21 22
Actual (return) loss on plan assets 2 (12)
Net amortization and deferral (10) 5
-----------------------------------------------------------------
Net postretirement cost $ 90 $ 79
=================================================================
Postretirement Life
---------------------
1994 1993
--------------------
(in millions)
Benefits earned during the year $ 5 $ 6
Interest cost on accumulated
benefit obligation 13 13
Amortization of transition obligation 6 6
Actual (return) loss on plan assets - -
Net amortization and deferral - -
-----------------------------------------------------------------
Net postretirement cost $24 $25
=================================================================
Of the above net postretirement medical and life insurance costs recorded
in 1994 and 1993, $77 million and $64 million were charged to operating
expenses, $18 million and $21 million were deferred, and the remainder was
charged to construction and other accounts, respectively.
Work Force Reduction Programs
The system companies have incurred additional costs for work force reduction
programs. The costs related to these programs were $112 million, $35 million,
and $37 million for the years 1994, 1993, and 1992, respectively. A portion of
the cost of these programs was deferred and is being amortized in accordance
with regulatory treatment. The unamortized balance of these costs was $15
million at December 31, 1994.
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
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. This action is still pending.
Alabama Power Heat Pump Financing Suit
In September 1990, two customers of Alabama Power filed a civil complaint in the
Circuit Court of Shelby County, Alabama, against Alabama Power seeking to
represent all persons who, prior to June 23, 1989, entered into agreements with
Alabama Power for the financing of heat pumps and other merchandise purchased
from vendors other than Alabama Power. The plaintiffs contended that Alabama
Power was required to obtain a license under the Alabama Consumer Finance Act to
II-27
NOTES (continued)
The Southern Company and Subsidiary Companies 1994 Annual Report
engage in the business of making consumer loans. The plaintiffs were seeking an
order declaring these agreements null and void and requiring Alabama Power to
refund all payments -- principal and interest -- made under these agreements.
The aggregate amount under these agreements, together with interest paid,
currently is estimated to be $40 million.
In June 1993, the court ordered Alabama Power to refund or forfeit interest
of approximately $10 million because of Alabama Power's failure to obtain such
license. However, the court's order did not require any refund or forfeiture
with respect to any principal payments under the agreements at issue. Alabama
Power has appealed the court's order to the Supreme Court of Alabama.
The final outcome of this matter cannot now be determined; however, in
management's opinion, the final outcome will not have a material adverse effect
on the company's financial statements.
Georgia Power Potentially Responsible Party Status
In January 1995, Georgia Power 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. 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.
The final outcome of this matter cannot now be determined; however, in
management's opinion -- based on the nature and extent of Georgia Power's
activities relating to the site -- the final outcome will not have a material
adverse effect on the company's financial statements.
Georgia Power Tax Litigation
In June 1994, a tax deficiency notice was received from the Internal Revenue
Service (IRS) for the years 1984 through 1987 with regard to the tax accounting
by Georgia Power 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 $28 million
and $32 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
Power has filed a petition with the U. S. Tax Court challenging the IRS
position. In order to minimize additional interest charges should the IRS's
position prevail, Georgia Power made a payment to the IRS related to the
potential tax deficiency in September 1994.
The final outcome of this matter cannot now be determined; however, in
management's opinion, the final outcome will not have a material adverse effect
on the company's financial statements.
Alabama Power Rate Adjustment Procedures
In November 1982, the Alabama Public Service Commission (APSC) adopted rates
that provide for periodic adjustments based upon Alabama Power's earned return
on end-of-period retail common equity. The rates also provide for adjustments to
recognize the placing of new generating facilities in retail service. Both
increases and decreases have been placed into effect since the adoption of these
rates. The last rate adjustment was effective in January 1992. 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 1994, the APSC issued an order -- at Alabama Power's request -- allowing
Alabama Power to establish a natural disaster reserve not to exceed $32 million
and to change the procedure for estimating the accrual of revenues for service
rendered but unbilled at the end of each month. This change increased unbilled
revenues for September 1994 by $28 million, which offset the initial accrual for
the natural disaster reserve for the same amount. Additional monthly accruals of
$250 thousand will be made until the reserve maximum is attained. In addition, a
moratorium on rate increases through the third quarter of 1995 was approved.
The ratemaking procedures will remain in effect until the APSC votes to
modify or discontinue them.
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
II-28
NOTES (continued)
The Southern Company and Subsidiary Companies 1994 Annual Report
such rate riders except through general rate case proceedings and that those
procedures had not been followed. Georgia Power suspended collection of the
demand-side conservation costs and appealed the court's decision to the Georgia
Court of Appeals. In December 1993, the GPSC approved Georgia Power's request
for an accounting order allowing Georgia Power to defer all current unrecovered
and future costs related to these programs until the superior court's decision
is reversed or until the next general rate case proceedings. An association of
industrial customers filed a petition for review of the accounting order in
superior court.
In July 1994, the Georgia Court of Appeals upheld the legality of the rate
riders. In November 1994, the Supreme Court of Georgia denied petitions for
review of this ruling. As a result, Georgia Power resumed collection under the
rate riders in December 1994. In early 1995, the GPSC initiated a true-up
proceeding to review Georgia Power's demand-side conservation program costs both
incurred and expected to be incurred during 1995 in order to adjust rate riders
accordingly. The proceeding will also address a plan for recovery of costs
deferred under the accounting order. Georgia Power's costs related to these
conservation programs through 1994 were $115 million, of which $18 million has
been collected and the remainder deferred.
The final outcome of this matter cannot now be determined; however, in
management's opinion, the final outcome will not have a material adverse effect
on the company's financial statements.
Georgia Power 1991 Rate Order; Phase-In Plan Modifications
Georgia Power received a rate order in 1991 from the GPSC that modified the
Plant Vogtle phase-in plans to begin earlier amortization of the costs deferred
under the plans. The amortization period began October 1991 -- rather than
October 1994 as originally scheduled -- and extends through September 1999. In
addition, the GPSC ordered the levelization of capacity buyback expense from the
co-owners of Plant Vogtle over a six-year period beginning October 1991. This
results in net cost deferrals during the first three years and subsequent
amortization of the deferred amounts in the last three years.
Mississippi Power Retail Rate Adjustment Plan
Mississippi Power's retail base rates have been set under a Performance
Evaluation Plan (PEP) since 1986 with various modifications. In January 1994,
the Mississippi Public Service Commission (MPSC) approved PEP-2. Under PEP-2,
Mississippi Power's rate of return is measured on retail net investment. Also,
three indicators are used to evaluate Mississippi Power's performance with
emphasis on price and service to the customer. In addition, PEP-2 provides for
the sharing of rate adjustments based on low rates and on the performance
rating. The evaluation periods for PEP-2 are semiannual. Any change in rates is
limited to 2 percent of retail revenues per period. PEP-2 will remain in effect
until the MPSC modifies or terminates the plan.
FERC Reviews Equity Returns
In May 1991, the FERC ordered that hearings be conducted concerning the
reasonableness of the Southern electric system's wholesale rate schedules and
contracts that have a return on common equity of 13.75 percent or greater. The
contracts that could be affected by the hearings include substantially all of
the transmission, unit power, long-term power, and other similar contracts. Any
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 began in October 1994 and is scheduled to continue
until January 1996.
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 $77
million at December 31, 1994. Although the final outcome of this matter cannot
now be determined, in management's opinion, the final outcome will not result in
II-29
NOTES (continued)
The Southern Company and Subsidiary Companies 1994 Annual Report
changes that would have a material adverse effect on the company's financial
statements.
4. CONSTRUCTION PROGRAM
General
The operating companies are engaged in continuous construction programs,
currently estimated to total some $1.4 billion in 1995, $1.3 billion in 1996,
and $1.3 billion in 1997. These estimates include AFUDC of $40 million in 1995,
$30 million in 1996, and $33 million in 1997. 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, 1994, significant purchase commitments were
outstanding in connection with the construction program. The operating companies
do not have any new baseload generating plants under construction. However,
within the service area, the construction of combustion turbine peaking units of
approximately 1,100 megawatts is planned to be completed by 1997. In addition,
significant construction will continue related to transmission and distribution
facilities and the upgrading and extension of the useful lives of generating
plants.
See Management's Discussion and Analysis under "Environmental Matters" for
information on the impact of the Clean Air Act Amendments of 1990 and other
environmental matters.
Rocky Mountain Project Status
In its 1985 financing order, the GPSC concluded that completion of the Rocky
Mountain pumped storage hydroelectric project in 1991 as then planned was not
economically justifiable and reasonable and withheld authorization for Georgia
Power to spend funds from approved securities issuances on that project. In
1988, Georgia Power and Oglethorpe Power Corporation (OPC) entered into a joint
ownership agreement for OPC to assume responsibility for the construction and
operation of the project, as discussed in Note 6. However, full recovery of
Georgia Power's costs depends on the GPSC's treatment of the project's costs and
the disposition of the project's capacity output. In the event the GPSC does not
allow full recovery of the project costs, then the portion not allowed may have
to be written off. AFUDC accrued on the Rocky Mountain project has not been
credited to income or included in the project cost since December 1985. If
accrual of AFUDC is not resumed, Georgia Power's portion of the estimated total
plant additions at completion would be approximately $200 million. The plant is
scheduled to be in commercial operation in 1995.
The ultimate outcome of this matter cannot now be determined.
5. FINANCING, INVESTMENT, AND COMMITMENTS
General
In early 1995, The Southern Company sold -- through a public offering -- 5
million shares of common stock with proceeds totaling $103 million. The company
may require additional equity capital during the remainder of 1995. The amount
and timing of additional equity capital to be raised in 1995 -- 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 will be utilized if necessary;
the amounts available are discussed below. The subsidiary companies may issue
additional long-term debt and preferred stock primarily for the purposes of debt
maturities and for redeeming higher-cost securities if market conditions permit.
Southern Electric Investments
Southern Electric's investments in generating facilities in domestic and various
foreign markets were approximately $436 million at December 31, 1994. The
consolidated financial statements reflect these investments in majority-owned or
controlled subsidiaries on a consolidated basis and other investments on an
equity basis.
II-30
NOTES (continued)
The Southern Company and Subsidiary Companies 1994 Annual Report
Bank Credit Arrangements
At the beginning of 1995, unused credit arrangements with banks totaled $1.4
billion, of which approximately $875 million expires at various times during
1995 and 1996; $41 million expires at May 1, 1997; $25 million expires at May
31, 1997; $400 million expires at June 30, 1997; and $40 million expires at
December 1, 1997.
Georgia Power's revolving credit agreements of $60 million, of which $41
million remained unused as of December 31, 1994, expire May 1, 1997. 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 has $25 million of revolving credit agreements expiring May 31,
1997. 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, 1997, is under revolving credit
arrangements with several banks providing The Southern Company, Alabama Power,
and Georgia Power up to the total credit amount of $400 million. To provide
liquidity support to commercial paper programs, $135 million and $165 million of
the $400 million available credit are currently dedicated to the exclusive use
of Alabama Power and Georgia Power, respectively. During the term of these
agreements, short-term borrowings may be converted into term loans, payable in
12 equal quarterly installments, with the first installment due at the end of
the first calendar quarter after the applicable termination date or at an
earlier date at the companies' option. In addition, these agreements require
payment of commitment fees based on the unused portions of the commitments or
the maintenance of compensating balances with the banks.
Mississippi Power has $40 million of revolving credit agreements expiring
December 1, 1997. 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
$11 million remained unused as of December 31, 1994, expire December 31, 1996.
These agreements allow short-term borrowings to be converted into term loans,
payable in 12 equal quarterly installments, with the first installment due at
the end of the first calendar quarter after the applicable termination date or
at an earlier date at 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.
A portion of the $1.4 billion unused credit arrangements with banks --
discussed earlier -- is dedicated to provide liquidity support to the companies'
variable rate pollution control bonds. The amount of credit lines dedicated at
December 31, 1994, was $293 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 Alabama Power and Georgia Power,
through commercial paper programs that have the liquidity support of committed
bank credit arrangements.
II-31
NOTES (continued)
The Southern Company and Subsidiary Companies 1994 Annual Report
Assets Subject to Lien
The operating companies' mortgages, which secure the first mortgage bonds issued
by the companies, constitute a direct first lien on substantially all of the
companies' respective fixed property and franchises.
Fuel Commitments
To supply a portion of the fuel requirements of the system's generating plants,
the subsidiary companies have entered into various long-term commitments for the
procurement of fossil and nuclear fuel. In most cases, these contracts contain
provisions for price escalations, minimum purchase levels, and other financial
commitments. Total estimated long-term obligations were approximately $16
billion at December 31, 1994. Additional commitments for coal and nuclear fuel
will be required in the future to supply the operating companies' fuel needs.
To take advantage of lower-cost coal supplies, agreements were reached in
1986 for the payment of $121 million to terminate two contracts for the supply
of coal to Plant Daniel, which is jointly owned by Gulf Power and Mississippi
Power. Also, in March 1988, Gulf Power made an advance payment of $60 million to
a coal supplier under an agreement to lower the cost of future coal purchased
under an existing contract. These amounts are being amortized to expense.
Operating Leases
The operating companies have entered into coal rail car rental agreements with
various terms and expiration dates. These expenses totaled $15 million, $11
million, and $9 million for 1994, 1993, and 1992, respectively. At December 31,
1994, estimated minimum rental commitments for noncancelable operating leases
were as follows:
Year Amounts
--- -----------
(in millions)
1995 $ 18
1996 17
1997 17
1998 17
1999 17
2000 and thereafter 242
-------------------------------------------------------
Total minimum payments $328
=======================================================
6. FACILITY SALES AND JOINT OWNERSHIP AGREEMENTS
In 1992, Alabama Power sold an undivided interest in units 1 and 2 of Plant
Miller and related facilities to Alabama Electric Cooperative, Inc.
Since 1975, Georgia Power has sold undivided interests in plants Vogtle,
Hatch, Scherer, and Wansley in varying amounts, together with transmission
facilities, to OPC, the Municipal Electric Authority of Georgia (MEAG), and the
city of Dalton, Georgia. Georgia Power has completed three of four separate
transactions to sell Unit 4 of Plant Scherer to two Florida utilities. See Note
7 for additional information concerning these sales. In addition, Georgia Power
has 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, both of which are discussed later.
At December 31, 1994, 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% $3,289 $628
Plant Hatch
(nuclear) 50.1 842 346
Plant Miller
(coal)
Units 1 and 2 91.8 708 264
Plant Scherer
(coal)
Units 1 and 2 8.4 112 36
Unit 4 16.6 119 18
Plant Wansley
(coal) 53.5 287 129
Rocky Mountain
(pumped storage) 25.0* 199 -
-------------------------------------------------------------
*Estimated ownership at date of completion.
Georgia Power and OPC have a joint ownership agreement regarding the
848-megawatt Rocky Mountain pumped storage hydroelectric project. Under the
agreement, Georgia Power will retain its present investment in the project and
OPC will finance, complete, and operate the facility. Upon completion, Georgia
II-32
NOTES (continued)
The Southern Company and Subsidiary Companies 1994 Annual Report
Power will own an undivided interest in the project equal to the proportion its
investment bears to the total investment in the project (excluding each party's
cost of funds and ad valorem taxes). Based on current cost estimates, Georgia
Power's final ownership is estimated at approximately 25 percent of the project
at completion. The plant is scheduled to be in commercial operation in 1995.
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 in early 1996, and will be constructed, operated,
and maintained by FPC. Georgia Power will have a 33 percent interest 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.
Also, Georgia Power entered into a separate four-year purchase power contract
with FPC. Beginning in 1996, Georgia Power will purchase 400 megawatts of
capacity. In 1998, this amount will decline to 200 megawatts for the remaining
two years.
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.
In connection with a joint ownership arrangement at Plant Vogtle, Georgia
Power has remaining commitments to purchase declining fractions of OPC's and
MEAG's capacity and energy from this plant for periods of up to 10 years
following commercial operation (and, with regard to a portion of the 5 percent
additional interest in Plant Vogtle owned by MEAG, until the latter of the
retirement of the plant or the latest stated maturity date of MEAG's bonds
issued to finance such ownership interest). The payments for such capacity are
required whether any capacity is available. The energy cost of these purchases
is a function of each unit's variable operating costs. Except as noted below,
the cost of such capacity and energy is included in purchased power in the
Consolidated Statements of Income. Capacity payments totaled $129 million, $183
million, and $289 million for 1994, 1993, and 1992, respectively. Projected
capacity payments for the next five years are as follows: $77 million in 1995;
$70 million in 1996; $59 million in 1997; $59 million in 1998; and $59 million
in 1999. Also, a portion of the above capacity payments relates to Plant Vogtle
costs that were written off after being disallowed for retail ratemaking
purposes.
In 1991, the GPSC ordered that the Plant Vogtle capacity buyback expense be
levelized over a six-year period. The amounts deferred and not expensed in the
year paid totaled $38 million in 1993 and $100 million in 1992. In 1994, the
amount deferred was exceeded by the amortization of amounts previously deferred
by almost $1 million. The projected net amortization of the deferred expense is
$49 million in 1995, $62 million in 1996, and $57 million in 1997.
7. SALES OF INTERESTS IN PLANT SCHERER
Georgia Power has completed three 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,
including any gains on these transactions. FP&L would eventually own
approximately 76.4 percent of the unit, with JEA owning the remainder. Georgia
Power will continue to operate the unit.
The completed and scheduled remaining transactions are as follows:
Closing Percent
Date Capacity Ownership Amount
------ -------- --------- -------
(megawatts) (in millions)
July 1991 290 35.46% $291
June 1993 258 31.44 253
June 1994 135 16.55 133
June 1995 135 16.55 131
-------------------------------------------------------------
Total 818 100.00% $808
=============================================================
Plant Scherer -- a jointly owned coal-fired generating plant -- has four
units with a total capacity of 3,272 megawatts. Unit 4 was completed in 1989.
See Note 6 for information regarding current plant ownership.
8. LONG-TERM POWER SALES AGREEMENTS
The operating subsidiaries of The Southern Company 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
II-33
NOTES (continued)
The Southern Company and Subsidiary Companies 1994 Annual Report
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 capacity revenues have been as follows:
Unit Other
Year Power Long-Term Total
---- ----------------------------------
(in millions)
1994 $257 $19 $276
1993 312 38 350
1992 435 22 457
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 1,700 megawatts of capacity is scheduled to be sold during 1995.
Thereafter, these sales will decline to some 1,600 megawatts and remain at that
approximate level -- unless reduced by FP&L, FPC, and JEA for the periods after
1999 -- until the expiration of the contracts in 2010.
9. 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, 1994, the tax- related regulatory assets and liabilities were
$1.5 billion and $1.0 billion, 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:
1994 1993 1992
-------------------------
(in millions)
Total provision for income taxes:
Federal --
Currently payable $603 $424 $343
Deferred -- current year 67 224 225
-- reversal of
prior years (75) (51) (41)
Deferred investment tax
credits - (20) (6)
-------------------------------------------------------------------
595 577 521
-------------------------------------------------------------------
State --
Currently payable 86 64 50
Deferred -- current year 15 39 46
-- reversal of
prior years (11) (3) (9)
-------------------------------------------------------------------
90 100 87
-------------------------------------------------------------------
Total 685 677 608
Less income taxes charged
(credited) to other income (26) (57) (39)
-------------------------------------------------------------------
Federal and state income
taxes charged to operations $711 $734 $647
===================================================================
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:
1994 1993
-----------------------
(in millions)
Deferred tax liabilities:
Accelerated depreciation $2,637 $2,496
Property basis differences 1,647 1,741
Deferred plant costs 141 161
Other 271 289
------------------------------------------------------------------
Total 4,696 4,687
------------------------------------------------------------------
Deferred tax assets:
Federal effect of state deferred taxes 104 102
Other property basis differences 278 292
Deferred costs 79 69
Pension and other benefits 63 46
Other 225 210
------------------------------------------------------------------
Total 749 719
------------------------------------------------------------------
Net deferred tax liabilities 3,947 3,968
Portion included in current assets, net 60 11
------------------------------------------------------------------
Accumulated deferred income taxes
in the Consolidated Balance Sheet $4,007 $3,979
==================================================================
II-34
NOTES (continued)
The Southern Company and Subsidiary Companies 1994 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 $42 million in 1994, $36 million in 1993, and $41 million in
1992. At December 31, 1994, 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:
1994 1993 1992
---------------------------
Federal statutory rate 35.0% 35.0% 34.0%
State income tax,
net of federal deduction 3.3 3.7 3.4
Non-deductible book
depreciation 1.8 1.9 2.2
Difference in prior years'
deferred and current tax rate (1.5) (1.3) (1.5)
Other 0.3 (1.1) (1.6)
---------------------------------------------------------------
Effective income tax rate 38.9% 38.2% 36.5%
===============================================================
The Southern Company and its subsidiaries file a consolidated federal income
tax return. Under a joint consolidated income tax agreement, each company's
current and deferred tax expense is computed on a stand-alone basis, and
consolidated tax savings are allocated to each company based on its ratio of
taxable income to total consolidated taxable income.
10. COMMON STOCK
Stock Distribution
In January 1994, The Southern Company board of directors authorized a
two-for-one common stock split in the form of a stock distribution for each
share held as of February 7, 1994. For all reported common stock data, the
number of common shares outstanding and per share amounts for earnings,
dividends, and market price reflect the stock distribution.
Shares Reserved
At December 31, 1994, a total of 15 million shares was reserved for issuance
pursuant to the Dividend Reinvestment and Stock Purchase Plan, the Employee
Savings Plan, 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. Currently, 36 employees are eligible to participate in the plan. As of
December 31, 1994, 42 current and former employees participated in the plan. The
maximum number of shares of common stock that may be issued under the Executive
Stock Option Plan may not exceed 6 million. The price of options granted to date
has been at the fair market value of the shares on the date of grant. Options
granted to date become exercisable pro rata over a maximum period of four years
from date of grant. 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 1993 and 1994 is summarized
below:
Shares Average
Subject Option Price
To Option Per Share
---------------------------
Balance at December 31, 1992 1,189,122 $15.02
Options granted 359,492 21.22
Options canceled -- --
Options exercised (183,804) 14.14
--------------------------------------------------------------------
Balance at December 31, 1993 1,364,810 16.77
Options granted 446,443 18.88
Options canceled - -
Options exercised (74,649) 14.81
--------------------------------------------------------------------
Balance at December 31, 1994 1,736,604 $17.39
====================================================================
Shares reserved for future grants:
At December 31, 1992 4,073,936
At December 31, 1993 3,714,444
At December 31, 1994 3,268,001
--------------------------------------------------------------------
Options exercisable:
At December 31, 1993 475,795
At December 31, 1994 793,989
--------------------------------------------------------------------
Common Stock Dividend Restrictions
The income of The Southern Company is derived primarily from equity in earnings
of its operating subsidiaries. At December 31, 1994, $1.8 billion of
consolidated retained earnings was restricted against the payment by the
operating companies of cash dividends on common stock under terms of bond
indentures or charters.
II-35
NOTES (continued)
The Southern Company and Subsidiary Companies 1994 Annual Report
11. OTHER LONG-TERM DEBT
Details of other long-term debt at December 31 are as follows:
1994 1993
-----------------
(in millions)
Obligations incurred in connection
with the sale by public authorities
of tax-exempt pollution control
revenue bonds:
Collateralized --
5.375% to 9.375% due
2004-2024 $1,179 $ 708
Variable rate (5% to 6.25%
at 1/1/95) due 2011-2024 412 63
Non-collateralized --
7.2 % to 12.25% due 2003-2014 1 650
6.75% to 10.6% due 2015-2017 828 890
5.8% due 2022 10 10
Variable rate (2.95% to 3.7% at
1/1/94) due 2011-2022 - 92
-----------------------------------------------------------------
2,430 2,413
-----------------------------------------------------------------
Capitalized lease obligations 148 247
-----------------------------------------------------------------
Notes payable:
4.15% to 9.75% due 1994-1998 153 144
8.375% to 10% due 1997-1999 196 -
Adjustable rates (14.04% at
1/1/95) due 1995 26 -
Adjustable rates (4% to 7.8% at
1/1/95) due 1994-1996 133 115
Adjustable rates (5.5% to 8.14%
at 1/1/95) due 1998-2019 175 43
-----------------------------------------------------------------
683 302
-----------------------------------------------------------------
Total $3,261 $2,962
=================================================================
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 $126 million and $217 million at
December 31, 1994 and 1993, respectively. At December 31, 1994, the composite
interest rates for buildings and other were 9.7 percent and 10.7 percent,
respectively. Sinking fund requirements and/or serial maturities through 1999
applicable to other long-term debt are as follows: $97 million in 1995; $166
million in 1996; $46 million in 1997; $29 million in 1998; and $23 million in
1999.
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:
1994 1993
-------------
(in millions)
Bond improvement fund requirements $ 48 $ 51
Less:
Portion to be satisfied by certifying
property additions 46 3
Reacquired bonds - 25
----------------------------------------------------------------
Cash sinking fund requirements 2 23
First mortgage bond maturities
and redemptions 130 44
Other long-term debt maturities
(Note 11) 97 89
----------------------------------------------------------------
Total $229 $156
================================================================
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.
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
II-36
NOTES (continued)
The Southern Company and Subsidiary Companies 1994 Annual Report
taxes, for Alabama Power and Georgia Power -- based on its ownership and buyback
interests -- is $159 million and $163 million, respectively, per incident but
not more than an aggregate of $20 million and $21 million, respectively, to be
paid for each incident in any one year.
Alabama Power and Georgia Power are members of Nuclear Mutual Limited (NML),
a mutual insurer established to provide property damage insurance in an amount
up to $500 million for members' nuclear generating facilities. The members are
subject to a retrospective premium assessment in the event that losses exceed
accumulated reserve funds. Alabama Power's and Georgia Power's maximum annual
assessments are limited to $12 million and $15 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 $27 million and $25
million, respectively. The maximum replacement power assessments are $10 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.
14. QUARTERLY FINANCIAL INFORMATION (Unaudited)
Summarized quarterly financial data for 1994 and 1993 are as follows:
Per Common Share*
------------------------------------------------
Operating Operating Consolidated Price Range
Quarter Ended Revenues Income Net Income Earnings Dividends High Low
------------- ----------------------------------------- ------------------------------------------------
(in millions)
March 1994 $1,932 $330 $142 $0.22 $0.295 22 18 1/2
June 1994 2,069 440 256 0.39 0.295 20 1/2 17 3/4
September 1994 2,381 607 416 0.64 0.295 20 17
December 1994 1,915 338 175 0.27 0.295 21 18 1/4
March 1993 $1,840 $377 $177 $0.28 $0.285 21 3/8 18 3/8
June 1993 2,068 426 250 0.39 0.285 22 1/2 19 3/8
September 1993 2,636 637 442 0.70 0.285 23 20 1/2
December 1993 1,945 325 133 0.20 0.285 23 5/8 20 3/4
--------------------------------------------------------------------------------------------------------------------------------
Earnings for 1994 declined by $61 million or 9 cents per share as a result
of work force reduction programs primarily recorded in the first quarter.
*Common stock data reflect a two-for-one stock split in the form of a stock
distribution for each share held as of February 7, 1994.
The company's business is influenced by seasonal weather conditions.
II-37
SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA
The Southern Company and Subsidiary Companies 1994 Annual Report
(See Note Below)
==========================================================================================================
1994 1993 1992
----------------------------------------------------------------------------------------------------------
Operating Revenues (in millions) $8,297 $8,489 $8,073
Consolidated Net Income (in millions) $989 $1,002 $953
Earnings Per Share of Common Stock $1.52 $1.57 $1.51
Cash Dividends Paid Per Share of Common Stock $1.18 $1.14 $1.10
Return on Average Common Equity (percent) 12.47 13.43 13.42
Total Assets (in millions) $27,042 $25,911 $20,038
Gross Property Additions (in millions) $1,536 $1,441 $1,105
----------------------------------------------------------------------------------------------------------
Capitalization (in millions):
Common stock equity $8,186 $7,684 $7,234
Preferred stock 1,332 1,333 1,351
Preferred and preference stock subject
to mandatory redemption -- -- 8
Preferred securities 100 -- --
Long-term debt 7,593 7,412 7,241
----------------------------------------------------------------------------------------------------------
Total excluding amounts due within one year $17,211 $16,429 $15,834
==========================================================================================================
Capitalization Ratios (percent):
Common stock equity 47.6 46.8 45.7
Preferred stock 8.3 8.1 8.6
Long-term debt 44.1 45.1 45.7
----------------------------------------------------------------------------------------------------------
Total excluding amounts due within one year 100.0 100.0 100.0
==========================================================================================================
Other Common Stock Data:
Book value per share (year-end) $12.47 $11.96 $11.43
Market price per share:
High 22 23 5/8 19 1/2
Low 17 18 3/8 15 1/8
Close 20 22 19 1/4
Market-to-book ratio (year-end) (percent) 160.4 183.9 168.4
Price-earnings ratio (year-end) (times) 13.2 14.0 12.7
Dividends paid (in millions) $766 $726 $695
Dividend yield (year-end) (percent) 5.9 5.2 5.7
Dividend payout ratio (percent) 77.5 72.4 72.9
Cash coverage of dividends (year-end) (times) 2.7 2.9 2.8
Proceeds from sales of stock (in millions) $279 $204 $30
Shares outstanding (in thousands):
Average 649,927 637,319 631,844
Year-end 656,528 642,662 632,917
Stockholders of record (year-end) 234,927 237,105 247,378
----------------------------------------------------------------------------------------------------------
First Mortgage Bonds (in millions):
Issued $185 $2,185 $1,815
Retired 241 2,178 2,575
Preferred Stock (in millions):
Issued $-- $426 $410
Retired 1 516 326
----------------------------------------------------------------------------------------------------------
Customers (year-end) (in thousands):
Residential 3,046 2,996 2,950
Commercial 439 427 414
Industrial 17 18 18
Other 5 4 4
----------------------------------------------------------------------------------------------------------
Total 3,507 3,445 3,386
==========================================================================================================
Employees (year-end) 27,826 28,743 29,085
----------------------------------------------------------------------------------------------------------
Note: Common stock data reflect a two-for-one stock split in the form of a
stock distribution for each share held as of February 7, 1994.
II-38
SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA
The Southern Company and Subsidiary Companies 1994 Annual Report
(See Note Below)
==========================================================================================================
1991 1990 1989
----------------------------------------------------------------------------------------------------------
Operating Revenues (in millions) $8,050 $8,053 $7,620
Consolidated Net Income (in millions) $876 $604 $846
Earnings Per Share of Common Stock $1.39 $0.96 $1.34
Cash Dividends Paid Per Share of Common Stock $1.07 $1.07 $1.07
Return on Average Common Equity (percent) 12.74 8.85 12.49
Total Assets (in millions) $19,863 $19,955 $20,092
Gross Property Additions (in millions) $1,123 $1,185 $1,346
----------------------------------------------------------------------------------------------------------
Capitalization (in millions):
Common stock equity $6,976 $6,783 $6,861
Preferred stock 1,207 1,207 1,209
Preferred and preference stock subject
to mandatory redemption 126 151 191
Preferred securities -- -- --
Long-term debt 7,992 8,458 8,575
----------------------------------------------------------------------------------------------------------
Total excluding amounts due within one year $16,301 $16,599 $16,836
==========================================================================================================
Capitalization Ratios (percent):
Common stock equity 42.8 40.9 40.8
Preferred stock 8.2 8.2 8.3
Long-term debt 49.0 50.9 50.9
----------------------------------------------------------------------------------------------------------
Total excluding amounts due within one year 100.0 100.0 100.0
==========================================================================================================
Other Common Stock Data:
Book value per share (year-end) $11.05 $10.74 $10.87
Market price per share:
High 17 3/8 14 5/8 14 7/8
Low 12 7/8 11 1/2 11
Close 17 1/8 13 7/8 14 1/2
Market-to-book ratio (year-end) (percent) 155.5 129.7 134.0
Price-earnings ratio (year-end) (times) 12.4 14.6 10.9
Dividends paid (in millions) $676 $676 $675
Dividend yield (year-end) (percent) 6.2 7.7 7.3
Dividend payout ratio (percent) 77.1 111.8 79.8
Cash coverage of dividends (year-end) (times) 2.5 2.8 2.6
Proceeds from sales of stock (in millions) $-- $-- $4
Shares outstanding (in thousands):
Average 631,307 631,307 631,303
Year-end 631,307 631,307 631,307
Stockholders of record (year-end) 254,568 263,046 273,751
----------------------------------------------------------------------------------------------------------
First Mortgage Bonds (in millions):
Issued $380 $300 $280
Retired 881 146 201
Preferred Stock (in millions):
Issued $100 $-- $--
Retired 125 96 21
----------------------------------------------------------------------------------------------------------
Customers (year-end) (in thousands):
Residential 2,903 2,865 2,824
Commercial 403 396 392
Industrial 18 18 18
Other 4 4 4
----------------------------------------------------------------------------------------------------------
Total 3,328 3,283 3,238
==========================================================================================================
Employees (year-end) 30,402 30,263 30,530
----------------------------------------------------------------------------------------------------------
Note: Common stock data reflect a two-for-one stock split in the form of a
stock distribution for each share held as of February 7, 1994.
II-39A
SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA
The Southern Company and Subsidiary Companies 1994 Annual Report
(See Note Below)
==========================================================================================================
1988 1987 1986
----------------------------------------------------------------------------------------------------------
Operating Revenues (in millions) $7,287 $7,204 $7,033
Consolidated Net Income (in millions) $846 $577 $903
Earnings Per Share of Common Stock $1.36 $0.96 $1.56
Cash Dividends Paid Per Share of Common Stock $1.07 $1.07 $1.0325
Return on Average Common Equity (percent) 13.03 9.27 15.61
Total Assets (in millions) $19,731 $19,518 $18,483
Gross Property Additions (in millions) $1,754 $1,853 $2,367
----------------------------------------------------------------------------------------------------------
Capitalization (in millions):
Common stock equity $6,686 $6,307 $6,133
Preferred stock 1,259 1,139 1,214
Preferred and preference stock subject
to mandatory redemption 206 224 178
Preferred securities -- -- --
Long-term debt 8,433 8,333 7,812
----------------------------------------------------------------------------------------------------------
Total excluding amounts due within one year $16,584 $16,003 $15,337
==========================================================================================================
Capitalization Ratios (percent):
Common stock equity 40.3 39.4 40.0
Preferred stock 8.8 8.5 9.1
Long-term debt 50.9 52.1 50.9
----------------------------------------------------------------------------------------------------------
Total excluding amounts due within one year 100.0 100.0 100.0
==========================================================================================================
Other Common Stock Data:
Book value per share (year-end) $10.60 $10.28 $10.35
Market price per share:
High 12 1/8 14 1/2 13 5/8
Low 10 1/8 8 7/8 10 1/8
Close 11 1/8 11 1/8 12 5/8
Market-to-book ratio (year-end) (percent) 105.5 108.8 122.5
Price-earnings ratio (year-end) (times) 8.2 11.7 8.2
Dividends paid (in millions) $661 $628 $583
Dividend yield (year-end) (percent) 9.6 9.6 8.4
Dividend payout ratio (percent) 78.1 108.9 64.6
Cash coverage of dividends (year-end) (times) 2.3 2.0 2.7
Proceeds from sales of stock (in millions) $194 $247 $379
Shares outstanding (in thousands):
Average 622,292 601,390 580,252
Year-end 630,898 613,565 592,364
Stockholders of record (year-end) 290,725 296,079 297,302
----------------------------------------------------------------------------------------------------------
First Mortgage Bonds (in millions):
Issued $335 $700 $735
Retired 273 369 875
Preferred Stock (in millions):
Issued $120 $125 $100
Retired 10 160 53
----------------------------------------------------------------------------------------------------------
Customers (year-end) (in thousands):
Residential 2,781 2,733 2,675
Commercial 384 374 362
Industrial 18 18 17
Other 4 4 4
Total 3,187 3,129 3,058
==========================================================================================================
Employees (year-end) 32,523 32,612 32,358
----------------------------------------------------------------------------------------------------------
Note: Common stock data reflect a two-for-one stock split in the form of a
stock distribution for each share held as of February 7, 1994.
II-39B
SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA
The Southern Company and Subsidiary Companies 1994 Annual Report
(See Note Below)
==============================================================================================
1985 1984
----------------------------------------------------------------------------------------------
Operating Revenues (in millions) $6,999 $6,350
Consolidated Net Income (in millions) $845 $735
Earnings Per Share of Common Stock $1.56 $1.47
Cash Dividends Paid Per Share of Common Stock $0.975 $0.915
Return on Average Common Equity (percent) 16.59 16.55
Total Assets (in millions) $16,855 $15,327
Gross Property Additions (in millions) $2,242 $2,130
----------------------------------------------------------------------------------------------
Capitalization (in millions):
Common stock equity $5,443 $4,741
Preferred stock 1,114 1,004
Preferred and preference stock subject
to mandatory redemption 194 206
Preferred securities -- --
Long-term debt 7,220 6,774
----------------------------------------------------------------------------------------------
Total excluding amounts due within one year $13,971 $12,725
Capitalization Ratios (percent):
Common stock equity 38.9 37.3
Preferred stock 9.4 9.5
Long-term debt 51.7 53.2
----------------------------------------------------------------------------------------------
Total excluding amounts due within one year 100.0 100.0
Other Common Stock Data:
Book value per share (year-end) $9.72 $9.08
Market price per share:
High 11 5/8 9 3/8
Low 8 7/8 7 1/8
Close 11 1/8 9 3/8
Market-to-book ratio (year-end) (percent) 114.5 103.9
Price-earnings ratio (year-end) (times) 7.1 6.4
Dividends paid (in millions) $512 $444
Dividend yield (year-end) (percent) 9.2 10.2
Dividend payout ratio (percent) 60.6 60.4
Cash coverage of dividends (year-end) (times) 2.6 3.1
Proceeds from sales of stock (in millions) $373 $318
Shares outstanding (in thousands):
Average 541,244 501,313
Year-end 560,063 522,018
Stockholders of record (year-end) 318,221 336,165
----------------------------------------------------------------------------------------------
First Mortgage Bonds (in millions):
Issued $20 $150
Retired 69 71
Preferred Stock (in millions):
Issued $150 $50
Retired 6 6
----------------------------------------------------------------------------------------------
Customers (year-end) (in thousands):
Residential 2,611 2,541
Commercial 348 336
Industrial 17 17
Other 4 4
----------------------------------------------------------------------------------------------
Total 2,980 2,898
==============================================================================================
Employees (year-end) 32,354 31,753
----------------------------------------------------------------------------------------------
Note: Common stock data reflect a two-for-one stock split in the form of a
stock distribution for each share held as of February 7, 1994.
II-39C
SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA (continued)
The Southern Company and Subsidiary Companies 1994 Annual Report
==========================================================================================================
1994 1993 1992
----------------------------------------------------------------------------------------------------------
Operating Revenues (in millions):
Residential $2,560 $2,696 $2,402
Commercial 2,357 2,313 2,181
Industrial 2,162 2,200 2,126
Other 70 68 64
----------------------------------------------------------------------------------------------------------
Total retail 7,149 7,277 6,773
Sales for resale within service area 360 447 409
Sales for resale outside service area 505 613 797
----------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 8,014 8,337 7,979
Other revenues 283 152 94
----------------------------------------------------------------------------------------------------------
Total $8,297 $8,489 $8,073
==========================================================================================================
Kilowatt-Hour Sales (in millions):
Residential 35,836 36,807 33,627
Commercial 34,080 32,847 31,025
Industrial 50,311 48,738 47,816
Other 844 814 777
----------------------------------------------------------------------------------------------------------
Total retail 121,071 119,206 113,245
Sales for resale within service area 8,151 13,258 12,107
Sales for resale outside service area 10,769 12,445 16,632
----------------------------------------------------------------------------------------------------------
Total 139,991 144,909 141,984
==========================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 7.14 7.32 7.14
Commercial 6.92 7.04 7.03
Industrial 4.30 4.51 4.45
Total retail 5.90 6.10 5.98
Sales for resale 4.57 4.12 4.20
Total sales 5.72 5.75 5.62
Average Annual Kilowatt-Hour Use Per Residential Customer 11,851 12,378 11,490
Average Annual Revenue Per Residential Customer $846.48 $906.60 $820.67
Plant Nameplate Capacity Ratings (year-end) (megawatts) 29,932 29,513 29,830
Maximum Peak-Hour Demand (megawatts):
Winter 22,254 19,432 19,121
Summer 24,546 25,937 24,146
System Reserve Margin (at peak) (percent) 19.3 13.2 14.3
Annual Load Factor (percent) 63.5 59.4 60.3
Plant Availability (percent):
Fossil-steam 85.2 87.9 88.6
Nuclear 89.8 85.9 85.2
----------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 70.8 73.0 71.7
Nuclear 17.9 16.3 16.2
Hydro 4.7 3.9 4.6
Oil and gas 0.9 0.9 0.5
Purchased power 5.7 5.9 7.0
----------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0
==========================================================================================================
Total Fuel Economy Data:
BTU per net kilowatt-hour generated 10,010 9,994 9,976
Cost of fuel per million BTU (cents) 155.81 166.85 162.58
Average cost of fuel per net kilowatt-hour generated (cents) 1.56 1.67 1.62
----------------------------------------------------------------------------------------------------------
II-40
SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA (continued)
The Southern Company and Subsidiary Companies 1994 Annual Report
==========================================================================================================
1991 1990 1989
----------------------------------------------------------------------------------------------------------
Operating Revenues (in millions):
Residential $2,391 $2,342 $2,194
Commercial 2,122 2,062 1,965
Industrial 2,088 2,085 2,011
Other 65 64 60
----------------------------------------------------------------------------------------------------------
Total retail 6,666 6,553 6,230
Sales for resale within service area 417 412 401
Sales for resale outside service area 884 977 928
----------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 7,967 7,942 7,559
Other revenues 83 111 61
----------------------------------------------------------------------------------------------------------
Total $8,050 $8,053 $7,620
==========================================================================================================
Kilowatt-Hour Sales (in millions):
Residential 33,622 33,118 31,627
Commercial 30,379 29,658 28,454
Industrial 46,050 45,974 45,022
Other 817 806 787
----------------------------------------------------------------------------------------------------------
Total retail 110,868 109,556 105,890
Sales for resale within service area 12,320 11,134 11,419
Sales for resale outside service area 19,839 24,402 24,228
----------------------------------------------------------------------------------------------------------
Total 143,027 145,092 141,537
==========================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 7.11 7.07 6.94
Commercial 6.99 6.96 6.91
Industrial 4.53 4.53 4.47
Total retail 6.01 5.98 5.88
Sales for resale 4.05 3.91 3.73
Total sales 5.57 5.47 5.34
Average Annual Kilowatt-Hour Use Per Residential Customer 11,659 11,637 11,287
Average Annual Revenue Per Residential Customer $829.18 $822.93 $782.90
Plant Nameplate Capacity Ratings (year-end) (megawatts) 29,915 29,532 29,532
Maximum Peak-Hour Demand (megawatts):
Winter 19,166 17,629 20,772
Summer 25,261 25,981 24,399
System Reserve Margin (at peak) (percent) 16.5 14.0 21.0
Annual Load Factor (percent) 58.3 56.6 58.6
Plant Availability (percent):
Fossil-steam 91.3 91.9 92.2
Nuclear 83.4 83.0 87.0
----------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 72.6 72.1 71.5
Nuclear 16.2 15.6 15.7
Hydro 4.4 4.4 5.2
Oil and gas 0.6 1.3 1.1
Purchased power 6.2 6.6 6.5
----------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0
==========================================================================================================
Total Fuel Economy Data:
BTU per net kilowatt-hour generated 10,022 10,065 10,086
Cost of fuel per million BTU (cents) 168.28 172.81 171.00
Average cost of fuel per net kilowatt-hour generated (cents) 1.69 1.74 1.72
----------------------------------------------------------------------------------------------------------
II-41A
SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA (continued)
The Southern Company and Subsidiary Companies 1994 Annual Report
==========================================================================================================
1988 1987 1986
----------------------------------------------------------------------------------------------------------
Operating Revenues (in millions):
Residential $2,103 $2,042 $1,996
Commercial 1,835 1,692 1,613
Industrial 1,945 1,870 1,845
Other 56 54 52
----------------------------------------------------------------------------------------------------------
Total retail 5,939 5,658 5,506
Sales for resale within service area 480 461 511
Sales for resale outside service area 777 1,028 957
----------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 7,196 7,147 6,974
Other revenues 91 57 59
----------------------------------------------------------------------------------------------------------
Total $7,287 $7,204 $7,033
==========================================================================================================
Kilowatt-Hour Sales (in millions):
Residential 31,041 30,583 29,501
Commercial 27,005 25,593 24,166
Industrial 43,675 42,113 40,503
Other 763 737 723
----------------------------------------------------------------------------------------------------------
Total retail 102,484 99,026 94,893
Sales for resale within service area 14,806 13,282 14,347
Sales for resale outside service area 15,860 22,905 16,909
----------------------------------------------------------------------------------------------------------
Total 133,150 135,213 126,149
==========================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 6.77 6.68 6.77
Commercial 6.79 6.61 6.67
Industrial 4.45 4.44 4.56
Total retail 5.80 5.71 5.80
Sales for resale 4.10 4.11 4.69
Total sales 5.40 5.29 5.53
Average Annual Kilowatt-Hour Use Per Residential Customer 11,255 11,307 11,157
Average Annual Revenue Per Residential Customer $762.42 $754.96 $754.93
Plant Nameplate Capacity Ratings (year-end) (megawatts) 27,552 27,610 26,262
Maximum Peak-Hour Demand (megawatts):
Winter 18,685 18,185 19,665
Summer 23,641 23,194 23,255
System Reserve Margin (at peak) (percent) 15.0 16.2 11.4
Annual Load Factor (percent) 59.8 58.7 57.2
Plant Availability (percent):
Fossil-steam 91.3 91.2 90.3
Nuclear 78.4 84.5 74.2
----------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 77.7 77.8 79.4
Nuclear 14.5 13.1 11.5
Hydro 2.3 3.3 2.2
Oil and gas 0.7 0.6 0.9
Purchased power 4.8 5.2 6.0
----------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0
==========================================================================================================
Total Fuel Economy Data:
BTU per net kilowatt-hour generated 10,094 10,122 10,171
Cost of fuel per million BTU (cents) 170.36 176.64 185.89
Average cost of fuel per net kilowatt-hour generated (cents) 1.72 1.78 1.89
----------------------------------------------------------------------------------------------------------
II-41B
SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA (continued)
The Southern Company and Subsidiary Companies 1994 Annual Report
==============================================================================================
1985 1984
----------------------------------------------------------------------------------------------
Operating Revenues (in millions):
Residential $1,825 $1,751
Commercial 1,512 1,410
Industrial 1,830 1,790
Other 50 47
----------------------------------------------------------------------------------------------
Total retail 5,217 4,998
Sales for resale within service area 436 456
Sales for resale outside service area 1,289 854
----------------------------------------------------------------------------------------------
Total revenues from sales of electricity 6,942 6,308
Other revenues 57 42
----------------------------------------------------------------------------------------------
Total $6,999 $6,350
==============================================================================================
Kilowatt-Hour Sales (in millions):
Residential 27,088 26,163
Commercial 22,512 20,816
Industrial 39,804 39,055
Other 713 663
----------------------------------------------------------------------------------------------
Total retail 90,117 86,697
Sales for resale within service area 11,079 11,193
Sales for resale outside service area 27,881 21,374
----------------------------------------------------------------------------------------------
Total 129,077 119,264
==============================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 6.74 6.69
Commercial 6.71 6.77
Industrial 4.60 4.58
Total retail 5.79 5.76
Sales for resale 4.43 4.02
Total sales 5.38 5.29
Average Annual Kilowatt-Hour Use Per Residential Customer 10,515 10,434
Average Annual Revenue Per Residential Customer $708.46 $698.26
Plant Nameplate Capacity Ratings (year-end) (megawatts) 26,262 25,397
Maximum Peak-Hour Demand (megawatts):
Winter 19,347 16,353
Summer 21,778 20,210
System Reserve Margin (at peak) (percent) 17.6 32.8
Annual Load Factor (percent) 57.4 58.9
Plant Availability (percent):
Fossil-steam 90.5 90.5
Nuclear 80.3 66.9
----------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 78.5 77.3
Nuclear 12.0 11.8
Hydro 3.1 5.6
Oil and gas 0.3 0.2
Purchased power 6.1 5.1
----------------------------------------------------------------------------------------------
Total 100.0 100.0
==============================================================================================
Total Fuel Economy Data:
BTU per net kilowatt-hour generated 10,193 10,208
Cost of fuel per million BTU (cents) 191.24 191.44
Average cost of fuel per net kilowatt-hour generated (cents) 1.95 1.95
----------------------------------------------------------------------------------------------
II-41C
CONSOLIDATED STATEMENTS OF INCOME
The Southern Company and Subsidiary Companies
=======================================================================================================
For the Years Ended December 31, 1994 1993 1992
-------------------------------------------------------------------------------------------------------
(Millions of Dollars)
-------------------------------------------------------------------------------------------------------
Operating Revenues $ 8,297 $ 8,489 $ 8,073
-------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
Fuel 2,058 2,265 2,114
Purchased power 277 336 454
Proceeds from settlement of disputed contracts - (3) (7)
Other 1,505 1,448 1,317
Maintenance 660 653 613
Depreciation and amortization 821 793 768
Deferred Plant Vogtle expenses, net 75 36 (31)
Taxes other than income taxes 475 462 436
Federal and state income taxes 711 734 647
-------------------------------------------------------------------------------------------------------
Total operating expenses 6,582 6,724 6,311
-------------------------------------------------------------------------------------------------------
Operating Income 1,715 1,765 1,762
Other Income (Expense):
Allowance for equity funds used during construction 11 9 10
Deferred return on Plant Vogtle - - -
Write-off of Plant Vogtle costs - - -
Income tax reduction for write-off of Plant Vogtle costs - - -
Interest income 32 30 32
Other, net (48) (41) (50)
Income taxes applicable to other income 26 57 39
-------------------------------------------------------------------------------------------------------
Income Before Interest Charges 1,736 1,820 1,793
-------------------------------------------------------------------------------------------------------
Interest Charges and Preferred Dividends:
Interest on long-term debt 568 595 684
Allowance for debt funds used during construction (18) (13) (12)
Interest on interim obligations 33 30 16
Amortization of debt discount, premium, and expense, net 30 26 14
Other interest charges 47 87 34
Preferred and preference dividends of subsidiary companies 87 93 104
-------------------------------------------------------------------------------------------------------
Net interest charges and preferred and preference dividends 747 818 840
-------------------------------------------------------------------------------------------------------
Consolidated Net Income $ 989 $ 1,002 $ 953
=======================================================================================================
Earnings Per Share of Common Stock $1.52 $1.57 $1.51
Average Number of Shares of Common Stock Outstanding (Thousands) 649,927 637,319 631,844
=======================================================================================================
II-42
CONSOLIDATED STATEMENTS OF INCOME
The Southern Company and Subsidiary Companies
===============================================================================================================
For the Years Ended December 31, 1991 1990 1989 1988
(Millions of Dollars)
---------------------------------------------------------------------------------------------------------------
Operating Revenues $ 8,050 $ 8,053 $ 7,620 $ 7,287
---------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
Fuel 2,237 2,327 2,241 2,213
Purchased power 468 642 575 562
Proceeds from settlement of disputed contracts (181) - - -
Other 1,321 1,161 1,103 1,167
Maintenance 637 602 542 547
Depreciation and amortization 763 749 698 632
Deferred Plant Vogtle expenses, net 16 31 (39) (8)
Taxes other than income taxes 432 397 356 362
Federal and state income taxes 618 520 525 412
---------------------------------------------------------------------------------------------------------------
Total operating expenses 6,311 6,429 6,001 5,887
---------------------------------------------------------------------------------------------------------------
Operating Income 1,739 1,624 1,619 1,400
Other Income (Expense):
Allowance for equity funds used during construction 13 33 71 138
Deferred return on Plant Vogtle 35 83 48 107
Write-off of Plant Vogtle costs - (281) - -
Income tax reduction for write-off of Plant Vogtle costs - 63 - -
Interest income 30 28 28 46
Other, net (57) (55) (50) (30)
Income taxes applicable to other income 21 36 30 23
---------------------------------------------------------------------------------------------------------------
Income Before Interest Charges 1,781 1,531 1,746 1,684
---------------------------------------------------------------------------------------------------------------
Interest Charges and Preferred Dividends:
Interest on long-term debt 757 788 791 784
Allowance for debt funds used during construction (18) (34) (63) (130)
Interest on interim obligations 20 22 12 22
Amortization of debt discount, premium, and expense, net 9 10 11 10
Other interest charges 29 26 26 32
Preferred and preference dividends of subsidiary companies 108 115 123 120
---------------------------------------------------------------------------------------------------------------
Net interest charges and preferred and preference dividends 905 927 900 838
---------------------------------------------------------------------------------------------------------------
Consolidated Net Income $ 876 $ 604 $ 846 $ 846
===============================================================================================================
Earnings Per Share of Common Stock $1.39 $0.96 $1.34 $1.36
Average Number of Shares of Common Stock Outstanding (Thousands) 631,307 631,307 631,303 622,292
===============================================================================================================
II-43A
CONSOLIDATED STATEMENTS OF INCOME
The Southern Company and Subsidiary Companies
===============================================================================================================
For the Years Ended December 31, 1987 1986 1985 1984
(Millions of Dollars)
---------------------------------------------------------------------------------------------------------------
Operating Revenues $ 7,204 $ 7,033 $ 6,999 $ 6,350
---------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
Fuel 2,303 2,316 2,431 2,197
Purchased power 552 386 456 435
Proceeds from settlement of disputed contracts - - - -
Other 1,219 1,045 941 840
Maintenance 574 576 562 494
Depreciation and amortization 563 510 471 444
Deferred Plant Vogtle expenses, net (142) - - -
Taxes other than income taxes 349 315 303 283
Federal and state income taxes 517 672 649 576
---------------------------------------------------------------------------------------------------------------
Total operating expenses 5,935 5,820 5,813 5,269
---------------------------------------------------------------------------------------------------------------
Operating Income 1,269 1,213 1,186 1,081
Other Income (Expense):
Allowance for equity funds used during construction 190 312 269 212
Deferred return on Plant Vogtle 115 - - -
Write-off of Plant Vogtle costs (358) - - -
Income tax reduction for write-off of Plant Vogtle costs 129 - - -
Interest income 77 66 70 61
Other, net (59) (20) - 46
Income taxes applicable to other income 19 - (19) (42)
---------------------------------------------------------------------------------------------------------------
Income Before Interest Charges 1,382 1,571 1,506 1,358
---------------------------------------------------------------------------------------------------------------
Interest Charges and Preferred Dividends:
Interest on long-term debt 776 782 755 679
Allowance for debt funds used during construction (157) (260) (254) (199)
Interest on interim obligations 24 4 21 16
Amortization of debt discount, premium, and expense, net 8 6 3 2
Other interest charges 29 15 17 15
Preferred and preference dividends of subsidiary companies 125 121 119 110
---------------------------------------------------------------------------------------------------------------
Net interest charges and preferred and preference dividends 805 668 661 623
---------------------------------------------------------------------------------------------------------------
Consolidated Net Income $ 577 $ 903 $ 845 $ 735
===============================================================================================================
Earnings Per Share of Common Stock $0.96 $1.56 $1.56 $1.47
Average Number of Shares of Common Stock Outstanding (Thousands) 601,390 580,252 541,244 501,313
===============================================================================================================
II-43B
CONSOLIDATED STATEMENTS OF CASH FLOWS
The Southern Company and Subsidiary Companies
============================================================================================
For the Years Ended December 31, 1994 1993 1992
--------------------------------------------------------------------------------------------
(Millions of Dollars)
Operating Activities:
Net income $ 989 $ 1,002 $ 953
Adjustments to reconcile net income to net
cash provided by operating activities --
Depreciation and amortization 1,050 1,011 969
Deferred income taxes, net (3) 209 221
Deferred investment tax credits, net (1) (20) (6)
Allowance for equity funds used during construction (11) (9) (10)
Deferred Plant Vogtle costs 75 36 (31)
Write-off of Plant Vogtle costs - - -
Non-cash proceeds from settlement of disputed contracts - - (7)
Other, net (7) (45) (25)
Changes in certain current assets and liabilities --
Receivables 114 (55) (10)
Inventories (128) 136 (23)
Payables 81 43 35
Taxes accrued - 3 (62)
Other (48) (64) (9)
--------------------------------------------------------------------------------------------
Net cash provided from operating activities 2,111 2,247 1,995
--------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (1,536) (1,441) (1,105)
Foreign utility operations (405) (465) -
Sales of property 171 262 44
Other (87) (37) 61
--------------------------------------------------------------------------------------------
Net cash used for investing activities (1,857) (1,681) (1,000)
--------------------------------------------------------------------------------------------
Financing Activities:
Proceeds:
Common stock 279 205 30
Preferred securities of subsidiary 100 - -
Preferred stock - 426 410
First mortgage bonds 185 2,185 1,815
Pollution control bonds 749 386 208
Other long-term debt 439 206 48
Prepaid capacity revenues - - -
Retirements:
Preferred and preference stock (1) (516) (326)
First mortgage bonds (241) (2,178) (2,575)
Pollution control bonds (732) (351) (208)
Other long-term debt (307) (99) (88)
Interim obligations, net 37 114 525
Payment of common stock dividends (766) (726) (695)
Miscellaneous (35) (137) (148)
--------------------------------------------------------------------------------------------
Net cash provided from (used for) financing activities (293) (485) (1,004)
--------------------------------------------------------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents (39) 81 (9)
Cash and Cash Equivalents at Beginning of Year 178 97 106
--------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 139 $ 178 $ 97
============================================================================================
( ) Denotes use of cash.
II-44
CONSOLIDATED STATEMENTS OF CASH FLOWS
The Southern Company and Subsidiary Companies
======================================================================================================
For the Years Ended December 31, 1991 1990 1989 1988
------------------------------------------------------------------------------------------------------
(Millions of Dollars)
Operating Activities:
Net income $ 876 $ 604 $ 846 $ 846
Adjustments to reconcile net income to net
cash provided by operating activities --
Depreciation and amortization 968 982 951 837
Deferred income taxes, net 26 158 225 206
Deferred investment tax credits, net (11) - (1) 27
Allowance for equity funds used during construction (13) (33) (71) (138)
Deferred Plant Vogtle costs (19) (52) (87) (115)
Write-off of Plant Vogtle costs - 281 - -
Non-cash proceeds from settlement of disputed contracts (141) - - -
Other, net 45 (10) (28) 46
Changes in certain current assets and liabilities --
Receivables 68 8 (123) (21)
Inventories 20 (82) 6 (47)
Payables (13) (41) (23) (6)
Taxes accrued 107 (5) (15) 29
Other (46) (34) 156 (40)
------------------------------------------------------------------------------------------------------
Net cash provided from operating activities 1,867 1,776 1,836 1,624
------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (1,123) (1,185) (1,346) (1,754)
Foreign utility operations - - - -
Sales of property 291 35 - -
Other (45) 14 54 (2)
------------------------------------------------------------------------------------------------------
Net cash used for investing activities (877) (1,136) (1,292) (1,756)
------------------------------------------------------------------------------------------------------
Financing Activities:
Proceeds:
Common stock - - 4 194
Preferred securities of subsidiary - - - -
Preferred stock 100 - - 120
First mortgage bonds 380 300 280 335
Pollution control bonds 126 - 104 73
Other long-term debt 14 74 74 68
Prepaid capacity revenues 53 - - -
Retirements:
Preferred and preference stock (125) (96) (21) (10)
First mortgage bonds (881) (146) (201) (273)
Pollution control bonds (130) (3) (55) (1)
Other long-term debt (70) (207) (83) (108)
Interim obligations, net 180 78 27 (300)
Payment of common stock dividends (676) (676) (675) (661)
Miscellaneous (41) (8) (10) (20)
------------------------------------------------------------------------------------------------------
Net cash provided from (used for) financing activities (1,070) (684) (556) (583)
------------------------------------------------------------------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents (80) (44) (12) (715)
Cash and Cash Equivalents at Beginning of Year 186 230 242 957
------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 106 $ 186 $ 230 $ 242
======================================================================================================
( ) Denotes use of cash.
II-45A
CONSOLIDATED STATEMENTS OF CASH FLOWS
The Southern Company and Subsidiary Companies
======================================================================================================
For the Years Ended December 31, 1987 1986 1985 1984
------------------------------------------------------------------------------------------------------
(Millions of Dollars)
Operating Activities:
Net income $ 577 $ 903 $ 845 $ 735
Adjustments to reconcile net income to net
cash provided by operating activities --
Depreciation and amortization 742 674 623 581
Deferred income taxes, net 198 465 242 243
Deferred investment tax credits, net 20 132 184 245
Allowance for equity funds used during construction (190) (312) (269) (212)
Deferred Plant Vogtle costs (257) - - -
Write-off of Plant Vogtle costs 358 - - -
Non-cash proceeds from settlement of disputed contracts - - - -
Other, net 87 15 17 (190)
Changes in certain current assets and liabilities --
Receivables (113) 38 (89) (27)
Inventories (62) (37) 127 (69)
Payables 125 48 38 187
Taxes accrued (34) 24 (65) 32
Other 42 (56) 84 70
------------------------------------------------------------------------------------------------------
Net cash provided from operating activities 1,493 1,894 1,737 1,595
------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (1,853) (2,367) (2,242) (2,130)
Foreign utility operations - - - -
Sales of property 12 - 1 321
Other 64 46 126 110
------------------------------------------------------------------------------------------------------
Net cash used for investing activities (1,777) (2,321) (2,115) (1,699)
------------------------------------------------------------------------------------------------------
Financing Activities:
Proceeds:
Common stock 247 379 373 318
Preferred securities of subsidiary - - - -
Preferred stock 125 100 150 50
First mortgage bonds 700 735 20 150
Pollution control bonds 228 386 635 368
Other long-term debt 81 367 68 28
Prepaid capacity revenues - 100 - -
Retirements:
Preferred and preference stock (160) (53) (6) (6)
First mortgage bonds (369) (875) (69) (71)
Pollution control bonds (122) (21) - (4)
Other long-term debt (56) (55) (54) (99)
Interim obligations, net 313 (37) (77) 118
Payment of common stock dividends (628) (583) (512) (444)
Miscellaneous (58) (82) (24) (22)
------------------------------------------------------------------------------------------------------
Net cash provided from (used for) financing activities 301 361 504 386
------------------------------------------------------------------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents 17 (66) 126 282
Cash and Cash Equivalents at Beginning of Year 940 1,006 880 598
------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 957 $ 940 $ 1,006 $ 880
======================================================================================================
( ) Denotes use of cash.
II-45B
CONSOLIDATED BALANCE SHEETS
The Southern Company and Subsidiary Companies
====================================================================================================
At December 31, 1994 1993 1992
----------------------------------------------------------------------------------------------------
(Millions of Dollars)
ASSETS
Electric Plant:
Production-
Fossil $ 8,778 $ 8,006 $ 8,033
Nuclear 5,942 5,930 5,912
Hydro 1,341 1,263 1,253
----------------------------------------------------------------------------------------------------
Total production 16,061 15,199 15,198
Transmission 3,504 3,224 3,093
Distribution 7,243 6,848 6,430
General 2,380 2,395 2,291
Construction work in progress 1,247 1,031 665
Nuclear fuel, at amortized cost 238 229 257
----------------------------------------------------------------------------------------------------
Total electric plant 30,673 28,926 27,934
----------------------------------------------------------------------------------------------------
Steam Heat Plant 21 21 21
----------------------------------------------------------------------------------------------------
Total utility plant 30,694 28,947 27,955
----------------------------------------------------------------------------------------------------
Accumulated Provision for Depreciation:
Electric 9,567 8,924 8,271
Steam heat 10 10 9
----------------------------------------------------------------------------------------------------
Total accumulated provision for depreciation 9,577 8,934 8,280
----------------------------------------------------------------------------------------------------
Total 21,117 20,013 19,675
----------------------------------------------------------------------------------------------------
Less property-related accumulated deferred income taxes - - 3,186
----------------------------------------------------------------------------------------------------
Total 21,117 20,013 16,489
----------------------------------------------------------------------------------------------------
Other Property and Investments:
Securities received from settlement of disputed contracts - - -
Argentine operating concession, being amortized 446 469 -
Nuclear decommissioning trusts 125 88 52
Miscellaneous 224 179 75
----------------------------------------------------------------------------------------------------
Total 795 736 127
----------------------------------------------------------------------------------------------------
Current Assets:
Cash and cash equivalents 139 178 97
Investment securities - - 199
Receivables, net 840 962 742
Accrued utility revenues 218 185 177
Fossil fuel stock, at average cost 354 254 392
Materials and supplies, at average cost 553 535 533
Prepayments 194 148 220
Vacation pay deferred 70 73 70
----------------------------------------------------------------------------------------------------
Total 2,368 2,335 2,430
----------------------------------------------------------------------------------------------------
Deferred Charges:
Deferred charges related to income taxes 1,454 1,546 -
Deferred Plant Vogtle costs 432 507 383
Deferred fuel charges 47 70 89
Debt expense, being amortized 48 33 28
Premium on reacquired debt, being amortized 298 288 222
Miscellaneous 483 383 270
----------------------------------------------------------------------------------------------------
Total 2,762 2,827 992
----------------------------------------------------------------------------------------------------
Total Assets $ 27,042 $25,911 $20,038
====================================================================================================
II-46
CONSOLIDATED BALANCE SHEETS
The Southern Company and Subsidiary Companies
================================================================================================================
At December 31, 1991 1990 1989 1988
----------------------------------------------------------------------------------------------------------------
(Millions of Dollars)
ASSETS
Electric Plant:
Production-
Fossil $ 7,997 $ 7,661 $ 7,565 $ 6,226
Nuclear 5,902 5,820 5,976 4,995
Hydro 1,247 1,222 1,215 1,197
----------------------------------------------------------------------------------------------------------------
Total production 15,146 14,703 14,756 12,418
Transmission 2,955 2,824 2,683 2,500
Distribution 6,092 5,738 5,365 4,944
General 2,196 2,078 2,026 1,865
Construction work in progress 603 1,092 1,006 3,071
Nuclear fuel, at amortized cost 301 354 402 481
----------------------------------------------------------------------------------------------------------------
Total electric plant 27,293 26,789 26,238 25,279
----------------------------------------------------------------------------------------------------------------
Steam Heat Plant 20 20 20 20
----------------------------------------------------------------------------------------------------------------
Total utility plant 27,313 26,809 26,258 25,299
----------------------------------------------------------------------------------------------------------------
Accumulated Provision for Depreciation:
Electric 7,676 7,079 6,492 5,885
Steam heat 8 8 7 6
----------------------------------------------------------------------------------------------------------------
Total accumulated provision for depreciation 7,684 7,087 6,499 5,891
----------------------------------------------------------------------------------------------------------------
Total 19,629 19,722 19,759 19,408
----------------------------------------------------------------------------------------------------------------
Less property-related accumulated deferred income taxes 3,020 2,911 2,759 2,559
----------------------------------------------------------------------------------------------------------------
Total 16,609 16,811 17,000 16,849
----------------------------------------------------------------------------------------------------------------
Other Property and Investments:
Securities received from settlement of disputed contracts 202 - - -
Argentine operating concession, being amortized - - - -
Nuclear decommissioning trusts 26 2 - -
Miscellaneous 83 83 85 88
----------------------------------------------------------------------------------------------------------------
Total 311 85 85 88
----------------------------------------------------------------------------------------------------------------
Current Assets:
Cash and cash equivalents 106 186 230 242
Investment securities - - - -
Receivables, net 723 793 765 687
Accrued utility revenues 160 151 189 148
Fossil fuel stock, at average cost 445 467 427 490
Materials and supplies, at average cost 457 456 413 348
Prepayments 222 193 192 174
Vacation pay deferred 70 64 65 63
----------------------------------------------------------------------------------------------------------------
Total 2,183 2,310 2,281 2,152
----------------------------------------------------------------------------------------------------------------
Deferred Charges:
Deferred charges related to income taxes - - - -
Deferred Plant Vogtle costs 375 364 322 270
Deferred fuel charges 106 126 143 157
Debt expense, being amortized 23 23 24 24
Premium on reacquired debt, being amortized 126 99 103 102
Miscellaneous 130 137 134 89
----------------------------------------------------------------------------------------------------------------
Total 760 749 726 642
----------------------------------------------------------------------------------------------------------------
Total Assets $ 19,863 $19,955 $20,092 $19,731
================================================================================================================
II-47A
CONSOLIDATED BALANCE SHEETS
The Southern Company and Subsidiary Companies
================================================================================================================
At December 31, 1987 1986 1985 1984
----------------------------------------------------------------------------------------------------------------
(Millions of Dollars)
ASSETS
Electric Plant:
Production-
Fossil $ 6,157 $ 5,415 $ 5,274 $ 4,740
Nuclear 4,987 2,490 2,341 2,312
Hydro 1,192 1,184 1,162 863
---------------------------------------------------------------------------------------------------------------
Total production 12,336 9,089 8,777 7,915
Transmission 2,388 2,254 2,001 1,878
Distribution 4,510 4,131 3,793 3,491
General 1,674 1,504 1,243 1,037
Construction work in progress 2,519 5,162 4,278 3,830
Nuclear fuel, at amortized cost 479 520 497 455
----------------------------------------------------------------------------------------------------------------
Total electric plant 23,906 22,660 20,589 18,606
----------------------------------------------------------------------------------------------------------------
Steam Heat Plant 20 35 32 26
----------------------------------------------------------------------------------------------------------------
Total utility plant 23,926 22,695 20,621 18,632
----------------------------------------------------------------------------------------------------------------
Accumulated Provision for Depreciation:
Electric 5,355 4,879 4,472 4,056
Steam heat 6 13 11 11
----------------------------------------------------------------------------------------------------------------
Total accumulated provision for depreciation 5,361 4,892 4,483 4,067
----------------------------------------------------------------------------------------------------------------
Total 18,565 17,803 16,138 14,565
----------------------------------------------------------------------------------------------------------------
Less property-related accumulated deferred income taxes 2,371 2,212 1,976 1,792
----------------------------------------------------------------------------------------------------------------
Total 16,194 15,591 14,162 12,773
----------------------------------------------------------------------------------------------------------------
Other Property and Investments:
Securities received from settlement of disputed contracts - - - -
Argentine operating concession, being amortized - - - -
Nuclear decommissioning trusts - - - -
Miscellaneous 70 69 36 32
----------------------------------------------------------------------------------------------------------------
Total 70 69 36 32
----------------------------------------------------------------------------------------------------------------
Current Assets:
Cash and cash equivalents 957 940 1,006 880
Investment securities - - - -
Receivables, net 687 657 685 613
Accrued utility revenues 139 83 92 76
Fossil fuel stock, at average cost 513 501 503 649
Materials and supplies, at average cost 278 228 188 169
Prepayments 136 70 22 18
Vacation pay deferred 59 56 53 49
----------------------------------------------------------------------------------------------------------------
Total 2,769 2,535 2,549 2,454
----------------------------------------------------------------------------------------------------------------
Deferred Charges:
Deferred charges related to income taxes - - - -
Deferred Plant Vogtle costs 173 - - -
Deferred fuel charges 112 121 - -
Debt expense, being amortized 25 24 24 22
Premium on reacquired debt, being amortized 95 70 - -
Miscellaneous 80 73 84 46
----------------------------------------------------------------------------------------------------------------
Total 485 288 108 68
----------------------------------------------------------------------------------------------------------------
Total Assets $ 19,518 $18,483 $16,855 $15,327
================================================================================================================
II-47B
CONSOLIDATED BALANCE SHEETS
The Southern Company and Subsidiary Companies
====================================================================================================
At December 31, 1994 1993 1992
----------------------------------------------------------------------------------------------------
(Millions of Dollars)
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock $ 3,283 $ 3,213 $ 1,582
Paid-in capital 1,711 1,502 2,929
Premium on preferred stock 1 1 2
Retained Earnings 3,191 2,968 2,721
----------------------------------------------------------------------------------------------------
Total common equity 8,186 7,684 7,234
Preferred stock 1,332 1,332 1,351
Preferred stock subject to mandatory redemption - 1 8
Preferred securities of subsidiary 100 - -
Long-term debt 7,593 7,412 7,241
----------------------------------------------------------------------------------------------------
Total (excluding amount due within one year) 17,211 16,429 15,834
----------------------------------------------------------------------------------------------------
Current Liabilities:
Notes payable to banks 575 865 567
Commercial paper 403 76 260
Preferred stock due within one year 1 1 65
Long-term debt due within one year 228 156 188
Accounts payable 806 698 646
Customer deposits 102 103 99
Taxes accrued 153 206 172
Interest accrued 190 186 191
Vacation pay accrued 87 90 86
Miscellaneous 233 190 242
----------------------------------------------------------------------------------------------------
Total 2,778 2,571 2,516
----------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 4,007 3,979 -
Deferred credits related to income taxes 987 1,051 -
Accumulated deferred investment tax credits 858 900 957
Prepaid capacity revenues, net 138 144 148
Disallowed Plant Vogtle capacity buyback costs 60 63 72
Miscellaneous 1,003 774 511
----------------------------------------------------------------------------------------------------
Total 7,053 6,911 1,688
----------------------------------------------------------------------------------------------------
Total Capitalization and Liabilities $ 27,042 $25,911 $20,038
====================================================================================================
II-48
CONSOLIDATED BALANCE SHEETS
The Southern Company and Subsidiary Companies
================================================================================================================
At December 31, 1991 1990 1989 1988
----------------------------------------------------------------------------------------------------------------
(Millions of Dollars)
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock $ 1,578 $ 1,578 $ 1,578 $ 1,577
Paid-in capital 2,906 2,906 2,906 2,903
Premium on preferred stock 2 3 3 3
Retained Earnings 2,490 2,296 2,374 2,203
----------------------------------------------------------------------------------------------------------------
Total common equity 6,976 6,783 6,861 6,686
Preferred stock 1,207 1,207 1,209 1,259
Preferred stock subject to mandatory redemption 126 151 191 206
Preferred securities of subsidiary - - - -
Long-term debt 7,992 8,458 8,575 8,433
----------------------------------------------------------------------------------------------------------------
Total (excluding amount due within one year) 16,301 16,599 16,836 16,584
----------------------------------------------------------------------------------------------------------------
Current Liabilities:
Notes payable to banks 302 122 44 17
Commercial paper - - - -
Preferred stock due within one year 7 7 61 17
Long-term debt due within one year 217 308 169 190
Accounts payable 585 616 676 728
Customer deposits 95 91 89 83
Taxes accrued 215 144 181 203
Interest accrued 221 246 233 240
Vacation pay accrued 84 75 75 74
Miscellaneous 229 233 252 104
----------------------------------------------------------------------------------------------------------------
Total 1,955 1,842 1,780 1,656
----------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes - - - -
Deferred credits related to income taxes - - - -
Accumulated deferred investment tax credits 1,004 1,063 1,111 1,161
Prepaid capacity revenues, net 149 100 102 81
Disallowed Plant Vogtle capacity buyback costs 110 136 73 104
Miscellaneous 344 215 190 145
----------------------------------------------------------------------------------------------------------------
Total 1,607 1,514 1,476 1,491
----------------------------------------------------------------------------------------------------------------
Total Capitalization and Liabilities $ 19,863 $19,955 $20,092 $19,731
================================================================================================================
II-49A
CONSOLIDATED BALANCE SHEETS
The Southern Company and Subsidiary Companies
================================================================================================================
At December 31, 1987 1986 1985 1984
----------------------------------------------------------------------------------------------------------------
(Millions of Dollars)
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock $ 1,534 $ 1,481 $ 1,400 $ 1,305
Paid-in capital 2,752 2,558 2,259 1,981
Premium on preferred stock 3 5 7 7
Retained Earnings 2,018 2,089 1,777 1,448
----------------------------------------------------------------------------------------------------------------
Total common equity 6,307 6,133 5,443 4,741
Preferred stock 1,139 1,214 1,114 1,004
Preferred stock subject to mandatory redemption 224 177 194 205
Preferred securities of subsidiary - - - -
Long-term debt 8,333 7,813 7,220 6,775
----------------------------------------------------------------------------------------------------------------
Total (excluding amount due within one year) 16,003 15,337 13,971 12,725
----------------------------------------------------------------------------------------------------------------
Current Liabilities:
Notes payable to banks 317 4 41 118
Commercial paper - - - -
Preferred stock due within one year 9 15 51 6
Long-term debt due within one year 192 251 303 162
Accounts payable 747 737 689 651
Customer deposits 86 82 80 83
Taxes accrued 221 259 144 208
Interest accrued 233 221 226 208
Vacation pay accrued 68 66 63 58
Miscellaneous 110 111 117 91
----------------------------------------------------------------------------------------------------------------
Total 1,983 1,746 1,714 1,585
----------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes - - - -
Deferred credits related to income taxes - - - -
Accumulated deferred investment tax credits 1,180 1,208 1,114 968
Prepaid capacity revenues, net 104 101 - -
Disallowed Plant Vogtle capacity buyback costs 79 - - -
Miscellaneous 169 91 56 49
----------------------------------------------------------------------------------------------------------------
Total 1,532 1,400 1,170 1,017
----------------------------------------------------------------------------------------------------------------
Total Capitalization and Liabilities $ 19,518 $18,483 $16,855 $15,327
================================================================================================================
II-49B
ALABAMA POWER COMPANY
FINANCIAL SECTION
II-50
MANAGEMENT'S REPORT
Alabama Power Company 1994 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
II-51
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, 1994 and 1993, and the related
statements of income, retained earnings, and cash flows for each of the three
years in the period ended December 31, 1994. These financial statements are the
responsibility of the company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements (pages II-60 through II-78)
referred to above present fairly, in all material respects, the financial
position of Alabama Power Company as of December 31, 1994 and 1993, and the
results of its operations and its cash flows for the periods stated, in
conformity with generally accepted accounting principles.
As explained in Notes 2 and 8 to the financial statements, effective January
1, 1993, the company changed its methods of accounting for postretirement
benefits other than pensions and for income taxes.
/s/ Arthur Andersen LLP
Birmingham, Alabama
February 15, 1995
II-52
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Alabama Power Company 1994 Annual Report
RESULTS OF OPERATIONS
Earnings
Alabama Power Company's 1994 net income after dividends on preferred stock was
$356 million, representing a $10 million (2.8 percent) increase from the prior
year. This improvement can be attributed to lower operating expenses which
decreased 3.0 percent from the previous year as a result of the company's
strategy to remain a low-cost producer of electricity. This improvement was
partially offset by reduced capacity sales to nonterritorial utilities. Net
income was also impacted by the mild weather in 1994.
In 1993, earnings were $346 million, representing a 2.3 percent increase
over the prior year. This increase was due to higher retail energy sales and
lower financing costs. These positive factors were partially offset by higher
operating costs and a scheduled reduction in capacity sales to non-affiliated
utilities.
The return on average common equity for 1994 was 13.86 percent compared to
13.94 percent in 1993, and 14.02 percent in 1992.
Revenues
The following table summarizes the principal factors that affected operating
revenues for the past three years:
===============================================================
Increase (Decrease)
From Prior Year
-------------------------------------
1994 1993 1992
-------------------------------------
(in thousands)
Retail --
Change in
base rates $ -- $ -- $ 36,348
Unbilled
adjustment 28,000 -- --
Sales growth 45,304 24,960 36,237
Weather (39,964) 58,536 (42,709)
Fuel cost recovery
and other (84,344) 96,437 (31,318)
----------------------------------------------------------------
Total retail (51,004) 179,933 (1,442)
----------------------------------------------------------------
Sales for Resale --
Non-affiliates (9,345) (43,686) (121)
Affiliates (17,213) 23,887 (1,287)
----------------------------------------------------------------
Total sales for resale (26,558) (19,799) (1,408)
Other operating
revenues 5,095 635 2,896
----------------------------------------------------------------
Total operating
revenues $(72,467) $160,769 $ 46
================================================================
Percent change (2.4)% 5.6% -- %
================================================================
Retail revenues of $2.4 billion in 1994 decreased $51 million (2.1 percent)
from the prior year, compared with an increase of $180 million (8.0 percent) in
1993. The mild weather during the summer of 1994 and lower fuel cost recovery
were the primary reasons for the decrease in retail revenues from 1993. The
extreme weather during 1993 and sales growth contributed to the increase in
retail revenues over 1992. Fuel revenues, which decreased substantially in 1994,
generally represent the direct recovery of fuel expense, including the fuel
component of purchased energy, and therefore have no effect on net income. In
September 1994, the company recorded an additional $28 million (679 million
kilowatt-hours) in estimated unbilled revenues due to a change in the estimating
procedure for unbilled kilowatt-hours (KWHs) and associated revenues. For
additional information concerning unbilled revenues and an offsetting expense,
see Note 3 under "Retail Rate Adjustment Procedures."
II-53
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 1994 Annual Report
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. These capacity and energy
components, as well as the components of the sales to affiliated companies,
were:
============================================================
1994 1993 1992
------------------------------------------
(in thousands)
Capacity $165,063 $187,062 $216,113
Energy 222,579 233,253 239,622
------------------------------------------------------------
Total $387,642 $420,315 $455,735
============================================================
Capacity revenues from non-affiliates remained relatively constant in 1994
but decreased in 1993 due to a scheduled reduction in capacity dedicated to unit
power sales customers for the first five months of the year. 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.
KWH sales for 1994 and the percent change by year were as follows:
===============================================================
KWH Percent Change
-----------------------------------------
1994 1994 1993 1992
-----------------------------------------
(millions)
Residential 12,955 (1.7)% 9.2% (2.1)%
Commercial 9,495 3.4 6.4 1.2
Industrial 19,181 3.2 1.8 4.3
Unbilled
adjustment 679 - - -
Other 184 1.1 2.8 1.2
---------
Total retail 42,494 3.3 5.1 1.6
Sales for resale -
Non-affiliates 6,775 (5.2) (14.8) (4.9)
Affiliates 8,433 4.3 12.1 (7.4)
---------
Total 57,702 2.4% 3.0% (0.7)%
===============================================================
Expenses
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.
Total operating expenses for 1993 were up 7.0 percent over those recorded in
1992. The increase was mainly attributable to higher production expenses of $95
million to meet increased energy demands.
Fuel costs are the single largest expense for the company. The mix of fuel
sources for generation of electricity is determined primarily by system load,
the unit cost of fuel consumed, and the availability of hydro and nuclear
generating units. Fuel expense 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.
Fuel expense increased in 1993 as a result of increased energy demands during
the summer. Fuel cost per KWH generated was 1.56 cents in 1994, 1.73 cents in
1993 and 1.64 cents in 1992.
Purchased power consists primarily of purchases from the affiliates of the
Southern electric system. Purchased power 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. Purchased capacity from affiliates increased $5 million in 1994. KWH
purchases from affiliates decreased 27 percent from the prior year.
Other operation expenses decreased 2.5 percent in 1994 following a 5.6
percent increase in 1993. The increase in 1993 was primarily the result of
environmental cleanup costs, net expenses of a March snowstorm, and the one-time
cost of a transportation fleet reduction program, which together totaled $16.1
million.
Maintenance expenses increased 3.8 percent in 1994 over the previous year
due to the establishment of a Natural Disaster Reserve. For additional
information concerning the Natural Disaster Reserve, see Note 3 under "Retail
Rate Adjustment Procedures."
Depreciation and amortization expense remained virtually unchanged from the
previous year. This is the result of lower average depreciation rates effective
January 1994 offset by growth in depreciable plant in service. Depreciation and
II-54
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 1994 Annual Report
amortization expense increased 3.4 percent in 1993 due principally to growth in
depreciable plant in service.
Income taxes increased in 1994 by $17 million (8.2 percent). This is due to
higher taxable income. The increase in income tax expense of 2.6 percent for
1993 was primarily attributable to a one percent increase in the corporate
federal income tax rate effective January 1, 1993.
The company contributed $13.5 million to the Alabama Power Foundation, Inc.
in 1994, which represents an increase of $10.5 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 continued to
decline from amounts reported in the previous year. The declines reflect the
significant refinancing activities in 1993 and 1992. In 1994, these costs were
$236 million -- down $23 million (9.0 percent). These costs decreased $7.5
million (2.8 percent) in 1993.
Effects of Inflation
The company is subject to rate regulation and income tax laws that are based on
the recovery of historical costs. Therefore, inflation creates an economic loss
because the company is recovering its costs of investments in dollars that have
less purchasing power. While the inflation rate has been relatively low in
recent years, it continues to have an adverse effect on the company because of
the large investment in long-lived utility plant. Conventional accounting for
historical cost does not recognize this economic loss nor the partially
offsetting gain that arises through financing facilities with fixed-money
obligations, such as long-term debt and preferred stock. Any recognition of
inflation by regulatory authorities is reflected in the rate of return allowed.
Future Earnings Potential
The results of operations for the past three years are not necessarily
indicative of future earnings potential. The level of future earnings depends on
numerous factors ranging from growth in energy sales to 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 changes in contracts with neighboring utilities, energy conservation
practiced by customers, the elasticity of demand, weather, competition, and the
rate of economic growth in the company's service area. However, the Energy
Policy Act of 1992 (Energy Act) 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 may enhance the
incentive for IPPs to build cogeneration plants for a utility's large industrial
and commercial customers and sell excess energy generation to other utilities.
Although the Energy Act does not require transmission access to retail
customers, retail wheeling initiatives are rapidly evolving and becoming very
prominent issues in several states. In order to address these initiatives,
numerous questions must be resolved with the most complex ones relating to
transmission pricing, recovery of stranded investments, and developing rate
structures for different market segments that reflect the economic costs of
serving that market. 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 scheduled addition of five combustion turbine generating units in 1995
and four more 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
II-55
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 1994 Annual Report
periodically within certain limitations based on earned retail rate of return
compared with an allowed return. See Note 3 to the financial statements for
information about other regulatory matters.
The 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. 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 is currently
reviewing the accounting for nuclear decommissioning. If current electric
utility industry accounting practices for decommissioning are changed: (1)
Annual provisions for decommissioning could increase. (2) The estimated cost for
decommissioning may be required to be recorded as a liability in the Balance
Sheets. In management's opinion -- should these changes be required -- the
changes would not have a significant adverse effect on results of operations
because of the company's current and expected future ability to recover
decommissioning costs through rates. See Note 1 to the financial statements
under "Depreciation and Nuclear Decommissioning" for additional information.
The Federal Energy Regulatory Commission (FERC) regulates wholesale rate
schedules and power sales contracts that the company has with its sales for
resale customers. The FERC currently is reviewing the rate of return on common
equity included in these schedules and contracts and may require such returns to
be lowered, possibly retroactively. See Note 3 to the financial statements under
"FERC Reviews Equity Returns" for additional information.
Compliance costs related to the Clean Air Act Amendments of 1990 (Clean Air
Act) could affect earnings if such costs are not fully recovered. The Clean Air
Act and other important environmental items are discussed later under
"Environmental Matters."
FINANCIAL CONDITION
Overview
The company's financial condition remained stable in 1994. 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 $537 million in 1994. The
majority of funds needed for gross property additions since 1991 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 was 47.4 percent in
1994 and 1993, compared to 47.6 percent in 1992.
In 1994, the company issued $150 million of first mortgage bonds and through
public authorities, $180 million of pollution control revenue refunding bonds.
Composite financing rates as of year-end for 1992 through 1994 were as follows:
================================================================
1994 1993 1992
------------------------------
Composite interest rate on
long-term debt 7.39% 7.35% 8.00%
Composite dividend rate on
preferred stock 6.23% 5.80% 6.76%
================================================================
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-
==============================================================
II-56
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 1994 Annual Report
Capital Requirements
Capital expenditures are estimated to be $604 million for 1995, $500 million for
1996, and $502 million for 1997. The total is $1.6 billion for the three years.
Actual capital costs may vary from this estimate because of factors such as
changes in environmental regulations; changes in the existing nuclear plant to
meet new regulations; revised load projections; 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
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 construction of
combustion turbine peaking units of approximately 720 megawatts of capacity is
planned by 1996 to meet increased peak-hour demands. In addition, significant
construction of transmission and distribution facilities and upgrading of
generating plants will continue.
Other Capital Requirements
In addition to the funds needed for the capital budget, approximately $60
million will be required by the end of 1997 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, as 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 -- will have a
significant impact on the Southern electric system. Specific reductions in
sulfur dioxide and nitrogen oxide emissions from fossil-fired generating plants
will be required in two phases. Phase I compliance began in 1995 and affected
eight generating plants -- some 10,000 megawatts of capacity or 35 percent of
total capacity -- in the Southern electric system. Phase II compliance is
required in 2000, and all fossil-fired generating plants in the Southern
electric system will be affected.
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 expects to achieve Phase I sulfur dioxide compliance at
the eight affected plants by switching to low-sulfur coal, which has required
some equipment upgrades. This compliance strategy is expected to result in
unused emission allowances being banked for later use. Additional construction
expenditures were required to install equipment for the control of nitrogen
oxide emissions at these eight plants. Also, continuous emissions monitoring
equipment will be installed on all fossil-fired units. Construction expenditures
for Phase I compliance are estimated to total approximately $300 million through
1995 for The Southern Company, of which the company's portion is approximately
$30 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 anticipated Phase II
limits. Therefore, during the period 1996 to 2000, compliance could require
total estimated construction expenditures of $150 million for The Southern
Company, of which the company's portion is approximately $80 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.
II-57
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 1994 Annual Report
An average increase of up to 2 percent in annual revenue requirements from
customers could be necessary to fully recover the company's cost of compliance
for both Phase I and Phase II of 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 by November 1995. 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.
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.
The EPA continues to evaluate the need for a new short-term ambient air
quality standard for sulfur dioxide. Preliminary results from an EPA study on
the impact of a new standard indicate that a number of plants could be required
to install sulfur dioxide controls. These controls would be in addition to the
controls already required to meet the acid rain provision of the Clean Air Act.
The EPA issued proposed rules in November 1994 and is required to take final
action on this issue in 1996. The impact of any new standard will depend on the
level chosen for the standard and cannot be determined at this time.
In addition, the EPA is evaluating the need to revise the ambient air quality
standards for particulate matter, nitrogen oxides, and ozone. The impact of any
new standard will depend on the level chosen for the standard and cannot be
determined at this time.
In 1995, 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.
Several major pieces of environmental legislation are being considered for
reauthorization or amendment by Congress. These include: the Clean Water Act;
the Comprehensive Environmental Response, Compensation, and Liability Act; the
Resource Conservation and Recovery 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
II-58
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 1994 Annual Report
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-59
STATEMENTS OF INCOME
For the Years Ended December 31, 1994, 1993, and 1992
Alabama Power Company 1994 Annual Report
====================================================================================================
1994 1993 1992
----------------------------------------------------------------------------------------------------
(in thousands)
Operating Revenues (Notes 1, 3 and 7):
Revenues $2,770,380 $2,825,634 $2,688,752
Revenues from affiliates 164,762 181,975 158,088
----------------------------------------------------------------------------------------------------
Total operating revenues 2,935,142 3,007,609 2,846,840
----------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
Fuel 801,948 877,099 794,438
Purchased power from non-affiliates 15,158 15,230 14,242
Purchased power from affiliates 100,888 120,330 107,230
Other 458,917 470,815 445,836
Maintenance 262,102 252,506 237,071
Depreciation and amortization 292,420 290,310 280,881
Taxes other than income taxes 183,425 178,997 172,095
Federal and state income taxes (Note 8) 224,280 207,210 201,925
----------------------------------------------------------------------------------------------------
Total operating expenses 2,339,138 2,412,497 2,253,718
----------------------------------------------------------------------------------------------------
Operating Income 596,004 595,112 593,122
Other Income (Expense):
Allowance for equity funds used during construction (Note 1) 3,239 3,260 2,071
Income from subsidiary (Note 6) 3,588 4,127 4,635
Charitable foundation (13,500) (3,000) (6,887)
Interest income 16,944 20,775 14,804
Other, net (30,569) (24,420) (11,019)
Income taxes applicable to other income 16,834 10,239 8,947
----------------------------------------------------------------------------------------------------
Income Before Interest Charges 592,540 606,093 605,673
----------------------------------------------------------------------------------------------------
Interest Charges:
Interest on long-term debt 178,045 184,861 206,871
Allowance for debt funds used during construction (Note 1) (3,548) (2,992) (2,416)
Interest on interim obligations 5,939 3,760 3,704
Amortization of debt discount, premium, and expense, net 9,623 8,937 4,392
Other interest charges 19,908 35,474 19,381
----------------------------------------------------------------------------------------------------
Net interest charges 209,967 230,040 231,932
----------------------------------------------------------------------------------------------------
Net Income 382,573 376,053 373,741
Dividends on Preferred Stock 26,235 29,559 35,186
----------------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred Stock $ 356,338 $ 346,494 $ 338,555
====================================================================================================
The accompanying notes are an integral part of these statements.
II-60
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1994, 1993, and 1992
Alabama Power Company 1994 Annual Report
=============================================================================================
1994 1993 1992
---------------------------------------------------------------------------------------------
(in thousands)
Operating Activities:
Net income $ 382,573 $ 376,053 $ 373,741
Adjustments to reconcile net income to net
cash provided by operating activities --
Depreciation and amortization 359,791 356,499 338,421
Deferred income taxes and investment tax credits (32,613) 32,994 23,514
Allowance for equity funds used during construction (3,239) (3,260) (2,071)
Other, net 28,656 36,493 (3,298)
Changes in certain current assets and liabilities --
Receivables, net 19,390 19,215 (11,010)
Inventories (38,946) 51,630 12,704
Payables (21,240) 31,544 2,158
Taxes accrued 6,856 (9,959) (21,120)
Energy cost recovery, retail 16,907 (56,128) 45,509
Other (14,235) (21,110) 10,629
---------------------------------------------------------------------------------------------
Net cash provided from operating activities 703,900 813,971 769,177
---------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (536,785) (435,843) (367,463)
Sale of property - - 43,556
Other (26,632) (741) (13,379)
---------------------------------------------------------------------------------------------
Net cash used for investing activities (563,417) (436,584) (337,286)
---------------------------------------------------------------------------------------------
Financing Activities:
Proceeds:
Preferred stock - 158,000 150,000
First mortgage bonds 150,000 860,000 745,000
Other long-term debt 208,720 180,314 48,382
Retirements:
Preferred stock - (207,000) (145,000)
First mortgage bonds (20,387) (699,788) (931,797)
Other long-term debt (305,380) (181,329) (54,223)
Interim obligations, net 139,882 (156,917) 120,917
Payment of preferred stock dividends (25,431) (32,099) (35,704)
Payment of common stock dividends (268,000) (252,900) (273,300)
Miscellaneous (8,444) (56,064) (53,697)
---------------------------------------------------------------------------------------------
Net cash used for financing activities (129,040) (387,783) (429,422)
---------------------------------------------------------------------------------------------
Net Change in Cash 11,443 (10,396) 2,469
Cash at Beginning of Year 3,233 13,629 11,160
---------------------------------------------------------------------------------------------
Cash at End of Year $ 14,676 $ 3,233 $ 13,629
=============================================================================================
Supplemental Cash Flow Information:
Cash paid during the year for --
Interest (net of amount capitalized) $ 183,445 $ 176,805 $ 219,263
Income taxes 231,831 175,591 197,693
---------------------------------------------------------------------------------------------
( ) Denotes use of cash.
The accompanying notes are an integral part of these statements.
II-61
BALANCE SHEETS
At December 31, 1994 and 1993
Alabama Power Company 1994 Annual Report
===============================================================================================
ASSETS 1994 1993
-----------------------------------------------------------------------------------------------
(in thousands)
Utility Plant:
Plant in service, at original cost (Note 1) $10,052,772 $9,757,141
Less accumulated provision for depreciation 3,598,604 3,384,156
-----------------------------------------------------------------------------------------------
6,454,168 6,372,985
Nuclear fuel, at amortized cost 101,630 93,551
Construction work in progress 317,779 225,786
-----------------------------------------------------------------------------------------------
Total 6,873,577 6,692,322
-----------------------------------------------------------------------------------------------
Other Property and Investments:
Southern Electric Generating Company, at equity (Note 6) 26,985 29,201
Nuclear decommissioning trusts (Note 1) 71,014 49,550
Miscellaneous 16,970 20,434
-----------------------------------------------------------------------------------------------
Total 114,969 99,185
-----------------------------------------------------------------------------------------------
Current Assets:
Cash 14,676 3,233
Receivables-
Customer accounts receivable 308,561 312,090
Other accounts and notes receivable 22,547 48,808
Affiliated companies 29,303 40,216
Accumulated provision for uncollectible accounts (2,297) (2,632)
Refundable income taxes 16,011 11,940
Fossil fuel stock, at average cost 119,555 88,481
Materials and supplies, at average cost 184,600 176,728
Prepayments-
Income taxes 19,196 18,980
Other 84,354 60,227
Vacation pay deferred 20,442 22,680
-----------------------------------------------------------------------------------------------
Total 816,948 780,751
-----------------------------------------------------------------------------------------------
Deferred Charges:
Deferred charges related to income taxes (Note 8) 451,886 469,010
Debt expense, being amortized 7,370 7,064
Premium on reacquired debt, being amortized 101,851 102,634
Uranium enrichment decontamination and decommissioning fund (Note 1) 42,996 45,554
Miscellaneous 49,620 52,163
-----------------------------------------------------------------------------------------------
Total 653,723 676,425
-----------------------------------------------------------------------------------------------
Total Assets $8,459,217 $8,248,683
===============================================================================================
The accompanying notes are an integral part of these statements.
II-62
BALANCE SHEETS
At December 31, 1994 and 1993
Alabama Power Company 1994 Annual Report
===============================================================================================
CAPITALIZATION AND LIABILITIES 1994 1993
-----------------------------------------------------------------------------------------------
(in thousands)
Capitalization (See accompanying statements):
Common stock equity $2,614,405 $2,526,348
Preferred stock 440,400 440,400
Long-term debt 2,455,013 2,362,852
-----------------------------------------------------------------------------------------------
Total 5,509,818 5,329,600
-----------------------------------------------------------------------------------------------
Current Liabilities:
Long-term debt due within one year (Note 10) 796 58,998
Notes payable to banks - 40,000
Commercial paper 179,882 -
Accounts payable-
Affiliated companies 60,334 62,507
Other 258,657 272,491
Customer deposits 30,245 31,198
Taxes accrued-
Federal and state income 6,848 25,730
Other 15,589 14,414
Interest accrued 52,516 52,809
Vacation pay accrued 20,442 22,680
Miscellaneous 57,047 50,426
-----------------------------------------------------------------------------------------------
Total 682,356 631,253
-----------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes (Note 8) 1,181,342 1,165,127
Accumulated deferred investment tax credits 317,018 329,909
Prepaid capacity revenues, net (Note 7) 138,421 143,762
Uranium enrichment decontamination and decommissioning fund (Note 1) 39,413 39,644
Deferred credits related to income taxes (Note 8) 405,256 440,945
Natural disaster reserve 28,750 -
Miscellaneous 156,843 168,443
-----------------------------------------------------------------------------------------------
Total 2,267,043 2,287,830
-----------------------------------------------------------------------------------------------
Commitments and Contingent Matters (Notes 1, 3, 4, 5, 6, 7, and 11)
Total Capitalization and Liabilities $8,459,217 $8,248,683
===============================================================================================
The accompanying notes are an integral part of these statements.
II-63
STATEMENTS OF CAPITALIZATION
At December 31, 1994 and 1993
Alabama Power Company 1994 Annual Report
=================================================================================================
1994 1993 1994 1993
-------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
Common Stock Equity:
Common stock, par value $40 per share --
Authorized -- 6,000,000 shares
Outstanding -- 5,608,955 shares in
1994 and 1993 $ 224,358 $ 224,358
Paid-in capital 1,304,645 1,304,645
Premium on preferred stock 146 146
Retained earnings (Note 12) 1,085,256 997,199
-------------------------------------------------------------------------------------------------
Total common stock equity 2,614,405 2,526,348 47.4 % 47.4 %
-------------------------------------------------------------------------------------------------
Cumulative Preferred Stock:
$1 par value --
Authorized -- 27,500,000 shares
Outstanding -- 12,020,200 shares
$25 stated capital --
6.40% 50,000 50,000
6.80% 38,000 38,000
7.60% 150,000 150,000
Adjustable rate
6.26% - at January 1, 1995 50,000 50,000
$100 stated capital --
Auction rate - at January 1, 1995: 4.59% 50,000 50,000
$100,000 stated capital --
Auction rate - at January 1, 1995: 4.64% 20,000 20,000
$100 par value --
Authorized -- 3,850,000 shares
Outstanding -- 824,000 shares
4.20% to 4.52% 41,400 41,400
4.60% to 4.92% 29,000 29,000
5.96% to 6.88% 12,000 12,000
-------------------------------------------------------------------------------------------------
Total (annual dividend requirement -- $27,421,000) 440,400 440,400 8.0 8.3
-------------------------------------------------------------------------------------------------
Long-Term Debt:
First mortgage bonds --
Maturity Interest Rates
-------- --------------
March 1, 1996 4 1/2% 60,000 60,000
February 1, 1998 5 1/2% 50,000 50,000
August 1, 1999 6 3/8% 170,000 170,000
2000 through 2003 6% to 7% 500,000 500,000
2007 7 1/4% 175,000 175,000
2017 10 5/8% - 15,243
2021 through 2024 7.30% to 9 1/4% 1,044,856 900,000
-------------------------------------------------------------------------------------------------
Total first mortgage bonds 1,999,856 1,870,243
Pollution control obligations 476,140 476,140
Other long-term debt 9,754 106,414
Unamortized debt premium (discount), net (29,941) (30,947)
-------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
requirement -- $183,592,000) 2,455,809 2,421,850
Less amount due within one year (Note 10) 796 58,998
-------------------------------------------------------------------------------------------------
Long-term debt excluding amount due within one year 2,455,013 2,362,852 44.6 44.3
-------------------------------------------------------------------------------------------------
Total Capitalization $5,509,818 $5,329,600 100.0 % 100.0 %
=================================================================================================
The accompanying notes are an integral part of these statements.
II-64
STATEMENTS OF RETAINED EARNINGS
For the Years Ended December 31, 1994, 1993, and 1992
Alabama Power Company 1994 Annual Report
=====================================================================================
1994 1993 1992
-------------------------------------------------------------------------------------
(in thousands)
Balance at Beginning of Year $ 997,199 $ 914,148 $ 857,734
Net income after dividends on preferred stock 356,338 346,494 338,555
Cash dividends on common stock (268,000) (252,900) (273,300)
Preferred stock transactions, net (118) (10,587) (8,732)
Other adjustments to retained earnings (163) 44 (109)
-------------------------------------------------------------------------------------
Balance at End of Year (Note 12) $1,085,256 $ 997,199 $ 914,148
=====================================================================================
The accompanying notes are an integral part of these statements.
II-65
NOTES TO FINANCIAL STATEMENTS
Alabama Power Company 1994 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), and The Southern Development and Investment Group
(SDIG). The operating companies (Alabama Power Company, Georgia Power Company,
Gulf Power Company, Mississippi Power Company, and Savannah Electric and Power
Company) provide electric service in four Southeastern states. Contracts among
the companies -- dealing with jointly-owned generating facilities,
interconnecting transmission lines, and the exchange of electric power -- are
regulated by the Federal Energy Regulatory Commission (FERC) or the Securities
and Exchange Commission (SEC). The system service company provides, at cost,
specialized services upon request to The Southern Company and to the subsidiary
companies. Southern Communications, beginning in mid-1995, will provide digital
wireless communications services -- over the 800-megahertz frequency band -- to
The Southern Company's subsidiaries and also will market these services to the
public within the Southeast. Southern Electric designs, builds, owns and
operates power production facilities and provides a broad range of technical
services to industrial companies and utilities in the United States and a number
of international markets. Southern Nuclear provides services to The Southern
Company's nuclear power plants. SDIG 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 regulated by the FERC and the Alabama Public Service Commission (APSC).
The company follows generally accepted accounting principles and complies with
the accounting policies and practices prescribed by the respective regulatory
commissions.
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:
================================================================
1994 1993
--------------------
(in thousands)
Deferred income taxes $451,886 $469,010
Premium on reacquired debt 101,620 102,216
Department of Energy assessments 42,996 45,554
Vacation pay 20,442 22,680
Work force reduction costs 3,664 5,468
Deferred income tax credits (405,256) (440,945)
Natural disaster reserve (28,750) -
Other, net 45,956 26,824
----------------------------------------------------------------
Total $232,558 $230,807
================================================================
In the event that a portion of the company's operations are 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 to their fair value.
Revenues and Fuel Costs
The company accrues revenues for services rendered but unbilled at the end of
each fiscal period. For additional information concerning unbilled revenues, see
Note 3 under "Retail Rate Adjustment Procedures."
The company has a diversified base of customers. No single customer or
industry comprises 10 percent or more of revenues. In 1994, uncollectible
II-66
NOTES (continued)
Alabama Power Company 1994 Annual Report
accounts continued to average less than 1 percent of revenues.
Fuel costs are expensed as the fuel is used. The company's electric rates
include provisions to adjust billings for fluctuations in fuel and the energy
component of purchased power costs. Revenues are adjusted for differences
between recoverable fuel costs and amounts actually recovered in current rates.
Fuel expense includes the amortization of the cost of nuclear fuel and a
charge, based on nuclear generation, for the permanent disposal of spent nuclear
fuel. Total charges for nuclear fuel included in fuel expense amounted to $65
million in 1994, $62 million in 1993, and $48 million in 1992. The company has a
contract with the U.S. Department of Energy (DOE) that provides for the
permanent disposal of spent nuclear fuel, which was scheduled to begin in 1998.
However, the actual year this service will begin is uncertain. Sufficient
storage capacity currently is available to permit operation into 2012 and 2014
at Plant Farley units 1 and 2, respectively.
Also, the Energy Policy Act of 1992 required the establishment in 1993 of a
Uranium Enrichment Decontamination and Decommissioning Fund, which is to be
funded in part by a special assessment on utilities with nuclear plants. This
assessment will be paid over a 15- year period, which began in 1993. This fund
will be used by the DOE for the decontamination and decommissioning of its
nuclear fuel enrichment facilities. The law provides that utilities will recover
these payments in the same manner as any other fuel expense. The company
estimates its remaining liability at December 31, 1994, under this law to be
approximately $43 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 1994 and 3.3 percent in both 1993 and 1992. 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.
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. Earnings
on the trust fund 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.
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 cost of decommissioning -- both site study
costs and ultimate costs -- at December 31, 1994, 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 $409
Non-radiated structures 75
Other 94
--------------------------------------------------------------
Total $578
==============================================================
(in millions)
Ultimate costs:
Radiated structures $1,258
Non-radiated structures 231
Other 289
--------------------------------------------------------------
Total $1,778
==============================================================
II-67
NOTES (continued)
Alabama Power Company 1994 Annual Report
(in millions)
Amount expensed in 1994 $18
--------------------------------------------------------------
Accumulated provisions:
Balance in external trust funds $ 71
Balance in internal reserves 51
--------------------------------------------------------------
Total $122
==============================================================
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 regulatory requirements, changes in technology, and
changes in costs of labor, materials, and equipment.
Income Taxes
The company provides deferred income taxes for all significant income tax
temporary differences. Investment tax credits utilized are deferred and
amortized to income over the average lives of the related property.
Effective January 1, 1993, the company adopted FASB Statement No. 109,
Accounting for Income Taxes. Statement No. 109 required, among other things,
conversion to the liability method of accounting for accumulated deferred income
taxes. See Note 8 for additional information about Statement No. 109.
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 7.9 percent in 1994, 7.8 percent in 1993, and 7.9 percent in 1992.
AFUDC, net of income tax, as a percent of net income after dividends on
preferred stock was 1.5 percent in both 1994 and 1993 and 1.1 percent in 1992.
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 that the carrying
amount did not approximate fair value at December 31 was as follows:
==============================================================
Long-Term Debt
-------------------------
Carrying Fair
Year Amount Value
------------- ----------
(in millions)
1994 $2,446 $2,323
1993 2,315 2,439
==============================================================
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.
Vacation Pay
The company's employees earn their vacation in one year and take it in the
subsequent year. However, for ratemaking purposes, vacation pay is recognized as
II-68
NOTES (continued)
Alabama Power Company 1994 Annual Report
an allowable expense only when paid. Consistent with this ratemaking treatment,
the company accrues a current liability for earned vacation pay and records a
current regulatory asset representing future recoverability of this cost. The
amount was $20 million and $23 million at December 31, 1994 and 1993,
respectively. In 1995, an estimated 64 percent of the 1994 deferred vacation
cost will be expensed and the balance will be charged to construction and other
accounts.
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, 1994, the accumulated provision amounted to $28.8 million.
Regulatory treatment by the APSC allows the company to accrue $250 thousand per
month until the maximum accumulated provision of $32 million is attained. For
additional information concerning the Natural Disaster Reserve, see Note 3 under
"Retail Rate Adjustment Procedures."
2. RETIREMENT BENEFITS
Pension Plan
The company has a defined benefit, trusteed, non-contributory pension plan that
covers substantially all regular employees. Benefits are based on the greater of
amounts resulting from two different formulas: years of service and final
average pay or years of service and a flat-dollar benefit. The company uses the
"entry age normal method with a frozen initial liability" actuarial method for
funding purposes, subject to limitations under federal income tax regulations.
Amounts funded to the pension 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. 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.
Effective January 1, 1993, the company adopted FASB Statement No. 106,
Employers' Accounting for Postretirement Benefits Other Than Pensions, on a
prospective basis. Statement No. 106 requires that medical care and life
insurance benefits for retired employees be accounted for on an accrual basis
using a specified actuarial method, "benefit/years-of-service." Because the
adoption of Statement No. 106 was reflected in rates, it did not have a material
impact on net income.
Prior to 1993, the company recognized these benefit costs on an accrual
basis using the "aggregate cost" actuarial method, which spreads the expected
cost of such benefits over the remaining periods of employees' service as a
level percentage of payroll costs. The total costs of such benefits recognized
by the company in 1992 were $15.2 million.
Funded Status and Cost of Benefits
Shown in the following tables are actuarial results and assumptions for pension
and postretirement medical and life insurance benefits as computed under the
requirements of Statement Nos. 87 and 106, respectively. The funded status of
the plans at December 31 was as follows:
============================================================
Pension
------------------
1994 1993
------------------
(in millions)
Actuarial present value of
benefit obligations:
Vested benefits $ 522 $ 523
Non-vested benefits 18 20
------------------------------------------------------------
Accumulated benefit obligation 540 543
Additional amounts related to
projected salary increases 174 153
------------------------------------------------------------
Projected benefit obligation 714 696
Less:
Fair value of plan assets 1,059 1,121
Unrecognized net gain (251) (349)
Unrecognized prior service cost 23 25
Unrecognized transition asset (51) (56)
============================================================
Prepaid asset recognized in the
Balance Sheets $ 66 $ 45
============================================================
II-69
NOTES (continued)
Alabama Power Company 1994 Annual Report
===========================================================
Postretirement
Medical
-------------------
1994 1993
-------------------
(in millions)
Actuarial present value of
benefit obligation:
Retirees and dependents $ 69 $ 67
Employees eligible to retire 22 21
Other employees 90 95
-----------------------------------------------------------
Accumulated benefit obligation 181 183
Less:
Fair value of plan assets 56 39
Unrecognized net loss 6 18
Unrecognized transition
obligation 96 102
-----------------------------------------------------------
Accrued liability recognized
in the Balance Sheets $ 23 $ 24
===========================================================
===========================================================
Postretirement
Life
------------------
1994 1993
------------------
(in millions)
Actuarial present value of
benefit obligation:
Retirees and dependents $ 27 $ 27
Other employees 29 29
-----------------------------------------------------------
Accumulated benefit obligation 56 56
Less:
Fair value of plan assets 5 1
Unrecognized net gain (6) (4)
Unrecognized transition
obligation 24 26
-----------------------------------------------------------
Accrued liability recognized
in the Balance Sheets $ 33 $ 33
===========================================================
The weighted average rates assumed in the actuarial calculations were:
===========================================================
1994 1993 1992
----------------------------
Discount 8.0% 7.5% 8.0%
Annual salary increase 5.5 5.0 6.0
Long-term return on
plan assets 8.5 8.5 8.5
===========================================================
An additional assumption used in measuring the accumulated postretirement
medical benefit obligation was a weighted average medical care cost trend rate
of 10.5 percent for 1994, decreasing gradually to 6.0 percent through the year
2000 and remaining at that level thereafter. An annual increase in the assumed
medical care cost trend rate of 1.0 percent would increase the accumulated
medical benefit obligation as of December 31, 1994, by $33 million and the
aggregate of the service and interest cost components of the net retiree medical
cost by $4 million.
Components of the plans' net income are shown below:
==================================================================
Pension
------------------------------------------------------------------
1994 1993 1992
-----------------------------
(in millions)
Benefits earned during
the year $ 20.8 $ 20.6 $ 20.6
Interest cost on projected
benefit obligation 51.2 50.4 48.2
Actual (return) loss on plan
assets 23.5 (146.3) (45.8)
Net amortization and deferral (116.2) 63.3 (29.3)
------------------------------------------------------------------
Net pension cost (income) $ (20.7)$ (12.0) $ (6.3)
==================================================================
Of the above net pension amounts, $(15.7) million in 1994, $(8.9)
million in 1993, and $(5.1) million in 1992 were recorded in operating expenses,
and the remainder was recorded in construction and other accounts.
============================================================
Postretirement
Medical
------------------
1994 1993
------------------
(in millions)
Benefits earned during the year $ 6 $ 5
Interest cost on accumulated
benefit obligation 14 12
Amortization of transition
obligation 5 5
Actual (return) loss on plan
assets 1 (5)
Net amortization and deferral (4) 2
------------------------------------------------------------
Net postretirement cost $22 $19
============================================================
II-70
NOTES (continued)
Alabama Power Company 1994 Annual Report
=============================================================
Postretirement
Life
------------------
1994 1993
------------------
(in millions)
Benefits earned during the year $2 $2
Interest cost on accumulated
benefit obligation 4 4
Amortization of transition
obligation 1 1
-------------------------------------------------------------
Net postretirement cost $7 $7
=============================================================
Of the above net postretirement medical and life insurance costs recorded in
1994 and 1993, $23 million and $22 million, respectively, 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 $8.2 million, $16.1 million and $13.4
million for the years 1994, 1993 and 1992, respectively. A portion of the cost
of these programs was deferred and is being amortized in accordance with
regulatory treatment. The unamortized balance of these costs was $3.7 million at
December 31, 1994.
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 last rate adjustment
was effective in January 1992. 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 February 1993, the APSC ordered - at the company's request - a moratorium
on rate increases for the first two quarters of 1993, which facilitated the
transition of an accounting change. This accounting change permitted the accrual
of estimated operation and maintenance expenses related to nuclear refueling
outages during the period between outages rather than at the time the expenses
are incurred.
Also, in 1994, the APSC issued an order - at the company's request -
allowing the company to establish a natural disaster reserve not to exceed $32
million and to change the estimating procedure for unbilled kilowatt-hours and
associated revenues for service rendered but unbilled at the end of each month.
This change in estimate resulted in an increase in unbilled revenues for
September 1994 of $28 million, which offset the initial accrual for the natural
disaster reserve for the same amount. Additional monthly accruals of $250
thousand will be made until the reserve maximum is attained. In addition, a
moratorium on rate increases through the third quarter of 1995 was approved.
The ratemaking procedures will remain in effect until the APSC votes to
modify or discontinue them.
Heat Pump Financing Suit
In September 1990, two customers of the company filed a civil complaint in the
Circuit Court of Shelby County, Alabama, against the company seeking to
represent all persons who, prior to June 23, 1989, entered into agreements with
the company for the financing of heat pumps and other merchandise purchased from
vendors other than the company. The plaintiffs contended that the company was
required to obtain a license under the Alabama Consumer Finance Act to engage in
the business of making consumer loans. The plaintiffs were seeking an order
declaring these agreements null and void and requiring the company to refund all
payments -- principal and interest -- made under these agreements. The aggregate
amount under these agreements, together with interest paid, currently is
estimated to be $40 million.
In June 1993, the court ordered the company to refund or forfeit interest of
approximately $10 million because of the company's failure to obtain such
license. However, the court's order did not require any refund or forfeiture
with respect to any principal payments under the agreements at issue. The
company has appealed the court's order to the Supreme Court of Alabama.
The final outcome of this matter cannot now be determined; however, in
management's opinion, the final outcome will not have a material effect on the
II-71
NOTES (continued)
Alabama Power Company 1994 Annual Report
company's financial statements.
FERC Reviews Equity Returns
In May 1991, the FERC ordered that hearings be conducted concerning the
reasonableness of the Southern electric system's wholesale rate schedules and
contracts that have a return on common equity of 13.75 percent or greater. The
contracts that could be affected by the hearings include substantially all of
the transmission, unit power, long-term power and other similar contracts. Any
changes in the rate of return on common equity that may 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 is scheduled to continue
until January 1996.
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 $34
million at December 31, 1994. Although the final outcome of this matter cannot
now be determined; in management's opinion, the final outcome will not have a
material effect on the company's financial statements.
4. CAPITAL BUDGET
The company's capital expenditures are currently estimated to total $604 million
in 1995, $500 million in 1996, and $502 million in 1997. The estimates include
AFUDC of $10 million in 1995 and $9 million in both 1996 and 1997. The
estimates for property additions for the three-year period includes $42.5
million committed to meeting the requirements of the Clean Air Act. The capital
budget is subject to periodic review and revision, and actual capital cost
incurred may vary from the above estimates because of numerous factors. These
factors include changes in business conditions; revised load growth projections;
changes in environmental regulations; changes in the existing nuclear plant to
meet new regulatory requirements; increasing costs of labor, equipment, and
materials; and cost of capital. At December 31, 1994, significant purchase
commitments were outstanding in connection with the construction program. The
company does not have any new baseload generating plants under construction.
However, the construction of combustion turbine peaking units of approximately
720 megawatts is planned to be completed by 1996. In addition, significant
construction will continue related to transmission and distribution facilities
and the upgrading and extension of the useful lives of generating plants.
5. FINANCING, INVESTMENT, AND
COMMITMENTS
General
To the extent possible, the company's construction program is expected to be
financed primarily from internal sources. Short-term debt will be utilized 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.
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
II-72
NOTES (continued)
Alabama Power Company 1994 Annual Report
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, 1997. To
provide liquidity support for commercial paper programs, the company and Georgia
Power Company have exclusive right to $135 million and $165 million,
respectively, of the available credit. The companies have the option of
converting the short-term borrowings into term loans, payable in 12 equal
quarterly installments, with the first installment due at the end of the first
calendar quarter after the applicable termination date or at an earlier date at
the companies' option. In addition, these agreements provide for payment of
commitment fees based on the unused portions of the commitments or the
maintenance of compensating balances with the banks.
Additionally, the company maintains committed lines of credit in the amount
of $349 million which expire at various times during 1995 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, 1994, the company had regulatory approval to have
outstanding up to $530 million of short-term borrowings.
Assets Subject to Lien
The company's mortgage, as amended and supplemented, securing the first mortgage
bonds issued by the company, constitutes a direct
lien on substantially all of the company's fixed property and franchises.
Fuel Commitments
To supply a portion of the fuel requirements of its generating plants, the
company has entered into various long-term commitments for the procurement of
fossil and nuclear fuel. In most cases, these contracts contain provisions for
price escalations, minimum purchase levels and other financial commitments.
Total estimated long-term obligations through year 2013 were approximately $9.4
billion at December 31, 1994. Additional commitments for coal and for nuclear
fuel will be required in the future to supply the company's fuel needs.
Operating Leases
The company has entered into coal rail car rental agreements with various terms
and expiration dates. At December 31, 1994, estimated minimum rental commitments
for noncancellable operating leases were as follows:
============================================================
Year Amounts
---- ---------------
(in millions)
1995 $ 0.5
1996 2.8
1997 2.8
1998 2.8
1999 2.8
2000 and thereafter 59.5
------------------------------------------------------------
Total minimum payments $71.2
============================================================
6. FACILITY SALES AND JOINT OWNERSHIP
AGREEMENTS
The company and Georgia Power Company own equally all of the outstanding capital
stock of Southern Electric Generating Company (SEGCO), which owns electric
generating units with a total rated capacity of 1,019,680 kilowatts, together
with associated transmission facilities. The capacity of these units is sold
equally to the company and Georgia Power Company under a contract 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 $74
million in 1994, $86 million in 1993 and $73 million in 1992, and is included in
"Purchased power from affiliates" in the Statements of Income.
II-73
NOTES (continued)
Alabama Power Company 1994 Annual Report
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, 1994, the capitalization of SEGCO consisted of $54 million
of equity and $78 million of long-term debt on which the annual interest
requirement is $5.1 million. SEGCO paid dividends totaling $11.6 million in
1994, $11.3 million in 1993, and $12.0 million in 1992, of which one-half of
each was paid to the company. SEGCO's net income was $7.2 million, $8.3 million,
and $9.3 million for 1994, 1993 and 1992, respectively.
The company's percentage ownership and investment in jointly-owned
generating plants at December 31, 1994, 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 $ 89 $ 39
Plant Miller
Units 1 and 2 $708 $264
----------------------------------------------------------------
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)
1994 $152 $ 7 $159
1993 144 15 159
1992 177 9 186
================================================================
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,
approximately 1,200 megawatts of capacity, a slight increase over 1994, is
scheduled to be sold during 1995 and 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
II-74
NOTES (continued)
Alabama Power Company 1994 Annual Report
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,
1994, $146 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, 1994, the tax-related regulatory assets and liabilities were
$452 million and $405 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:
=================================================================
1994 1993 1992
-------------------------------
(in thousands)
Total provision for income taxes:
Federal --
Currently payable $219,494 $149,680 $152,481
Deferred --
current year (48,153) 9,636 27,760
reversal of prior years 15,932 19,653 (7,827)
Deferred investment tax
credits (1) (2,106) -
-----------------------------------------------------------------
187,272 176,863 172,414
-----------------------------------------------------------------
State --
Currently payable 20,565 14,297 16,983
Deferred --
current year (4,067) 1,898 6,387
reversal of prior years 3,676 3,913 (2,806)
-----------------------------------------------------------------
20,174 20,108 20,564
-----------------------------------------------------------------
Total 207,446 196,971 192,978
Less income taxes credited
to other income (16,834) (10,239) (8,947)
-----------------------------------------------------------------
Federal and state income
taxes charged to operations $224,280 $207,210 $201,925
=================================================================
II-75
NOTES (continued)
Alabama Power Company 1994 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:
===============================================================
1994 1993
--------------------
(in millions)
Deferred tax liabilities:
Accelerated depreciation $ 734 $ 697
Property basis differences 513 536
Premium on reacquired debt 38 38
Fuel clause underrecovered 4 11
Other 26 17
---------------------------------------------------------------
Total 1,315 1,299
---------------------------------------------------------------
Deferred tax assets:
Capacity prepayments 36 44
Other deferred costs 27 8
Postretirement benefits 24 15
Accrued nuclear outage costs 7 7
Unbilled revenue 13 7
Other 44 39
---------------------------------------------------------------
Total 151 120
---------------------------------------------------------------
Net deferred tax liabilities 1,164 1,179
Portion included in current assets
(liabilities), net 17 (14)
---------------------------------------------------------------
Accumulated deferred income taxes
in the Balance Sheets $1,181 $1,165
===============================================================
Deferred investment tax credits are amortized over the life of the related
property with such amortization normally applied as a credit to reduce
depreciation in the Statements of Income. Credits amortized in this manner
amounted to $13 million in 1994 and 1993 and $18 million in 1992. At December
31, 1994, 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:
==============================================================
1994 1993 1992
--------------------------
Federal statutory rate 35.0% 35.0% 34.0%
State income tax,
net of federal deduction 2.2 2.3 2.4
Non-deductible book
depreciation 1.6 1.6 1.6
Differences in prior years'
deferred and current tax rates (2.9) (1.6) (1.9)
Other (0.7) (2.9) (2.0)
--------------------------------------------------------------
Effective income tax rate 35.2% 34.4% 34.1%
==============================================================
The Southern Company and its subsidiaries file a consolidated federal income tax
return. Under a joint consolidated income tax agreement, each company's current
and deferred tax expense is computed on a stand-alone basis, and consolidated
tax savings are allocated to each company based on its ratio of taxable income
to total consolidated taxable income.
9. OTHER LONG-TERM DEBT
Details of other long-term debt at December 31 are as follows:
==============================================================
1994 1993
--------------------------
(in thousands)
Obligations incurred in
connection with the
sale of tax-exempt
pollution control
revenue bonds by
public authorities-
2003-2013--6% to
9.375% $ 1,000 $ 27,050
2014-2024--3.05%
to 10.875% 475,140 449,090
--------------------------------------------------------------
476,140 476,140
--------------------------------------------------------------
Capitalized lease obligations:
Nuclear fuel - 95,943
Office buildings 7,312 7,710
Street light 2,442 2,761
--------------------------------------------------------------
9,754 106,414
--------------------------------------------------------------
Total $485,894 $582,554
==============================================================
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 1994 Annual Report
The company has capitalized certain office building leases and a street light
lease. Monthly principal payments plus interest are required, and at December
31, 1994, the interest rate was 9.5 percent for office buildings and 13.0
percent for street lights. 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 $6.2 million and $94.7 million at December 31, 1994 and 1993, respectively.
The estimated aggregate annual maturities of other long-term debt through 1999
are as follows: $0.8 million in 1995, $0.9 million in 1996, $1.0 million in
1997, $1.0 million in 1998 and $1.2 million in 1999.
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:
=================================================================
1994 1993
------------------------
(in thousands)
Bond improvement fund
requirements $20,047 $20,135
Less:
Portion to be satisfied by
certifying property additions 20,047 -
-----------------------------------------------------------------
Cash sinking fund requirements - $20,135
Other long-term debt maturities
(Note 9) 796 38,863
-----------------------------------------------------------------
Total $ 796 $58,998
=================================================================
The annual first mortgage bond improvement fund requirement is one
percent of the aggregate principal amount of bonds of each series authenticated,
so long as a portion of that series is outstanding, and may be satisfied by the
deposit of cash and/or reacquired bonds, the certification of unfunded property
additions or a combination thereof. The 1995 requirement of $20.0 million was
satisfied by certification of property additions. In addition, maturing in 1995
are other long-term debt of $796 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 $12 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 1994 Annual Report
that policy. The maximum annual assessments per incident under current policies
for the company would be $27 million for excess property damage and $10 million
for replacement power.
For all on-site property damage insurance policies for commercial nuclear
power plants, the NRC requires that the proceeds of such policies issued or
renewed on or after April 2, 1991, shall be dedicated first for the sole purpose
of placing the reactor in a safe and stable condition after an accident. Any
remaining proceeds are to be applied next toward the costs of decontamination
and debris removal operations ordered by the NRC, and then, any further
remaining proceeds are to be paid either to the company or to its bond trustees
as may be appropriate under applicable trust indentures.
The company participates in an insurance program for nuclear workers that
provides coverage for worker tort claims filed for bodily injury caused at
commercial nuclear power plants. In the event that claims for this insurance
exceed the accumulated reserve funds, the company could be subject to a maximum
total assessment of $6.4 million.
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, 1994, $807 million of retained earnings was
restricted against the payment of cash dividends on common stock under terms of
the mortgage indenture. Supplemental indentures in connection with future first
mortgage bond issues may contain more stringent common stock dividend
restrictions than those currently in effect.
13. QUARTERLY FINANCIAL INFORMATION
(Unaudited)
Summarized quarterly financial data for 1994 and 1993 are as follows:
==================================================================
Net Income
After
Dividends
Quarter Operating Operating on Preferred
Ended Revenues Income Stock
------------------- --------- --------- --------------
(in thousands)
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
March 1993 $635,559 $124,356 $ 57,856
June 1993 733,589 159,023 91,448
September 1993 919,934 205,151 150,818
December 1993 718,527 106,582 46,372
==================================================================
The company's business is influenced by seasonal weather conditions.
II-78
SELECTED FINANCIAL AND OPERATING DATA
Alabama Power Company 1994 Annual Report
=====================================================================================================
1994 1993 1992
-----------------------------------------------------------------------------------------------------
Operating Revenues (in thousands) $2,935,142 $3,007,609 $2,846,840
Net Income after Dividends
on Preferred Stock (in thousands) $356,338 $346,494 $338,555
Cash Dividends on Common Stock (in thousands) $268,000 $252,900 $273,300
Return on Average Common Equity (percent) 13.86 13.94 14.02
Total Assets (in thousands) $8,459,217 $8,248,683 $6,593,618
Gross Property Additions (in thousands) $536,785 $435,843 $367,463
-----------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $2,614,405 $2,526,348 $2,443,493
Preferred stock 440,400 440,400 489,400
Preferred stock subject to mandatory redemption - - -
Long-term debt 2,455,013 2,362,852 2,202,473
-----------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $5,509,818 $5,329,600 $5,135,366
=====================================================================================================
Capitalization Ratios (percent):
Common stock equity 47.4 47.4 47.6
Preferred stock 8.0 8.3 9.5
Long-term debt 44.6 44.3 42.9
-----------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0 100.0
=====================================================================================================
First Mortgage Bonds (in thousands):
Issued 150,000 860,000 745,000
Retired 20,387 699,788 931,797
Preferred Stock (in thousands):
Issued - 158,000 150,000
Retired - 207,000 145,000
-----------------------------------------------------------------------------------------------------
Security Ratings:
First Mortgage Bonds -
Moody's A1 A1 A1
Standard and Poor's A A A
Duff & Phelps A+ A+ A
Preferred Stock -
Moody's a2 a2 a2
Standard and Poor's A- A- A-
Duff & Phelps A- A- A-
-----------------------------------------------------------------------------------------------------
Customers (year-end):
Residential 1,042,974 1,027,130 1,012,294
Commercial 162,239 157,337 152,530
Industrial 5,341 5,391 5,434
Other 716 713 704
-----------------------------------------------------------------------------------------------------
Total 1,211,270 1,190,571 1,170,962
=====================================================================================================
Employees (year-end) 7,996 8,009 8,116
II-79
SELECTED FINANCIAL AND OPERATING DATA
Alabama Power Company 1994 Annual Report
=====================================================================================================
1991 1990 1989
-----------------------------------------------------------------------------------------------------
Operating Revenues (in thousands) $2,846,794 $2,722,424 $2,629,354
Net Income after Dividends
on Preferred Stock (in thousands) $339,666 $312,803 $311,146
Cash Dividends on Common Stock (in thousands) $232,900 $220,800 $217,300
Return on Average Common Equity (percent) 14.55 14.00 14.53
Total Assets (in thousands) $6,549,462 $6,362,293 $6,279,431
Gross Property Additions (in thousands) $397,011 $444,680 $459,199
-----------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $2,387,198 $2,280,590 $2,188,811
Preferred stock 484,400 484,400 484,400
Preferred stock subject to mandatory redemption - 12,500 17,500
Long-term debt 2,382,635 2,397,931 2,435,129
-----------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $5,254,233 $5,175,421 $5,125,840
=====================================================================================================
Capitalization Ratios (percent):
Common stock equity 45.4 44.1 42.7
Preferred stock 9.2 9.6 9.8
Long-term debt 45.4 46.3 47.5
-----------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0 100.0
=====================================================================================================
First Mortgage Bonds (in thousands):
Issued 250,000 - -
Retired 227,695 33,122 75,650
Preferred Stock (in thousands):
Issued - - -
Retired 17,500 5,000 5,000
-----------------------------------------------------------------------------------------------------
Security Ratings:
First Mortgage Bonds -
Moody's A1 A1 A1
Standard and Poor's A A A
Duff & Phelps A A A
Preferred Stock -
Moody's a2 a2 a2
Standard and Poor's A- A- A-
Duff & Phelps A- A- A-
-----------------------------------------------------------------------------------------------------
Customers (year-end):
Residential 997,585 985,566 974,622
Commercial 148,228 144,340 141,265
Industrial 5,496 5,322 5,200
Other 697 690 684
-----------------------------------------------------------------------------------------------------
Total 1,152,006 1,135,918 1,121,771
=====================================================================================================
Employees (year-end) 8,513 9,473 9,698
II-80A
SELECTED FINANCIAL AND OPERATING DATA
Alabama Power Company 1994 Annual Report
=====================================================================================================
1988 1987 1986
-----------------------------------------------------------------------------------------------------
Operating Revenues (in thousands) $2,476,626 $2,574,634 $2,549,574
Net Income after Dividends
on Preferred Stock (in thousands) $283,475 $257,239 $273,456
Cash Dividends on Common Stock (in thousands) $212,700 $201,100 $191,300
Return on Average Common Equity (percent) 14.03 13.56 15.12
Total Assets (in thousands) $6,180,945 $5,912,000 $5,570,653
Gross Property Additions (in thousands) $643,892 $600,589 $553,767
-----------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $2,094,815 $1,946,747 $1,847,608
Preferred stock 484,400 384,400 384,400
Preferred stock subject to mandatory redemption 22,500 27,500 30,000
Long-term debt 2,496,492 2,386,258 2,210,108
-----------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $5,098,207 $4,744,905 $4,472,116
=====================================================================================================
Capitalization Ratios (percent):
Common stock equity 41.1 41.0 41.3
Preferred stock 9.9 8.7 9.3
Long-term debt 49.0 50.3 49.4
-----------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0 100.0
=====================================================================================================
First Mortgage Bonds (in thousands):
Issued 150,000 200,000 125,000
Retired 42,445 108,082 405,765
Preferred Stock (in thousands):
Issued 100,000 - -
Retired 2,500 5,000 42,224
-----------------------------------------------------------------------------------------------------
Security Ratings:
First Mortgage Bonds -
Moody's A1 A1 A1
Standard and Poor's A A A
Duff & Phelps 6 6 6
Preferred Stock -
Moody's a2 a2 a2
Standard and Poor's A- A- A-
Duff & Phelps 7 7 7
-----------------------------------------------------------------------------------------------------
Customers (year-end):
Residential 964,581 950,101 934,798
Commercial 137,955 134,533 130,540
Industrial 5,120 4,955 4,725
Other 678 713 697
-----------------------------------------------------------------------------------------------------
Total 1,108,334 1,090,302 1,070,760
=====================================================================================================
Employees (year-end) 10,302 10,457 10,367
II-80B
SELECTED FINANCIAL AND OPERATING DATA
Alabama Power Company 1994 Annual Report
=========================================================================================
1985 1984
-----------------------------------------------------------------------------------------
Operating Revenues (in thousands) $2,518,699 $2,236,560
Net Income after Dividends
on Preferred Stock (in thousands) $264,562 $233,252
Cash Dividends on Common Stock (in thousands) $185,700 $161,900
Return on Average Common Equity (percent) 15.41 14.74
Total Assets (in thousands) $5,722,263 $5,496,197
Gross Property Additions (in thousands) $568,073 $575,173
-----------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $1,770,156 $1,664,295
Preferred stock 384,400 424,400
Preferred stock subject to mandatory redemption 35,000 37,224
Long-term debt 2,349,373 2,402,713
-----------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $4,538,929 $4,528,632
=========================================================================================
Capitalization Ratios (percent):
Common stock equity 39.0 36.7
Preferred stock 9.3 10.2
Long-term debt 51.7 53.1
-----------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0
=========================================================================================
First Mortgage Bonds (in thousands):
Issued - -
Retired 39,460 21,250
Preferred Stock (in thousands):
Issued - -
Retired - 810
-----------------------------------------------------------------------------------------
Security Ratings:
First Mortgage Bonds -
Moody's A1 A2
Standard and Poor's A A-
Duff & Phelps 6 7
Preferred Stock -
Moody's a2 a3
Standard and Poor's A- BBB+
Duff & Phelps 7 8
-----------------------------------------------------------------------------------------
Customers (year-end):
Residential 918,777 905,239
Commercial 126,644 123,561
Industrial 4,619 4,467
Other 755 759
-----------------------------------------------------------------------------------------
Total 1,050,795 1,034,026
=========================================================================================
Employees (year-end) 10,212 10,144
II-80C
SELECTED FINANCIAL AND OPERATING DATA (continued)
Alabama Power Company 1994 Annual Report
=====================================================================================================
1994 1993 1992
-----------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $913,146 $947,277 $845,660
Commercial 647,202 634,895 589,816
Industrial 803,587 832,938 800,311
Other 13,515 13,344 12,734
-----------------------------------------------------------------------------------------------------
Total retail 2,377,450 2,428,454 2,248,521
Sales for resale - non-affiliates 354,760 364,105 407,791
Sales for resale - affiliates 164,762 181,975 158,088
-----------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 2,896,972 2,974,534 2,814,400
Other revenues 38,170 33,075 32,440
-----------------------------------------------------------------------------------------------------
Total $2,935,142 $3,007,609 $2,846,840
=====================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 13,183,147 13,185,062 12,069,268
Commercial 9,645,798 9,185,462 8,629,869
Industrial 19,479,364 18,595,237 18,260,274
Other 185,876 181,673 176,798
-----------------------------------------------------------------------------------------------------
Total retail 42,494,185 41,147,434 39,136,209
Sales for resale - non-affiliates 6,775,176 7,143,672 8,382,571
Sales for resale - affiliates 8,432,533 8,081,324 7,210,697
-----------------------------------------------------------------------------------------------------
Total 57,701,894 56,372,430 54,729,477
=====================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 6.93 7.18 7.01
Commercial 6.71 6.91 6.83
Industrial 4.13 4.48 4.38
Total retail 5.59 5.90 5.75
Sales for resale 3.42 3.59 3.63
Total sales 5.02 5.28 5.14
Residential Average Annual Kilowatt-Hour
Use Per Customer 12,746 12,936 12,017
Residential Average Annual Revenue
Per Customer $882.88 $929.36 $842.00
Plant Nameplate Capacity Ratings (Note 1)
(year-end) (megawatts) 10,431 10,431 10,431
Territorial Peak-Hour Demand (megawatts) (Note 2):
Winter 8,217 7,152 7,077
Summer 9,028 9,457 8,801
Annual Load Factor (percent) (Note 2) 62.2 58.6 59.6
Plant Availability (percent):
Fossil-steam 86.9 89.7 88.9
Nuclear 92.5 86.6 80.2
-----------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 62.9 63.9 64.3
Nuclear 21.7 20.1 19.0
Hydro 8.4 6.9 8.5
Oil and gas * * *
Purchased power -
From non-affiliates 1.3 1.1 1.2
From affiliates 5.7 8.0 7.0
-----------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0
=====================================================================================================
Total Fuel Economy Data (Note 1):
BTU per net kilowatt-hour generated 9,961 10,003 10,000
Cost of fuel per million BTU (cents) 157.62 173.66 164.57
Average cost of fuel per net kilowatt-hour generated (cents) 1.57 1.74 1.65
=====================================================================================================
Notes:
(1) Generating capacity and fuel data includes Alabama Power Company's 50% portion of SEGCO.
(2) Includes Southeastern Power Administration allotment.
* Less than one-tenth of one percent.
II-81
SELECTED FINANCIAL AND OPERATING DATA (continued)
Alabama Power Company 1994 Annual Report
=====================================================================================================
1991 1990 1989
-----------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $864,347 $825,645 $781,982
Commercial 582,730 551,634 533,487
Industrial 790,224 777,580 762,274
Other 12,662 12,103 11,743
-----------------------------------------------------------------------------------------------------
Total retail 2,249,963 2,166,962 2,089,486
Sales for resale - non-affiliates 407,912 434,996 409,202
Sales for resale - affiliates 159,375 93,473 104,488
-----------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 2,817,250 2,695,431 2,603,176
Other revenues 29,544 26,993 26,178
-----------------------------------------------------------------------------------------------------
Total $2,846,794 $2,722,424 $2,629,354
=====================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 12,324,898 11,996,794 11,346,736
Commercial 8,526,131 8,201,534 7,915,685
Industrial 17,511,579 17,713,153 17,360,791
Other 174,760 170,420 166,485
-----------------------------------------------------------------------------------------------------
Total retail 38,537,368 38,081,901 36,789,697
Sales for resale - non-affiliates 8,810,442 10,277,060 10,292,329
Sales for resale - affiliates 7,784,285 4,519,275 5,048,743
-----------------------------------------------------------------------------------------------------
Total 55,132,095 52,878,236 52,130,769
=====================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 7.01 6.88 6.89
Commercial 6.83 6.73 6.74
Industrial 4.51 4.39 4.39
Total retail 5.84 5.69 5.68
Sales for resale 3.42 3.57 3.35
Total sales 5.11 5.10 4.99
Residential Average Annual Kilowatt-Hour
Use Per Customer 12,435 12,256 11,717
Residential Average Annual Revenue
Per Customer $872.04 $843.50 $807.50
Plant Nameplate Capacity Ratings (Note 1)
(year-end) (megawatts) 10,539 9,879 9,879
Territorial Peak-Hour Demand (megawatts) (Note 2):
Winter 6,586 6,293 7,264
Summer 8,627 8,878 8,256
Annual Load Factor (percent) (Note 2) 59.9 57.4 59.5
Plant Availability (percent):
Fossil-steam 93.1 92.2 90.7
Nuclear 87.0 86.5 83.1
-----------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 61.5 57.0 54.1
Nuclear 20.8 21.6 21.0
Hydro 8.2 8.7 11.0
Oil and gas * 0.1 0.1
Purchased power -
From non-affiliates 1.6 0.9 1.8
From affiliates 7.9 11.7 12.0
-----------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0
=====================================================================================================
Total Fuel Economy Data (Note 1):
BTU per net kilowatt-hour generated 9,985 10,072 10,061
Cost of fuel per million BTU (cents) 170.49 171.55 172.20
Average cost of fuel per net kilowatt-hour generated (cents) 1.70 1.73 1.73
=====================================================================================================
Notes:
(1) Generating capacity and fuel data includes Alabama Power Company's 50% portion of SEGCO.
(2) Includes Southeastern Power Administration allotment.
* Less than one-tenth of one percent.
II-82A
SELECTED FINANCIAL AND OPERATING DATA (continued)
Alabama Power Company 1994 Annual Report
=====================================================================================================
1988 1987 1986
-----------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $761,805 $759,957 $738,864
Commercial 510,910 501,088 481,676
Industrial 738,755 721,298 705,395
Other 11,255 10,968 10,811
-----------------------------------------------------------------------------------------------------
Total retail 2,022,725 1,993,311 1,936,746
Sales for resale - non-affiliates 355,362 443,880 472,938
Sales for resale - affiliates 76,691 118,746 120,911
-----------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 2,454,778 2,555,937 2,530,595
Other revenues 21,848 18,697 18,979
-----------------------------------------------------------------------------------------------------
Total $2,476,626 $2,574,634 $2,549,574
=====================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 11,332,285 11,149,225 10,606,698
Commercial 7,711,092 7,476,924 7,015,589
Industrial 16,881,342 15,969,075 15,025,806
Other 165,122 159,422 153,282
-----------------------------------------------------------------------------------------------------
Total retail 36,089,841 34,754,646 32,801,375
Sales for resale - non-affiliates 7,905,750 10,523,554 9,064,049
Sales for resale - affiliates 3,551,142 4,963,997 4,456,360
-----------------------------------------------------------------------------------------------------
Total 47,546,733 50,242,197 46,321,784
=====================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 6.72 6.82 6.97
Commercial 6.63 6.70 6.87
Industrial 4.38 4.52 4.69
Total retail 5.60 5.74 5.90
Sales for resale 3.77 3.63 4.39
Total sales 5.16 5.09 5.46
Residential Average Annual Kilowatt-Hour
Use Per Customer 11,839 11,848 11,457
Residential Average Annual Revenue
Per Customer $795.84 $807.61 $798.09
Plant Nameplate Capacity Ratings (Note 1)
(year-end) (megawatts) 9,279 9,337 9,337
Territorial Peak-Hour Demand (megawatts) (Note 2):
Winter 6,377 6,138 6,257
Summer 7,991 7,886 7,892
Annual Load Factor (percent) (Note 2) 59.6 58.3 56.2
Plant Availability (percent):
Fossil-steam 91.3 90.2 88.5
Nuclear 91.9 83.3 83.8
-----------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 53.9 52.5 58.8
Nuclear 26.1 21.7 23.8
Hydro 4.8 6.3 4.2
Oil and gas 0.1 0.2 0.1
Purchased power -
From non-affiliates 0.5 0.2 2.0
From affiliates 14.6 19.1 11.1
-----------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0
=====================================================================================================
Total Fuel Economy Data (Note 1):
BTU per net kilowatt-hour generated 10,137 10,214 10,209
Cost of fuel per million BTU (cents) 168.21 176.72 179.65
Average cost of fuel per net kilowatt-hour generated (cents) 1.71 1.80 1.83
=====================================================================================================
Notes:
(1) Generating capacity and fuel data includes Alabama Power Company's 50% portion of SEGCO.
(2) Includes Southeastern Power Administration allotment.
* Less than one-tenth of one percent.
II-82B
SELECTED FINANCIAL AND OPERATING DATA (continued)
Alabama Power Company 1994 Annual Report
=========================================================================================
1985 1984
-----------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $684,970 $664,286
Commercial 453,651 430,400
Industrial 717,078 692,177
Other 10,129 9,615
-----------------------------------------------------------------------------------------
Total retail 1,865,828 1,796,478
Sales for resale - non-affiliates 539,343 317,890
Sales for resale - affiliates 95,733 108,812
-----------------------------------------------------------------------------------------
Total revenues from sales of electricity 2,500,904 2,223,180
Other revenues 17,795 13,380
-----------------------------------------------------------------------------------------
Total $2,518,699 $2,236,560
=========================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 9,814,814 9,634,285
Commercial 6,593,645 6,270,899
Industrial 15,215,276 15,134,188
Other 146,119 143,785
-----------------------------------------------------------------------------------------
Total retail 31,769,854 31,183,157
Sales for resale - non-affiliates 12,158,464 8,587,936
Sales for resale - affiliates 3,588,338 4,270,493
-----------------------------------------------------------------------------------------
Total 47,516,656 44,041,586
=========================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 6.98 6.90
Commercial 6.88 6.86
Industrial 4.71 4.57
Total retail 5.87 5.76
Sales for resale 4.03 3.32
Total sales 5.26 5.05
Residential Average Annual Kilowatt-Hour
Use Per Customer 10,781 10,755
Residential Average Annual Revenue
Per Customer $752.43 $741.58
Plant Nameplate Capacity Ratings (Note 1)
(year-end) (megawatts) 9,337 8,580
Territorial Peak-Hour Demand (megawatts) (Note 2):
Winter 6,191 5,696
Summer 7,570 6,946
Annual Load Factor (percent) (Note 2) 57.2 59.8
Plant Availability (percent):
Fossil-steam 90.5 91.2
Nuclear 81.0 86.5
-----------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 55.7 51.5
Nuclear 22.4 26.1
Hydro 6.2 11.0
Oil and gas 0.1 *
Purchased power -
From non-affiliates 1.7 0.2
From affiliates 13.9 11.2
-----------------------------------------------------------------------------------------
Total 100.0 100.0
=========================================================================================
Total Fuel Economy Data (Note 1):
BTU per net kilowatt-hour generated 10,229 10,367
Cost of fuel per million BTU (cents) 185.74 179.40
Average cost of fuel per net kilowatt-hour generated (cents) 1.90 1.86
=========================================================================================
Notes:
(1) Generating capacity and fuel data includes Alabama Power Company's 50% portion of SEGCO.
(2) Includes Southeastern Power Administration allotment.
* Less than one-tenth of one percent.
II-82C
STATEMENTS OF INCOME
Alabama Power Company
=======================================================================================================
For the Years Ended December 31, 1994* 1993* 1992*
-------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Operating Revenues:
Revenues $ 2,770,380 $ 2,825,634 $ 2,688,752
Revenues from affiliates 164,762 181,975 158,088
-------------------------------------------------------------------------------------------------------
Total operating revenues 2,935,142 3,007,609 2,846,840
-------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
Fuel 801,948 877,099 794,438
Purchased power from non-affiliates 15,158 15,230 14,242
Purchased power from affiliates 100,888 120,330 107,230
Proceeds from settlement of disputed contracts - (2,568) (641)
Other 458,917 473,383 446,477
Maintenance 262,102 252,506 237,071
Depreciation and amortization 292,420 290,310 280,881
Taxes other than income taxes 183,425 178,997 172,095
Federal and state income taxes 224,280 207,210 201,925
-------------------------------------------------------------------------------------------------------
Total operating expenses 2,339,138 2,412,497 2,253,718
-------------------------------------------------------------------------------------------------------
Operating Income 596,004 595,112 593,122
Other Income (Expense):
Allowance for equity funds used during construction 3,239 3,260 2,071
Income from subsidiary 3,588 4,127 4,635
Charitable foundation (13,500) (3,000) (6,887)
Interest income 16,944 20,775 14,804
Other, net (30,569) (24,420) (11,019)
Income taxes applicable to other income 16,834 10,239 8,947
-------------------------------------------------------------------------------------------------------
Income Before Interest Charges 592,540 606,093 605,673
-------------------------------------------------------------------------------------------------------
Interest Charges:
Interest on long-term debt 178,045 184,861 206,871
Allowance for debt funds used during construction (3,548) (2,992) (2,416)
Interest on interim obligations 5,939 3,760 3,704
Amortization of debt discount, premium, and expense, net 9,623 8,937 4,392
Other interest charges 19,908 35,474 19,381
-------------------------------------------------------------------------------------------------------
Net interest charges 209,967 230,040 231,932
-------------------------------------------------------------------------------------------------------
Net Income 382,573 376,053 373,741
Dividends on Preferred Stock 26,235 29,559 35,186
-------------------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred Stock $ 356,338 $ 346,494 $ 338,555
=======================================================================================================
* Includes the effect of recognizing, beginning in 1987, retail service
rendered but not yet billed to customers.
II-83
STATEMENTS OF INCOME
Alabama Power Company
======================================================================================================================
For the Years Ended December 31, 1991* 1990* 1989* 1988*
----------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Operating Revenues:
Revenues $ 2,687,419 $ 2,628,951 $ 2,524,866 $ 2,399,935
Revenues from affiliates 159,375 93,473 104,488 76,691
----------------------------------------------------------------------------------------------------------------------
Total operating revenues 2,846,794 2,722,424 2,629,354 2,476,626
----------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
Fuel 812,667 756,501 712,453 676,423
Purchased power from non-affiliates 21,080 11,185 28,272 8,407
Purchased power from affiliates 119,602 165,982 163,267 185,390
Proceeds from settlement of disputed contracts (14,819) - - -
Other 435,908 411,559 380,536 400,879
Maintenance 229,114 215,304 202,633 197,225
Depreciation and amortization 271,433 262,817 247,973 225,123
Taxes other than income taxes 169,639 163,567 154,398 148,681
Federal and state income taxes 200,612 185,954 188,507 143,614
----------------------------------------------------------------------------------------------------------------------
Total operating expenses 2,245,236 2,172,869 2,078,039 1,985,742
----------------------------------------------------------------------------------------------------------------------
Operating Income 601,558 549,555 551,315 490,884
Other Income (Expense):
Allowance for equity funds used during construction 2,368 25,487 29,515 39,047
Income from subsidiary 4,576 4,182 3,750 3,302
Charitable foundation (6,500) (17,500) (25,000) -
Interest income 14,356 12,006 10,871 9,914
Other, net (9,926) (8,235) (4,313) (13,694)
Income taxes applicable to other income 7,523 11,081 13,629 8,034
----------------------------------------------------------------------------------------------------------------------
Income Before Interest Charges 613,955 576,576 579,767 537,487
----------------------------------------------------------------------------------------------------------------------
Interest Charges:
Interest on long-term debt 214,107 221,527 230,046 225,522
Allowance for debt funds used during construction (6,903) (23,339) (27,627) (31,830)
Interest on interim obligations 13,385 10,252 9,098 5,714
Amortization of debt discount, premium, and expense, net 2,634 3,706 4,469 4,411
Other interest charges 14,927 13,115 13,112 13,715
----------------------------------------------------------------------------------------------------------------------
Net interest charges 238,150 225,261 229,098 217,532
----------------------------------------------------------------------------------------------------------------------
Net Income 375,805 351,315 350,669 319,955
Dividends on Preferred Stock 36,139 38,512 39,523 36,480
----------------------------------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred Stock $ 339,666 $ 312,803 $ 311,146 $ 283,475
======================================================================================================================
* Includes the effect of recognizing, beginning in 1987, retail service
rendered but not yet billed to customers.
II-84A
STATEMENTS OF INCOME
Alabama Power Company
======================================================================================================================
For the Years Ended December 31, 1987* 1986 1985 1984
----------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Operating Revenues:
Revenues $ 2,455,888 $ 2,428,663 $ 2,422,966 $ 2,127,748
Revenues from affiliates 118,746 120,911 95,733 108,812
----------------------------------------------------------------------------------------------------------------------
Total operating revenues 2,574,634 2,549,574 2,518,699 2,236,560
----------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
Fuel 696,763 738,367 743,463 657,183
Purchased power from non-affiliates 6,703 23,889 25,990 4,592
Purchased power from affiliates 257,052 156,091 187,041 156,180
Proceeds from settlement of disputed contracts - - - -
Other 410,575 350,671 308,437 287,647
Maintenance 199,617 203,972 210,143 182,957
Depreciation and amortization 212,072 201,803 183,779 174,514
Taxes other than income taxes 141,422 135,248 128,648 122,928
Federal and state income taxes 190,575 255,400 248,774 224,726
----------------------------------------------------------------------------------------------------------------------
Total operating expenses 2,114,779 2,065,441 2,036,275 1,810,727
----------------------------------------------------------------------------------------------------------------------
Operating Income 459,855 484,133 482,424 425,833
Other Income (Expense):
Allowance for equity funds used during construction 27,663 27,455 32,985 45,704
Income from subsidiary 3,440 2,967 3,417 3,181
Charitable foundation - - - -
Interest income 7,044 11,422 20,874 12,432
Other, net (816) (3,738) (4,447) (666)
Income taxes applicable to other income 849 185 (4,941) (3,088)
----------------------------------------------------------------------------------------------------------------------
Income Before Interest Charges 498,035 522,424 530,312 483,396
----------------------------------------------------------------------------------------------------------------------
Interest Charges:
Interest on long-term debt 205,824 226,110 248,073 245,684
Allowance for debt funds used during construction (24,235) (24,334) (29,048) (42,868)
Interest on interim obligations 7,221 1,159 - -
Amortization of debt discount, premium, and expense, net 4,405 3,313 1,145 996
Other interest charges 14,662 8,695 4,234 4,291
----------------------------------------------------------------------------------------------------------------------
Net interest charges 207,877 214,943 224,404 208,103
----------------------------------------------------------------------------------------------------------------------
Net Income 290,158 307,481 305,908 275,293
Dividends on Preferred Stock 32,919 34,025 41,346 42,041
----------------------------------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred Stock $ 257,239 $ 273,456 $ 264,562 $ 233,252
======================================================================================================================
* Includes the effect of recognizing, beginning in 1987, retail service
rendered but not yet billed to customers.
II-84B
STATEMENTS OF CASH FLOWS
Alabama Power Company
============================================================================================================
For the Years Ended December 31, 1994 1993 1992
------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Operating Activities:
Net income $ 382,573 $ 376,053 $ 373,741
Adjustments to reconcile net income to net
cash provided by operating activities --
Depreciation and amortization 359,791 356,499 338,421
Deferred income taxes, net (32,612) 35,100 23,514
Deferred investment tax credits, net (1) (2,106) -
Allowance for equity funds used during construction (3,239) (3,260) (2,071)
Non-cash proceeds from settlement of disputed contracts - - (641)
Other, net 28,656 36,493 (2,657)
Changes in certain current assets and liabilities --
Receivables, net 19,390 19,215 (11,010)
Inventories (38,946) 51,630 12,704
Payables (21,240) 31,544 2,158
Taxes accrued 6,856 (9,959) (21,120)
Energy cost recovery, retail 16,907 (56,128) 45,509
Other (14,235) (21,110) 10,629
-------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities 703,900 813,971 769,177
-------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (536,785) (435,843) (367,463)
Sales of property - - 43,556
Other (26,632) (741) (13,379)
-------------------------------------------------------------------------------------------------------------
Net cash used for investing activities (563,417) (436,584) (337,286)
-------------------------------------------------------------------------------------------------------------
Financing Activities and Capital Contributions:
Proceeds:
Preferred stock - 158,000 150,000
First mortgage bonds 150,000 860,000 745,000
Pollution control bonds - - -
Other long-term debt 208,720 180,314 48,382
Capital contributions from parent company - - -
Prepaid capacity revenues - - -
Retirements:
Preferred stock - (207,000) (145,000)
First mortgage bonds (20,387) (699,788) (931,797)
Pollution control bonds (179,750) (135,315) (335)
Other long-term debt (125,630) (46,014) (53,888)
Interim obligations, net 139,882 (156,917) 120,917
Payment of preferred stock dividends (25,431) (32,099) (35,704)
Payment of common stock dividends (268,000) (252,900) (273,300)
Miscellaneous (8,444) (56,064) (53,697)
-------------------------------------------------------------------------------------------------------------
Net cash provided from (used for) financing activities (129,040) (387,783) (429,422)
-------------------------------------------------------------------------------------------------------------
Net Change in Cash 11,443 (10,396) 2,469
Cash at Beginning of Year 3,233 13,629 11,160
-------------------------------------------------------------------------------------------------------------
Cash at End of Year $ 14,676 $ 3,233 $ 13,629
=============================================================================================================
( ) Denotes use of cash.
II-85
STATEMENTS OF CASH FLOWS
Alabama Power Company
========================================================================================================================
For the Years Ended December 31, 1991 1990 1989 1988
------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Operating Activities:
Net income $ 375,805 $ 351,315 $ 350,669 $ 319,955
Adjustments to reconcile net income to net
cash provided by operating activities --
Depreciation and amortization 337,978 331,858 322,042 296,234
Deferred income taxes, net (5,779) 64,480 31,715 37,952
Deferred investment tax credits, net (1,089) 132 6,917 15,019
Allowance for equity funds used during construction (2,368) (25,487) (29,515) (39,047)
Non-cash proceeds from settlement of disputed contracts (13,750) - - -
Other, net 26,614 19,899 (5,297) 16,106
Changes in certain current assets and liabilities --
Receivables, net 9,178 12,005 (10,436) 8,822
Inventories (17,374) (40,901) 20,408 (23,182)
Payables 28,889 6,597 16,259 (12,957)
Taxes accrued 24,828 (6,167) 1,547 (7,754)
Energy cost recovery, retail (12,304) (42,535) 39,164 -
Other (37,906) 14,144 28,701 (18,658)
------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities 712,722 685,340 772,174 592,490
------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (397,011) (444,680) (459,199) (643,892)
Sales of property - - - -
Other (36,083) 6,935 3,768 23,161
------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities (433,094) (437,745) (455,431) (620,731)
------------------------------------------------------------------------------------------------------------------------
Financing Activities and Capital Contributions:
Proceeds:
Preferred stock - - - 100,000
First mortgage bonds 250,000 - - 150,000
Pollution control bonds - - 53,700 -
Other long-term debt 12,906 54,831 55,176 62,515
Capital contributions from parent company - - - 79,500
Prepaid capacity revenues 52,900 - - -
Retirements:
Preferred stock (17,500) (5,000) (5,000) (2,500)
First mortgage bonds (227,695) (33,122) (75,650) (42,445)
Pollution control bonds (250) (250) (53,950) -
Other long-term debt (48,428) (56,895) (57,316) (56,748)
Interim obligations, net (13,500) 59,500 30,000 (15,000)
Payment of preferred stock dividends (36,829) (38,245) (40,105) (35,362)
Payment of common stock dividends (232,900) (220,800) (217,300) (212,700)
Miscellaneous (17,732) (293) (4,576) (5,581)
------------------------------------------------------------------------------------------------------------------------
Net cash provided from (used for) financing activities (279,028) (240,274) (315,021) 21,679
------------------------------------------------------------------------------------------------------------------------
Net Change in Cash 600 7,321 1,722 (6,562)
Cash at Beginning of Year 10,560 3,239 1,517 8,079
------------------------------------------------------------------------------------------------------------------------
Cash at End of Year $ 11,160 $ 10,560 $ 3,239 $ 1,517
========================================================================================================================
( ) Denotes use of cash.
II-86A
STATEMENTS OF CASH FLOWS
Alabama Power Company
========================================================================================================================
For the Years Ended December 31, 1987 1986 1985 1984
------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Operating Activities:
Net income $ 290,158 $ 307,481 $ 305,908 $ 275,293
Adjustments to reconcile net income to net
cash provided by operating activities --
Depreciation and amortization 270,492 292,569 266,657 266,479
Deferred income taxes, net 107,824 135,364 104,259 85,426
Deferred investment tax credits, net 23,477 19,736 57,096 165,020
Allowance for equity funds used during construction (27,663) (27,455) (32,985) (45,704)
Non-cash proceeds from settlement of disputed contracts - - - -
Other, net 67,445 4,251 (18,971) (4,573)
Changes in certain current assets and liabilities --
Receivables, net (133,468) 15,238 (13,531) (16,403)
Inventories (26,255) (2,040) 29,823 25,159
Payables 39,645 (56,720) 26,360 39,964
Taxes accrued 516 (1,487) (6,325) (8,198)
Energy cost recovery, retail - - - -
Other 4,464 (35,293) 4,358 29,836
------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities 616,635 651,644 722,649 812,299
------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (600,589) (553,767) (568,073) (575,173)
Sales of property - - - -
Other 17,010 10,115 22,028 26,175
------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities (583,579) (543,652) (546,045) (548,998)
------------------------------------------------------------------------------------------------------------------------
Financing Activities and Capital Contributions:
Proceeds:
Preferred stock - - - -
First mortgage bonds 200,000 125,000 - -
Pollution control bonds 432 26,232 115,577 161,134
Other long-term debt 69,786 95,017 12,998 25,654
Capital contributions from parent company 43,000 - 27,000 93,000
Prepaid capacity revenues - 100,000 - -
Retirements:
Preferred stock (5,000) (42,224) - (810)
First mortgage bonds (108,082) (405,765) (39,460) (21,250)
Pollution control bonds - (21,000) - (3,500)
Other long-term debt (32,500) (43,561) (35,023) (128,060)
Interim obligations, net 15,000 - - -
Payment of preferred stock dividends (32,837) (36,014) (41,566) (42,061)
Payment of common stock dividends (201,100) (191,300) (185,700) (161,900)
Miscellaneous (2,581) (38,052) (4,438) (2,727)
------------------------------------------------------------------------------------------------------------------------
Net cash provided from (used for) financing activities (53,882) (431,667) (150,612) (80,520)
------------------------------------------------------------------------------------------------------------------------
Net Change in Cash (20,826) (323,675) 25,992 182,781
Cash at Beginning of Year 28,905 352,580 326,588 143,807
------------------------------------------------------------------------------------------------------------------------
Cash at End of Year $ 8,079 $ 28,905 $ 352,580 $ 326,588
========================================================================================================================
( ) Denotes use of cash.
II-86B
BALANCE SHEETS
Alabama Power Company
===========================================================================================================
At December 31, 1994* 1993* 1992*
-----------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
ASSETS
Electric Plant:
Production-
Fossil $ 3,027,956 $ 2,987,010 $ 2,953,683
Nuclear 1,866,750 1,860,842 1,860,832
Hydro 836,256 819,848 818,363
-----------------------------------------------------------------------------------------------------------
Total production 5,730,962 5,667,700 5,632,878
Transmission 1,087,452 1,051,130 1,013,464
Distribution 2,366,477 2,206,834 2,072,165
General 847,111 810,551 751,652
Construction work in progress 317,745 225,743 164,555
Nuclear fuel, at amortized cost 101,630 93,551 101,128
-----------------------------------------------------------------------------------------------------------
Total electric plant 10,451,377 10,055,509 9,735,842
-----------------------------------------------------------------------------------------------------------
Steam Heat Plant:
Plant in service 20,770 20,926 20,924
Construction work in progress 34 43 33
-----------------------------------------------------------------------------------------------------------
Total steam heat plant 20,804 20,969 20,957
-----------------------------------------------------------------------------------------------------------
Total utility plant 10,472,181 10,076,478 9,756,799
-----------------------------------------------------------------------------------------------------------
Accumulated provision for depreciation:
Electric 3,588,363 3,374,310 3,122,332
Steam heat 10,241 9,846 9,211
-----------------------------------------------------------------------------------------------------------
Total accumulated provision for depreciation 3,598,604 3,384,156 3,131,543
-----------------------------------------------------------------------------------------------------------
Total 6,873,577 6,692,322 6,625,256
Less property-related accumulated deferred income taxes - - 1,170,982
-----------------------------------------------------------------------------------------------------------
Total 6,873,577 6,692,322 5,454,274
-----------------------------------------------------------------------------------------------------------
Other Property and Investments:
Securities received from settlement of disputed contracts - - -
Nuclear decommissioning trusts 71,014 49,550 32,390
Miscellaneous 43,955 49,635 49,892
-----------------------------------------------------------------------------------------------------------
Total 114,969 99,185 82,282
-----------------------------------------------------------------------------------------------------------
Current Assets:
Cash and cash equivalents 14,676 3,233 13,629
Investment securities - - 64,832
Receivables, net 374,125 410,422 344,934
Fossil fuel stock, at average cost 119,555 88,481 134,328
Materials and supplies, at average cost 184,600 176,728 182,511
Prepayments 103,550 79,207 108,254
Vacation pay deferred 20,442 22,680 21,879
-----------------------------------------------------------------------------------------------------------
Total 816,948 780,751 870,367
-----------------------------------------------------------------------------------------------------------
Deferred Charges:
Deferred charges related to income taxes 451,886 469,010 -
Debt expense, being amortized 7,370 7,064 6,118
Premium on reacquired debt, being amortized 101,851 102,634 74,835
Uranium enrichment decontamination and decommissioning fund 42,996 45,554 47,730
Miscellaneous 49,620 52,163 58,012
-----------------------------------------------------------------------------------------------------------
Total 653,723 676,425 186,695
-----------------------------------------------------------------------------------------------------------
Total Assets $ 8,459,217 $ 8,248,683 $ 6,593,618
===========================================================================================================
*Includes the effect of recognizing, beginning in 1987, retail service rendered
but not yet billed to customers.
II-87
BALANCE SHEETS
Alabama Power Company
==========================================================================================================================
At December 31, 1991* 1990* 1989* 1988*
--------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
ASSETS
Electric Plant:
Production-
Fossil $ 2,991,876 $ 2,462,100 $ 2,428,146 $ 1,820,966
Nuclear 1,851,317 1,794,540 1,786,877 1,769,093
Hydro 814,301 809,578 803,901 789,617
--------------------------------------------------------------------------------------------------------------------------
Total production 5,657,494 5,066,218 5,018,924 4,379,676
Transmission 977,239 925,368 882,933 844,003
Distribution 1,947,972 1,815,265 1,692,426 1,587,690
General 713,948 660,217 646,523 613,498
Construction work in progress 148,564 654,055 557,150 1,023,019
Nuclear fuel, at amortized cost 109,259 143,711 147,997 174,130
---------------------------------------------------------------------------------------------------------------------------
Total electric plant 9,554,476 9,264,834 8,945,953 8,622,016
---------------------------------------------------------------------------------------------------------------------------
Steam Heat Plant:
Plant in service 20,214 20,091 20,083 20,076
Construction work in progress 181 74 71 58
--------------------------------------------------------------------------------------------------------------------------
Total steam heat plant 20,395 20,165 20,154 20,134
--------------------------------------------------------------------------------------------------------------------------
Total utility plant 9,574,871 9,284,999 8,966,107 8,642,150
--------------------------------------------------------------------------------------------------------------------------
Accumulated provision for depreciation:
Electric 2,913,385 2,676,957 2,458,747 2,257,696
Steam heat 8,492 7,861 7,154 6,456
--------------------------------------------------------------------------------------------------------------------------
Total accumulated provision for depreciation 2,921,877 2,684,818 2,465,901 2,264,152
--------------------------------------------------------------------------------------------------------------------------
Total 6,652,994 6,600,181 6,500,206 6,377,998
Less property-related accumulated deferred income taxes 1,140,303 1,106,664 1,051,877 1,001,173
--------------------------------------------------------------------------------------------------------------------------
Total 5,512,691 5,493,517 5,448,329 5,376,825
--------------------------------------------------------------------------------------------------------------------------
Other Property and Investments:
Securities received from settlement of disputed contracts 69,550 - - -
Nuclear decommissioning trusts 15,864 - - -
Miscellaneous 48,254 40,604 34,710 29,677
--------------------------------------------------------------------------------------------------------------------------
Total 133,668 40,604 34,710 29,677
--------------------------------------------------------------------------------------------------------------------------
Current Assets:
Cash and cash equivalents 11,160 10,560 3,239 1,517
Investment securities - - - -
Receivables, net 349,599 346,473 355,107 344,671
Fossil fuel stock, at average cost 154,798 144,960 131,942 173,858
Materials and supplies, at average cost 174,745 167,209 139,326 117,818
Prepayments 95,832 50,364 54,613 28,412
Vacation pay deferred 21,691 22,845 22,021 21,871
--------------------------------------------------------------------------------------------------------------------------
Total 807,825 742,411 706,248 688,147
--------------------------------------------------------------------------------------------------------------------------
Deferred Charges:
Deferred charges related to income taxes - - - -
Debt expense, being amortized 5,957 6,083 6,491 6,831
Premium on reacquired debt, being amortized 40,174 26,504 28,778 27,329
Uranium enrichment decontamination and decommissioning fund - - - -
Miscellaneous 49,147 53,174 54,875 52,136
--------------------------------------------------------------------------------------------------------------------------
Total 95,278 85,761 90,144 86,296
--------------------------------------------------------------------------------------------------------------------------
Total Assets $ 6,549,462 $ 6,362,293 $ 6,279,431 $ 6,180,945
==========================================================================================================================
*Includes the effect of recognizing, beginning in 1987, retail service rendered
but not yet billed to customers.
II-88A
BALANCE SHEETS
Alabama Power Company
==========================================================================================================================
At December 31, 1987* 1986 1985 1984
--------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
ASSETS
Electric Plant:
Production-
Fossil $ 1,787,979 $ 1,748,226 $ 1,678,117 $ 1,203,447
Nuclear 1,765,854 1,749,981 1,687,766 1,664,849
Hydro 788,046 784,445 773,682 559,696
--------------------------------------------------------------------------------------------------------------------------
Total production 4,341,879 4,282,652 4,139,565 3,427,992
Transmission 817,065 773,142 699,980 642,968
Distribution 1,481,845 1,384,576 1,295,930 1,221,003
General 535,148 506,228 349,249 300,043
Construction work in progress 750,907 497,491 502,455 972,832
Nuclear fuel, at amortized cost 191,493 205,768 243,468 223,818
--------------------------------------------------------------------------------------------------------------------------
Total electric plant 8,118,337 7,649,857 7,230,647 6,788,656
--------------------------------------------------------------------------------------------------------------------------
Steam Heat Plant:
Plant in service 20,217 19,508 17,056 9,780
Construction work in progress 89 123 64 901
--------------------------------------------------------------------------------------------------------------------------
Total steam heat plant 20,306 19,631 17,120 10,681
--------------------------------------------------------------------------------------------------------------------------
Total utility plant 8,138,643 7,669,488 7,247,767 6,799,337
--------------------------------------------------------------------------------------------------------------------------
Accumulated provision for depreciation:
Electric 2,068,176 1,877,124 1,697,547 1,525,893
Steam heat 5,938 5,261 3,874 3,619
--------------------------------------------------------------------------------------------------------------------------
Total accumulated provision for depreciation 2,074,114 1,882,385 1,701,421 1,529,512
--------------------------------------------------------------------------------------------------------------------------
Total 6,064,529 5,787,103 5,546,346 5,269,825
Less property-related accumulated deferred income taxes 933,932 857,081 758,150 664,591
--------------------------------------------------------------------------------------------------------------------------
Total 5,130,597 4,930,022 4,788,196 4,605,234
--------------------------------------------------------------------------------------------------------------------------
Other Property and Investments:
Securities received from settlement of disputed contracts - - - -
Nuclear decommissioning trusts - - - -
Miscellaneous 31,402 30,735 24,849 22,288
--------------------------------------------------------------------------------------------------------------------------
Total 31,402 30,735 24,849 22,288
--------------------------------------------------------------------------------------------------------------------------
Current Assets:
Cash and cash equivalents 8,079 28,905 352,580 326,588
Investment securities - - - -
Receivables, net 353,493 220,025 235,263 221,732
Fossil fuel stock, at average cost 164,671 152,640 163,899 206,232
Materials and supplies, at average cost 103,823 89,599 76,300 63,790
Prepayments 10,595 12,320 9,741 8,801
Vacation pay deferred 21,317 20,002 18,859 17,599
--------------------------------------------------------------------------------------------------------------------------
Total 661,978 523,491 856,642 844,742
--------------------------------------------------------------------------------------------------------------------------
Deferred Charges:
Deferred charges related to income taxes - - - -
Debt expense, being amortized 6,695 6,308 6,607 6,774
Premium on reacquired debt, being amortized 30,767 34,170 524 109
Uranium enrichment decontamination and decommissioning fund - - - -
Miscellaneous 50,561 45,927 45,445 17,050
--------------------------------------------------------------------------------------------------------------------------
Total 88,023 86,405 52,576 23,933
--------------------------------------------------------------------------------------------------------------------------
Total Assets $ 5,912,000 $ 5,570,653 $ 5,722,263 $ 5,496,197
==========================================================================================================================
*Includes the effect of recognizing, beginning in 1987, retail service rendered
but not yet billed to customers.
II-88B
BALANCE SHEETS
Alabama Power Company
===========================================================================================================
At December 31, 1994* 1993* 1992*
-----------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock $ 224,358 $ 224,358 $ 224,358
Paid-in capital 1,304,645 1,304,645 1,304,645
Premium on preferred stock 146 146 342
Earnings retained in the business 1,085,256 997,199 914,148
-----------------------------------------------------------------------------------------------------------
Total common equity 2,614,405 2,526,348 2,443,493
Preferred stock 440,400 440,400 489,400
Preferred stock subject to mandatory redemption - - -
Long-term debt 2,455,013 2,362,852 2,202,473
-----------------------------------------------------------------------------------------------------------
Total 5,509,818 5,329,600 5,135,366
(excluding amount due within one year)
-----------------------------------------------------------------------------------------------------------
Current Liabilities:
Notes payable to banks - 40,000 71,000
Commercial paper 179,882 - 125,917
Preferred stock due within one year - - -
Long-term debt due within one year 796 58,998 67,379
Accounts payable 318,991 334,998 296,731
Customer deposits 30,245 31,198 31,286
Taxes accrued 22,437 40,144 24,373
Interest accrued 52,516 52,809 41,675
Vacation pay accrued 20,442 22,680 21,879
Miscellaneous 57,047 50,426 93,836
-----------------------------------------------------------------------------------------------------------
Total 682,356 631,253 774,076
-----------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 1,181,342 1,165,127 -
Accumulated deferred investment tax credits 317,018 329,909 344,707
Prepaid capacity revenues, net 138,421 143,762 147,658
Deferred revenues from settlement of disputed contracts - 19,871 46,721
Uranium enrichment decontamination and decommissioning fund 39,413 39,644 44,548
Deferred credits related to income taxes 405,256 440,945 -
Natural disaster reserve 28,750 - -
Miscellaneous 156,843 148,572 100,542
-----------------------------------------------------------------------------------------------------------
Total 2,267,043 2,287,830 684,176
-----------------------------------------------------------------------------------------------------------
Total Capitalization and Liabilities $ 8,459,217 $ 8,248,683 $ 6,593,618
===========================================================================================================
*Includes the effect of recognizing, beginning in 1987, retail service rendered
but not yet billed to customers.
II-89
BALANCE SHEETS
Alabama Power Company
==========================================================================================================================
At December 31, 1991* 1990* 1989* 1988*
--------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock $ 224,358 $ 224,358 $ 224,358 $ 224,358
Paid-in capital 1,304,645 1,304,645 1,304,645 1,304,645
Premium on preferred stock 461 461 461 461
Earnings retained in the business 857,734 751,126 659,347 565,351
--------------------------------------------------------------------------------------------------------------------------
Total common equity 2,387,198 2,280,590 2,188,811 2,094,815
Preferred stock 484,400 484,400 484,400 484,400
Preferred stock subject to mandatory redemption - 12,500 17,500 22,500
Long-term debt 2,382,635 2,397,931 2,435,129 2,496,492
--------------------------------------------------------------------------------------------------------------------------
Total 5,254,233 5,175,421 5,125,840 5,098,207
(excluding amount due within one year)
--------------------------------------------------------------------------------------------------------------------------
Current Liabilities:
Notes payable to banks 76,000 89,500 30,000 -
Commercial paper - - - -
Preferred stock due within one year - 5,000 5,000 5,000
Long-term debt due within one year 85,077 83,989 81,031 96,242
Accounts payable 295,333 271,776 267,645 259,443
Customer deposits 30,165 29,571 28,450 25,964
Taxes accrued 45,493 20,665 26,832 25,285
Interest accrued 49,288 49,820 49,926 50,174
Vacation pay accrued 21,691 22,845 22,021 21,871
Miscellaneous 37,699 64,547 91,022 28,944
--------------------------------------------------------------------------------------------------------------------------
Total 640,746 637,713 601,927 512,923
--------------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes - - - -
Accumulated deferred investment tax credits 362,672 379,990 399,097 412,771
Prepaid capacity revenues, net 149,534 99,835 102,346 104,211
Deferred revenues from settlement of disputed contracts 59,937 - - -
Uranium enrichment decontamination and decommissioning fund - - - -
Deferred credits related to income taxes - - - -
Natural disaster reserve - - - -
Miscellaneous 82,340 69,334 50,221 52,833
--------------------------------------------------------------------------------------------------------------------------
Total 654,483 549,159 551,664 569,815
--------------------------------------------------------------------------------------------------------------------------
Total Capitalization and Liabilities $ 6,549,462 $ 6,362,293 $ 6,279,431 $ 6,180,945
==========================================================================================================================
*Includes the effect of recognizing, beginning in 1987, retail service rendered
but not yet billed to customers.
II-90A
BALANCE SHEETS
Alabama Power Company
==========================================================================================================================
At December 31, 1987* 1986 1985 1984
--------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock $ 224,358 $ 224,358 $ 224,358 $ 224,358
Paid-in capital 1,225,145 1,182,145 1,182,145 1,155,145
Premium on preferred stock 461 461 1,937 1,938
Earnings retained in the business 496,783 440,644 361,716 282,854
--------------------------------------------------------------------------------------------------------------------------
Total common equity 1,946,747 1,847,608 1,770,156 1,664,295
Preferred stock 384,400 384,400 384,400 424,400
Preferred stock subject to mandatory redemption 27,500 30,000 35,000 37,224
Long-term debt 2,386,258 2,210,108 2,349,373 2,402,713
--------------------------------------------------------------------------------------------------------------------------
Total 4,744,905 4,472,116 4,538,929 4,528,632
(excluding amount due within one year)
--------------------------------------------------------------------------------------------------------------------------
Current Liabilities:
Notes payable to banks 15,000 - - -
Commercial paper - - - -
Preferred stock due within one year 2,500 5,000 42,224 -
Long-term debt due within one year 95,140 142,394 224,918 120,077
Accounts payable 273,613 238,606 295,326 268,966
Customer deposits 32,220 30,333 29,436 28,498
Taxes accrued 72,118 50,757 27,368 36,788
Interest accrued 49,489 47,648 66,193 66,201
Vacation pay accrued 21,317 20,002 18,859 17,599
Miscellaneous 24,660 25,567 42,622 38,474
--------------------------------------------------------------------------------------------------------------------------
Total 586,057 560,307 746,946 576,603
--------------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes - - - -
Accumulated deferred investment tax credits 418,370 418,275 418,222 379,433
Prepaid capacity revenues, net 103,947 101,143 - -
Deferred revenues from settlement of disputed contracts - - - -
Uranium enrichment decontamination and decommissioning fund - - - -
Deferred credits related to income taxes - - - -
Natural disaster reserve - - - -
Miscellaneous 58,721 18,812 18,166 11,529
--------------------------------------------------------------------------------------------------------------------------
Total 581,038 538,230 436,388 390,962
--------------------------------------------------------------------------------------------------------------------------
Total Capitalization and Liabilities $ 5,912,000 $ 5,570,653 $ 5,722,263 $ 5,496,197
==========================================================================================================================
*Includes the effect of recognizing, beginning in 1987, retail service rendered
but not yet billed to customers.
II-90B
ALABAMA POWER COMPANY
OUTSTANDING SECURITIES AT DECEMBER 31, 1994
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
1985 50,000 9-3/8% 50,000 6/1/15
1985 81,500 9-1/4% 81,500 12/1/15
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
---------- ----------
$ 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 1994
First Mortgage Bonds
Principal Interest
Series Amount Rate
----------------------------------------------------
(Thousands)
1987 $ 15,243 10-5/8%
1991 1,252 9-1/4%
1991 1,500 8-3/4%
1992 2,000 8-1/2%
1992 392 8.30%
--------
$ 20,387
========
Pollution Control Bonds
Principal Interest
Series Amount Rate
---------------------------------------------------
(Thousands)
1974 $ 18,550 6%
1976 2,900 7.20%
1978 4,600 7-1/4%
1984 100,000 10-7/8%
1989 35,000 7.20%
1989 18,700 7.20%
--------
$179,750
========
II-92
GEORGIA POWER COMPANY
FINANCIAL SECTION
II-93
MANAGEMENT'S REPORT
Georgia Power Company 1994 Annual Report
The management of Georgia Power Company has prepared this annual report and is
responsible for the financial statements and related information. These
statements were prepared in accordance with generally accepted accounting
principles appropriate in the circumstances, and necessarily include amounts
that are based on the best estimates and judgments of management. Financial
information throughout this annual report is consistent with the financial
statements.
The Company maintains a system of internal accounting controls to provide
reasonable assurance that assets are safeguarded and that the books and records
reflect only authorized transactions of the Company. Limitations exist in any
system of internal controls based upon the recognition that the cost of the
system should not exceed its benefits. The Company believes that its system of
internal accounting controls maintains an appropriate cost/benefit relationship.
The Company's system of internal accounting controls is evaluated on an
ongoing basis by the Company's internal audit staff. The Company's independent
public accountants also consider certain elements of the internal control system
in order to determine their auditing procedures for the purpose of expressing an
opinion on the financial statements.
The audit committee of the board of directors, which is composed of five
directors who are not employees, provides a broad overview of management's
financial reporting and control functions. At least three times a
year this committee meets with management, the internal auditors, and the
independent public accountants to ensure that these groups are fulfilling their
obligations and to discuss auditing, internal control and financial reporting
matters. The internal auditors and the independent public accountants have
access to the members of the audit committee at any time.
Management believes that its policies and procedures provide reasonable
assurance that the Company's operations are conducted with a high standard of
business ethics.
In management's opinion, the financial statements present fairly, in all
material respects, the financial position, results of operations and cash flows
of Georgia Power Company in conformity with generally accepted accounting
principles. As discussed in Note 4 to the financial statements, an uncertainty
exists with respect to the actions of regulators regarding recoverability of the
Company's investment in the Rocky Mountain pumped storage hydroelectric project.
The outcome of this uncertainty cannot be determined until a regulatory review
is completed. Accordingly, no provision for any write-down of the costs
associated with the Rocky Mountain project resulting from the potential actions
of the Georgia Public Service Commission has been made in the accompanying
financial statements.
/s/ H. Allen Franklin
H. Allen Franklin
President and Chief
Executive Officer
/s/ Warren Y. Jobe
Warren Y. Jobe
Executive Vice President,
Treasurer and Chief
Financial Officer
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, 1994 and 1993, 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, 1994. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements (pages II-104 through II-126)
referred to above present fairly, in all material respects, the financial
position of Georgia Power Company as of December 31, 1994 and 1993, and
the results of its operations and its cash flows for the periods stated, in
conformity with generally accepted accounting principles.
As explained in Notes 2 and 7 to the financial statements, effective January
1, 1993, the Company changed its methods of accounting for postretirement
benefits other than pensions and for income taxes.
As more fully discussed in Note 4 to the financial statements, an
uncertainty exists with respect to the actions of the regulators regarding
recoverability of the Company's investment in the Rocky Mountain pumped storage
hydroelectric project. The outcome of this uncertainty cannot be determined
until a regulatory review is completed. Accordingly, no provision for any
write-down of the costs associated with the Rocky Mountain project resulting
from the potential actions of the Georgia Public Service Commission has been
made in the accompanying financial statements.
/s/ Arthur Andersen LLP
Atlanta, Georgia
February 15, 1995
II-95
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Georgia Power Company 1994 Annual Report
RESULTS OF OPERATIONS
Earnings
Georgia Power Company's 1994 earnings totaled $526 million, representing a $44
million (7.8 percent) decrease from the prior year. This decline is primarily
the result of a $55 million after-tax charge associated with the 1994 work force
reduction programs. The Company had lower operating expenses and financing costs
in 1994, partially offset by lower retail revenues due to the mild weather.
Also, during the period, the Company had an $11 million after-tax gain on the
sale of a portion of Plant Scherer Unit 4 compared to an $18 million after-tax
gain on the sale of a portion of the plant in the prior year.
Earnings for 1993 increased over the prior year primarily as a result of
higher retail revenues due to the exceptionally hot summer weather during 1993
and lower financing costs. Also, as previously discussed, 1993 earnings included
an $18 million after-tax gain on the sale of a portion of Plant Scherer. These
positive events were partially offset by higher operating expenses.
Revenues
The following table summarizes the factors impacting operating revenues for the
1992-1994 period:
==========================================================
Increase (Decrease)
From Prior Year
----------------------------------------------------------
1994 1993 1992
--------------------------
Retail - (in millions)
Change in base rates $ - $ - $ 95
Sales growth 67 45 76
Weather (128) 126 (58)
Fuel cost recovery (35) 76 (26)
Demand-side programs (12) 15 -
----------------------------------------------------------
Total retail (108) 262 87
----------------------------------------------------------
Sales for resale -
Non-affiliates (183) (106) (96)
Affiliates (1) (6) 2
----------------------------------------------------------
Total sales for resale (184) (112) (94)
----------------------------------------------------------
Other operating revenues 3 4 3
----------------------------------------------------------
Total operating revenues $(289) $ 154 $ (4)
==========================================================
Percent change (6.5)% 3.6% (0.1)%
----------------------------------------------------------
Retail revenues of $3.7 billion in 1994 decreased $108 million (2.8 percent)
from the prior year, compared with an increase of $262 million (7.4 percent) in
1993. The milder-than-normal weather during the summer of 1994, compared to the
hot summer of 1993, was the primary reason for the decrease in retail revenues.
The hot weather during the summer of 1993 was the primary factor affecting the
increase in retail revenues over 1992. 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 1994 and
1993. Sales to municipalities and cooperatives in Georgia 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 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:
==============================================================
1994 1993 1992
--------------------------
(in millions)
Capacity $84 $152 $233
Energy 82 113 168
--------------------------------------------------------------
Total $166 $265 $401
==============================================================
Contractual unit power sales to Florida utilities for 1994 and 1993 are down
compared with prior years, primarily due to scheduled reductions that
corresponded with the sales to these utilities of portions of Plant Scherer Unit
4 in June 1994 and June 1993. The amount of capacity under these contracts
declined by 427 megawatts and 533 megawatts in 1994 and 1993, respectively.
In 1995, the contracted capacity will decline another 155 megawatts.
II-96
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1994 Annual Report
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.
Kilowatt-hour (KWH) sales for 1994 and the percent change by year were as
follows:
=======================================================================
Percent Change
----------------------------------
1994
KWH 1994 1993 1992
------ ----------------------------------
(in billions)
Residential 15.7 (5.8)% 11.5% 0.8%
Commercial 18.7 2.5 5.9 2.2
Industrial 24.3 3.0 2.9 3.1
Other 0.5 5.0 5.7 1.7
------
Total retail 59.2 0.4 6.1 2.2
------
Sales for resale -
Non-affiliates 8.0 (44.3) (9.8) (15.2)
Affiliates 3.1 0.9 (8.8) (14.6)
------
Total sales for resale 11.1 (36.4) (9.7) (15.1)
------
Total sales 70.3 (8.0) 2.1 (2.9)
======
-----------------------------------------------------------------------
The sales decline in the residential class was primarily the result of
milder-than-normal summer weather in 1994, compared to the extremely hot summer
of 1993. Industrial and commercial sales were positively impacted by continued
improvement in economic conditions. Residential and commercial energy sales
growth in 1993 reflected hot summer weather. Industrial sales growth in 1993 is
attributable to improved economic conditions which also positively influenced
commercial sales. Assuming normal weather, sales to retail customers are
projected to grow approximately 2 percent annually on average during 1995
through 1997.
Energy sales to non-affiliated utilities reflect reductions in contractual
unit power sales and energy sales to municipalities and cooperatives, as
discussed earlier.
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:
===============================================================================
1994 1993 1992
----------------------------------
Total generation
(billions of kilowatt-hours) 62 64 63
Sources of generation
(percent) --
Coal 74.8 76.9 75.9
Nuclear 21.9 20.0 20.9
Hydro 3.1 2.8 3.1
Oil and gas 0.2 0.3 0.1
Average cost of fuel per net
kilowatt-hour generated
(cents) --
Coal 1.67 1.75 1.75
Nuclear 0.63 0.58 0.63
Oil and gas * * *
Total 1.44 1.52 1.52
-------------------------------------------------------------------------------
* Not meaningful because of minimal generation from
fuel source.
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. In 1993, fuel expense increased 2.3 percent due to higher
generation, which was partially offset by lower nuclear fuel costs.
Purchased power expense has decreased significantly since 1992, reflecting
declining contractual capacity purchases from the co-owners of plants Vogtle and
Scherer. Purchased power expense decreased $156 million in 1994 and $88 million
in 1993. The decline in 1994 also results from decreased purchases from
affiliated companies and energy purchases from territorial wholesale customers.
The declines in Plant Vogtle contractual capacity purchases did not have a
significant impact on earnings in 1994 or 1993 since these costs are being
levelized over six years under the terms of the 1991 Georgia Public Service
Commission (GPSC) retail rate order. The levelization is reflected in the
amortization of deferred Plant Vogtle expenses in the income statements. See
Note 3 to the financial statements under "Plant Vogtle Phase-In Plans" for
additional information.
II-97
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1994 Annual Report
Other Operation and Maintenance (O & M) expenses, excluding the provision
for separation benefits, decreased 4.5 percent in 1994. The decrease is
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 expenses
and pension costs during 1994. Other O & M expenses increased 9.0 percent in
1993 primarily as a result of environmental remediation costs and the automotive
fleet reduction program, and the recognition of higher employee benefit costs
under new accounting rules adopted in 1993. See Note 2 to the financial
statements under "Postretirement Benefits" for additional information concerning
the new accounting rules. Also, during 1993, O & M expenses reflected costs
associated with new demand-side option programs. These program costs were offset
by increases in retail revenues. See Note 3 to the financial statements under
"Demand-Side Conservation Programs" for additional information on the recovery
of these program costs.
Taxes other than income taxes increased 1.0 percent in 1994 and 7.4 percent
in 1993, reflecting primarily higher ad valorem taxes. The 1993 increase also
includes higher franchise taxes paid to municipalities as a result of increased
sales.
Income tax expense decreased $24 million in 1994 primarily due to lower
earnings and the recognition of $17 million in tax expense associated with the
sale of a portion of Plant Scherer Unit 4 in 1994, compared to $27 million in
tax expense associated with the sale of a portion of the plant in the prior
year. The sales resulted in after-tax gains of $11 million in 1994 and $18
million in 1993. Income tax expense increased $62 million in 1993 due primarily
to higher earnings, the effect of a one percent increase in the federal tax rate
effective January, 1993, and as previously discussed, the sale of a portion of
Plant Scherer Unit 4.
Interest expense and dividends on preferred stock decreased $63 million
(13.7 percent) and $19 million (4.0 percent) in 1994 and 1993, respectively.
These reductions are primarily due to refinancing of long-term debt and
preferred stock. The Company refinanced $510 million and $1.5 billion of
securities in 1994 and 1993, respectively. The Company also retired $386 million
of long-term debt with the proceeds from the 1994 and 1993 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.
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 1995 through 1997.
The scheduled addition of four combustion turbine generating units and the
Rocky Mountain pumped storage hydroelectric project in 1995 and one jointly
owned combustion turbine unit in 1996, will increase related O & M and
II-98
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1994 Annual Report
depreciation expenses. In addition, the Company has entered into a four-year
purchase power agreement to meet peaking needs. Beginning in 1996, the Company
will purchase 400 megawatts of capacity. In 1998, this amount will decline to
200 megawatts for the remaining two years. Capacity payments are projected to be
$6 million in 1996 and 1997 and $3 million in 1998 and 1999. These costs will be
recorded in purchased power expenses in the Statements of Income. The Company
has also reached an agreement on major terms and conditions of a purchase power
arrangement whereby the Company would buy electricity during peak periods from a
proposed 200 megawatt cogeneration facility, starting in June 1998. A final
agreement is expected to be completed and filed with the GPSC for certification
during 1995.
In 1994, work force reduction programs were implemented, reducing earnings
by $55 million. These reductions will assist in efforts to control growth in
future operating expenses.
As discussed in Note 4 to the financial statements, regulatory uncertainties
exist related to the Rocky Mountain pumped storage hydroelectric project. In the
event the GPSC does not allow full recovery of the project's costs, then the
portion not allowed may have to be written off. The Company's total investment
in the project at completion is estimated to be approximately $200 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 and litigation currently pending in the U. S. Tax Court.
The Company has completed three in a series of four separate transactions to
sell Unit 4 of Plant Scherer to two Florida utilities. The remaining transaction
is scheduled to take place in 1995. If the sale takes place as planned, the
Company would realize an additional after-tax gain estimated to total
approximately $12 million. This transaction coincides with scheduled reductions
in capacity revenues from Florida utilities under contractual unit power sales
contracts of approximately $18 million in 1995 and an additional $10 million in
1996. Additionally, the expiration in 1994 of the contract for the sale of
long-term non-firm power to Florida Power Corporation will result in a $9
million decrease in capacity revenues in 1995. See Notes 5 and 6 to the
financial statements for additional information.
During 1994, Oglethorpe Power Corporation (OPC) gave the Company notice of
its intent to decrease its purchases of capacity under a power supply agreement.
As a result, the Company's capacity revenues from OPC will decline approximately
$8 million in 1996 and an additional $16 million in 1997.
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 Clean Air 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 may enhance the
incentive for IPPs to build cogeneration plants for a utility's large industrial
and commercial customers and sell excess energy generation to other utilities.
Although the Energy Act does not require transmission access to retail
customers, retail wheeling initiatives are rapidly evolving and becoming very
prominent issues in several states. 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
II-99
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1994 Annual Report
connected load may choose their electricity supplier. In addition, the bulk
power market has become very competitive as utilities, IPPs and cogenerators
seek to supply future capacity needs. Competition can create new business
opportunities, but it increases risk and has the potential to adversely affect
earnings.
The Federal Energy Regulatory Commission (FERC) regulates wholesale rate
schedules and power sales contracts that the Company has with its sales for
resale customers. The FERC currently is reviewing the rate of return on common
equity included in these schedules and contracts and may require such returns to
be lowered, possibly retroactively. See Note 3 to the financial statements under
"FERC Review of Equity Returns" for additional information.
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. 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 nuclear decommissioning. If current electric utility
industry accounting practices for decommissioning are changed: (1) annual
provisions for decommissioning could increase, and (2) the estimated cost for
decommissioning may be required to be recorded as a liability in the Balance
Sheets. In management's opinion -- should these changes be required -- the
changes would not have a significant adverse effect on results of operations
because of the Company's current and expected future ability to recover
decommissioning costs through rates. See Note 1 to the financial statements
under "Depreciation and Nuclear Decommissioning" for additional information.
FINANCIAL CONDITION
Overview
The principal changes in the Company's financial condition in 1994 were gross
utility plant additions of $638 million and the lowering of the cost of capital
achieved through the refinancing or retirement of $654 million 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 1994, the Company continued to lower its financing costs by refinancing
higher-cost issues. New issues during 1992 through 1994 totaled $3.5 billion and
retirement or repayment of securities totaled $4.1 billion. The retirements
included the redemption of $133 million and $253 million in 1994 and 1993,
respectively, of first mortgage bonds with the proceeds from the Plant Scherer
Unit 4 sales. Composite financing rates for the years 1992 through 1994, as of
year-end, were as follows:
==============================================================
1994 1993 1992
----------------------------------
Composite interest rate
on long-term debt 7.14% 7.86% 8.49%
Composite preferred
stock dividend rate 7.11% 6.76% 7.52%
==============================================================
The Company's current securities ratings are as follows:
==============================================================
Duff & Standard &
Phelps Moody's Poor's
First Mortgage Bonds A+ A2 A
Preferred Stock A- a3 A-
Unsecured Bonds A A3 A-
Commercial Paper D1 P1 A1
==============================================================
Liquidity and Capital Requirements
Cash provided from operations decreased by $128 million in 1994, primarily due
to lower retail sales, higher tax payments, and the receipt in 1993 of cash
payments from Gulf States as partial settlement of litigation.
II-100
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1994 Annual Report
The Company estimates that construction expenditures for the years 1995
through 1997 will total $579 million, $626 million and $724 million,
respectively. The Company will continue to invest in transmission and
distribution facilities and enhance existing generating plants. These
expenditures also include amounts for five combustion turbine generating units
and equipment that will be required to comply with the provisions of the Clean
Air Act.
The Company's annual contractual capacity purchases will decline by $70
million over the next three years. Cash requirements for sinking fund
requirements, redemptions announced, and maturities of long-term debt are
expected to total $360 million during 1995 through 1997.
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 1995 through 1997, the amount to be funded totals $16
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 $33 million as of December 31, 1994. 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 $709 million of unused credit
arrangements with banks at the beginning of 1995. See Note 8 to the financial
statements for additional information.
Completing the remaining transaction for the sale of Plant Scherer Unit 4
will generate approximately $131 million in 1995.
Georgia Power Capital, a limited partnership, was formed on November 10,
1994, for the purpose of issuing preferred securities and subsequently lending
the proceeds to the Company. In December 1994, Georgia Power Capital issued four
million shares of preferred securities at 9 percent and subsequently loaned the
proceeds of $100 million to the Company. This subordinated debt of the Company
is due December 19, 2024.
The Company is required to meet certain coverage requirements specified in
its mortgage indenture and corporate charter to issue new first mortgage bonds
and preferred stock. The Company's ability to satisfy all coverage requirements
is such that it could issue new first mortgage bonds and preferred stock to
provide sufficient funds for all anticipated requirements.
Environmental Issues
In November 1990, the Clean Air Act was signed into law. Title IV of the Clean
Air Act -- the acid rain compliance provision of the law -- will have a
significant impact on The Southern Company. Specific reductions in sulfur
dioxide and nitrogen oxide emissions from fossil-fired generating plants will be
required in two phases. Phase I compliance began in 1995 and affected eight
generating plants -- some 10,000 megawatts of capacity or 35 percent of total
capacity -- in the Southern electric system. Phase II compliance is required in
2000, and all fossil-fired generating plants in the Southern electric system
will be affected.
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
II-101
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1994 Annual Report
designed to use allowances as a compliance option.
The Southern Company expects to achieve Phase I sulfur dioxide compliance at
the eight affected plants by switching to low-sulfur coal, which has required
some equipment upgrades. This compliance strategy is expected to result in
unused emission allowances being banked for later use. Additional construction
expenditures were required to install equipment for the control of nitrogen
oxide emissions at these eight plants. Also, continuous emissions monitoring
equipment will be installed on all fossil-fired units. Under this Phase I
compliance approach, Georgia Power's construction expenditures are estimated to
total approximately $175 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
$20 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 2 percent in Georgia Power's annual revenue
requirements from customers could be necessary to fully recover the cost of
compliance for both Phase I and Phase II of 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.
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 has issued
rules for the application of reasonably available control technology to reduce
nitrogen oxide emissions by May 31, 1995. The results of these new rules require
nitrogen oxide controls, above Title IV requirements, on some of the Company's
plants. Final attainment rules, based on modeling studies, could require
installation of additional controls for nitrogen oxide emissions to meet the
1999 deadline. A decision on new requirements is expected in 1996. 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 by November 1995. 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 continues to evaluate the need for a new short-term ambient air
quality standard for sulfur dioxide. Preliminary results from an EPA study on
the impact of a new standard indicate that a number of plants could be required
to install sulfur dioxide controls. These controls would be in addition to the
controls already required to meet the acid rain provision of the Clean Air Act.
The EPA issued proposed rules in November 1994 and is required to take final
action on this issue in 1996. The impact of any new standard will depend on the
level chosen for the standard and cannot be determined at this time.
In addition, the EPA is evaluating the need to revise the ambient air
quality standards for particulate matter, nitrogen oxides, and ozone. The impact
of any new standard will depend on the level chosen for the standard and cannot
be determined at this time.
In 1995, 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.
II-102
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1994 Annual Report
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, $32
million, and $3 million in 1994, 1993, and 1992, respectively. Additional sites
may require environmental remediation for which the Company may be liable for a
portion or all required cleanup costs. See Note 4 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 another environmental matter.
Several major pieces of environmental legislation are being considered for
reauthorization or amendment by Congress. These include: the Clean Water Act;
the Comprehensive Environmental Response, Compensation, and Liability Act; the
Resource Conservation and Recovery 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 new legislation related to global climate change,
electromagnetic fields and other environmental and health concerns could
significantly affect the Company. The impact of new legislation -- if any --
will depend on the subsequent development and implementation of applicable
regulations. In addition, the potential exists for liability as the result of
lawsuits alleging damages caused by electromagnetic fields.
II-103
STATEMENTS OF INCOME
For the Years Ended December 31, 1994, 1993, and 1992
Georgia Power Company 1994 Annual Report
==================================================================================================
1994 1993 1992
--------------------------------------------------------------------------------------------------
(in thousands)
Operating Revenues:
Revenues (Note 1) $4,101,504 $4,389,513 $4,229,601
Revenues from affiliates 60,899 61,668 67,835
--------------------------------------------------------------------------------------------------
Total operating revenues 4,162,403 4,451,181 4,297,436
--------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
Fuel 870,653 951,507 929,780
Purchased power from non-affiliates 193,130 313,170 436,761
Purchased power from affiliates 158,063 194,024 158,306
Provision for separation benefits 82,238 - 9,778
Other 643,375 675,284 611,134
Maintenance 272,818 284,521 264,757
Depreciation and amortization 379,158 379,425 375,460
Amortization of deferred Plant Vogtle expenses, net (Note 3) 74,888 36,284 (30,804)
Taxes other than income taxes 194,566 192,671 179,460
Federal and state income taxes 399,413 452,122 377,542
--------------------------------------------------------------------------------------------------
Total operating expenses 3,268,302 3,479,008 3,312,174
--------------------------------------------------------------------------------------------------
Operating Income 894,101 972,173 985,262
Other Income (Expense):
Allowance for equity funds used during construction 5,663 3,168 5,855
Equity in earnings of unconsolidated subsidiary (Note 5) 3,588 4,127 4,635
Interest income 3,254 3,806 12,475
Other, net 10,626 11,902 (30,527)
Income taxes applicable to other income 7,975 37,661 25,163
--------------------------------------------------------------------------------------------------
Income Before Interest Charges 925,207 1,032,837 1,002,863
--------------------------------------------------------------------------------------------------
Interest Charges:
Interest on long-term debt 306,473 343,634 402,541
Allowance for debt funds used during construction (11,571) (8,271) (8,310)
Interest on interim obligations 17,529 15,530 9,694
Amortization of debt discount, premium, and expense, net 15,743 14,024 8,033
Other interest charges 23,483 47,393 12,425
--------------------------------------------------------------------------------------------------
Net interest charges 351,657 412,310 424,383
--------------------------------------------------------------------------------------------------
Net Income 573,550 620,527 578,480
Dividends on Preferred Stock 48,006 50,674 57,942
--------------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred Stock $ 525,544 $ 569,853 $ 520,538
==================================================================================================
The accompanying notes are an integral part of these statements.
II-104
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1994, 1993, and 1992
Georgia Power Company 1994 Annual Report
==================================================================================================
1994 1993 1992
--------------------------------------------------------------------------------------------------
(in thousands)
Operating Activities:
Net income $ 573,550 $ 620,527 $ 578,480
Adjustments to reconcile net income to net
cash provided by operating activities --
Depreciation and amortization 484,032 475,152 471,014
Deferred income taxes and investment tax credits, net 33,567 150,735 189,251
Allowance for equity funds used during construction (5,663) (3,168) (5,855)
Deferred Plant Vogtle costs 74,888 36,284 (30,804)
Provision for separation benefits 68,599 - -
Gain on asset sales (22,717) (35,514) (12)
Other, net (72,597) (10,713) (14,738)
Changes in certain current assets and liabilities --
Receivables, net 67,218 27,088 (31,348)
Inventories (63,545) 82,433 (65,621)
Payables 5,409 17,364 25,303
Taxes accrued (60,474) 15,377 (22,828)
Energy cost recovery, retail 55,505 (74,260) (46,615)
Other (706) (35,691) (16,518)
------------------------------------------------------------------------------------------------
Net cash provided from operating activities 1,137,066 1,265,614 1,029,709
------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (638,426) (674,432) (508,444)
Sales of property 132,644 261,687 46
Other (41,273) (43,154) 42,892
------------------------------------------------------------------------------------------------
Net cash used for investing activities (547,055) (455,899) (465,506)
------------------------------------------------------------------------------------------------
Financing Activities and Capital Contributions:
Proceeds:
Preferred securities of subsidiary 100,000 - -
Preferred stock - 175,000 195,000
First mortgage bonds - 1,135,000 975,000
Pollution control bonds 527,210 145,425 161,955
Long-term notes - 37,000 -
Retirements:
Preferred stock - (245,005) (165,004)
First mortgage bonds (133,559) (1,337,822) (1,381,300)
Pollution control bonds (510,320) (145,465) (160,205)
Other long-term debt (10,187) (19,451) (567)
Interim obligations, net (57,425) (51,444) 334,671
Payment of preferred stock dividends (47,147) (53,123) (60,475)
Payment of common stock dividends (429,300) (402,400) (384,000)
Miscellaneous (22,640) (63,648) (70,986)
------------------------------------------------------------------------------------------------
Net cash used for financing activities (583,368) (825,933) (555,911)
------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents 6,643 (16,218) 8,292
Cash and Cash Equivalents at Beginning of Year 5,896 22,114 13,822
------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 12,539 $ 5,896 $ 22,114
================================================================================================
Supplemental Cash Flow Information:
Cash paid during the year for --
Interest (net of amount capitalized) $ 336,155 $ 420,107 $ 435,203
Income taxes 386,653 275,867 190,674
------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
II-105
BALANCE SHEETS
At December 31, 1994 and 1993
Georgia Power Company 1994 Annual Report
===========================================================================================
ASSETS 1994 1993
-------------------------------------------------------------------------------------------
(in thousands)
Utility Plant:
Plant in service (Note 1) $ 14,054,917 $ 13,743,521
Less accumulated provision for depreciation 4,054,986 3,822,344
-------------------------------------------------------------------------------------------
9,999,931 9,921,177
Nuclear fuel, at amortized cost (Note 1) 136,425 135,742
Construction work in progress (Note 4) 541,889 584,013
-------------------------------------------------------------------------------------------
Total 10,678,245 10,640,932
-------------------------------------------------------------------------------------------
Other Property and Investments:
Southern Electric Generating Company, at equity (Note 5) 26,985 29,201
Nuclear decommissioning trusts (Note 1) 54,297 37,937
Miscellaneous 89,542 31,941
-------------------------------------------------------------------------------------------
Total 170,824 99,079
-------------------------------------------------------------------------------------------
Current Assets:
Cash and cash equivalents 12,539 5,896
Receivables-
Customer accounts receivable 377,570 486,947
Other accounts and notes receivable 104,989 117,249
Affiliated companies 14,443 14,832
Accumulated provision for uncollectible accounts (4,500) (4,300)
Fossil fuel stock, at average cost 169,252 111,620
Materials and supplies, at average cost 293,464 287,551
Prepayments 55,383 65,269
Vacation pay deferred (Note 1) 40,823 41,575
-------------------------------------------------------------------------------------------
Total 1,063,963 1,126,639
-------------------------------------------------------------------------------------------
Deferred Charges:
Deferred charges related to income taxes (Note 7) 919,750 992,510
Deferred Plant Vogtle costs (Note 3) 432,092 506,980
Premium on reacquired debt, being amortized 164,676 153,146
Debt expense, being amortized 26,223 20,730
Miscellaneous 256,885 196,094
-------------------------------------------------------------------------------------------
Total 1,799,626 1,869,460
-------------------------------------------------------------------------------------------
Total Assets $ 13,712,658 $ 13,736,110
===========================================================================================
The accompanying notes are an integral part of these statements.
II-106
BALANCE SHEETS
At December 31, 1994 and 1993
Georgia Power Company 1994 Annual Report
===========================================================================================
CAPITALIZATION AND LIABILITIES 1994 1993
-------------------------------------------------------------------------------------------
(in thousands)
Capitalization (See accompanying statements):
Common stock equity $ 4,141,554 $ 4,045,458
Preferred stock 692,787 692,787
Preferred securities of subsidiary 100,000 -
Long-term debt 3,757,823 4,031,387
-------------------------------------------------------------------------------------------
Total 8,692,164 8,769,632
-------------------------------------------------------------------------------------------
Current Liabilities:
Long-term debt due within one year (Note 8) 167,420 10,543
Notes payable to banks (Note 8) 202,200 406,700
Commercial paper (Note 8) 222,602 75,527
Accounts payable-
Affiliated companies 41,760 38,115
Other 313,307 285,929
Customer deposits 47,017 45,922
Taxes accrued-
Federal and state income 2,856 31,639
Other 90,163 121,854
Interest accrued 110,256 110,497
Vacation pay accrued 39,720 40,060
Miscellaneous 70,006 64,527
-------------------------------------------------------------------------------------------
Total 1,307,307 1,231,313
-------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes (Note 7) 2,477,661 2,479,720
Accumulated deferred investment tax credits 453,121 478,334
Deferred credits related to income taxes (Note 7) 433,334 452,819
Disallowed Plant Vogtle capacity buyback costs (Note 5) 60,490 63,067
Miscellaneous 288,581 261,225
-------------------------------------------------------------------------------------------
Total 3,713,187 3,735,165
-------------------------------------------------------------------------------------------
Commitments and Contingent Matters (Notes 1, 2, 3, 4, 5, and 6)
Total Capitalization and Liabilities $ 13,712,658 $ 13,736,110
===========================================================================================
The accompanying notes are an integral part of these statements.
II-107
STATEMENTS OF CAPITALIZATION
At December 31, 1994 and 1993
Georgia Power Company 1994 Annual Report
====================================================================================================
1994 1993 1994 1993
----------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
Common Stock Equity:
Common stock, without par value --
Authorized -- 15,000,000 shares
Outstanding -- 7,761,500 shares $ 344,250 $ 344,250
Paid-in capital 2,384,348 2,384,348
Premium on preferred stock 413 413
Retained earnings (Note 8) 1,412,543 1,316,447
----------------------------------------------------------------------------------------------------
Total common stock equity 4,141,554 4,045,458 47.6 % 46.1 %
----------------------------------------------------------------------------------------------------
Cumulative Preferred Stock, without par value:
Authorized -- 55,000,000 shares in 1994 and 1993;
Outstanding -- 21,027,865 shares in 1994;
$100 stated value --
4.60% to 6.60% 117,787 117,787
7.72% to 7.80% 105,000 105,000
$25 stated value --
$1.90 to $2.125 295,000 295,000
Adjustable rate -- at January 1, 1995:
6.30% 100,000 100,000
6.86% 75,000 75,000
----------------------------------------------------------------------------------------------------
Total (annual dividend requirement -- $49,251,000) 692,787 692,787 8.0 7.9
----------------------------------------------------------------------------------------------------
Cumulative Preferred Securities of Subsidiary (Note 8):
$25 stated value -- 9% 100,000 -
----------------------------------------------------------------------------------------------------
Total (annual distribution requirement -- $9,000,000) 100,000 - 1.2 -
----------------------------------------------------------------------------------------------------
Long-Term Debt:
First mortgage bonds --
Maturity Interest Rates
-------- --------------
September 1, 1995 5 1/8% 130,000 130,000
March 1, 1996 4 3/4% 150,000 150,000
April 1, 1998 5 1/2% 100,000 100,000
September 1, 1999 6 1/8% 195,000 195,000
2000 through 2003 6% to 7% 625,000 625,000
2008 6 7/8% 50,000 50,000
2016 through 2019 9.23% to 10% 36,157 169,716
2022 through 2023 7.55% to 8 3/4% 660,000 660,000
2032 variable rates 200,000 200,000
----------------------------------------------------------------------------------------------------
Total first mortgage bonds 2,146,157 2,279,716
Pollution control obligations (Note 8) 1,678,140 1,661,250
Other long-term debt (Note 8) 124,686 135,058
Unamortized debt premium (discount), net (23,740) (34,094)
----------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
requirement -- $282,112,000) 3,925,243 4,041,930
Less amount due within one year (Note 8) 167,420 10,543
----------------------------------------------------------------------------------------------------
Long-term debt excluding amount due within one year 3,757,823 4,031,387 43.2 46.0
----------------------------------------------------------------------------------------------------
Total Capitalization $ 8,692,164 $ 8,769,632 100.0 % 100.0 %
====================================================================================================
The accompanying notes are an integral part of these statements.
II-108
STATEMENTS OF RETAINED EARNINGS
For the Years Ended December 31, 1994, 1993, and 1992
Georgia Power Company 1994 Annual Report
===============================================================================================
1994 1993 1992
-----------------------------------------------------------------------------------------------
(in thousands)
Balance at Beginning of Period $ 1,316,447 $ 1,159,380 $ 1,038,012
Net income after dividends on preferred stock 525,544 569,853 520,538
Cash dividends on common stock (429,300) (402,400) (384,000)
Preferred stock transactions, net (148) (10,386) (15,170)
-----------------------------------------------------------------------------------------------
Balance at End of Period (Note 8) $ 1,412,543 $ 1,316,447 $ 1,159,380
===============================================================================================
STATEMENTS OF PAID-IN CAPITAL
For the Years Ended December 31, 1994, 1993, and 1992
Georgia Power Company 1994 Annual Report
===============================================================================================
1994 1993 1992
-----------------------------------------------------------------------------------------------
(in thousands)
Balance at Beginning of Period $ 2,384,348 $ 2,384,140 $ 2,383,800
Contributions to capital by parent company - 208 340
-----------------------------------------------------------------------------------------------
Balance at End of Period $ 2,384,348 $ 2,384,348 $ 2,384,140
===============================================================================================
The accompanying notes are an integral part of these financial statements.
II-109
NOTES TO FINANCIAL STATEMENTS
Georgia Power Company 1994 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), and
Southern Nuclear Operating Company (Southern Nuclear), and The Southern
Development and Investment Group (SDIG). The operating companies (Alabama Power
Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company,
and Savannah Electric and Power Company) provide electric service in four
southeastern states. Intracompany contracts dealing with jointly owned
generating facilities, transmission lines and exchange of electric power are
regulated by the Federal Energy Regulatory Commission (FERC) or the Securities
and Exchange Commission. SCS provides, at cost, specialized services to The
Southern Company and each of the subsidiary companies. Southern Communications,
beginning in mid-1995, will provide digital wireless communications services to
The Southern Company's subsidiaries and also will market these services to the
public within the Southeast. Southern Electric designs, builds, owns, and
operates power production facilities and provides a broad range of technical
services to industrial companies and utilities in the United States and a number
of international markets. Southern Nuclear provides services to The Southern
Company's nuclear power plants. SDIG 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. Both The Southern Company and its
subsidiaries are subject to the regulatory provisions of this act. The Company
is also subject to regulation by the FERC and the Georgia Public Service
Commission (GPSC). The Company follows generally accepted accounting principles
and complies with the accounting policies and practices prescribed by the
respective regulatory commissions.
Certain prior years' data presented in the financial statements have been
reclassified to conform with current year presentation.
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:
===============================================================
1994 1993
--------------------
(in millions)
Deferred income taxes $ 920 $ 993
Deferred income tax credits (433) (453)
Deferred Plant Vogtle costs 432 507
Premium on reacquired debt 165 153
Demand-side program costs 97 49
Corporate building lease 48 47
Postretirement benefits 41 22
Vacation pay 41 42
Inventory conversions (39) (47)
Department of Energy assessments 36 41
Other, net 52 61
---------------------------------------------------------------
Total $1,360 $1,415
===============================================================
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 to their fair value.
II-110
NOTES (continued)
Georgia Power Company 1994 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. Fuel costs were under recovered by $23 million and $79 million at
December 31, 1994, and 1993, respectively. These amounts are included in
customer accounts receivable on the Balance Sheets. The fuel cost recovery rate
was increased effective December 6, 1993.
The Company has a diversified base of customers. No single customer or
industry comprises 10 percent or more of revenues. In 1994, 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 $87
million in 1994, $75 million in 1993, and $84 million in 1992. 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 to
be approximately $33 million. This obligation is recognized in the accompanying
Balance Sheets and is being recovered through the fuel cost recovery provisions.
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
3.1 percent in 1994, 1993, and 1992. 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.
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.
II-111
NOTES (continued)
Georgia Power Company 1994 Annual Report
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, 1994, -- 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
-----------------------------------------------------------
Site study costs: (in millions)
Radiated structures $241 $193
Non-radiated structures 34 43
Other 60 49
-----------------------------------------------------------
Total $335 $285
===========================================================
Ultimate costs: (in millions)
Radiated structures $641 $ 843
Non-radiated structures 91 190
Other 160 215
-----------------------------------------------------------
Total $892 $1,248
===========================================================
(in millions)
Amount expensed in 1994 $6 $6
Accumulated provisions:
Balance in external trust funds $33 $22
Balance in internal reserves 29 10
-----------------------------------------------------------
Total $62 $32
===========================================================
Assumed in ultimate costs:
Inflation rate 4.4% 4.4%
Trust earning 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
approved for ratemaking are $184 million for Plant Hatch and $155 million for
Plant Vogtle. These amounts are based on costs to decommission the radioactive
portions of the plants based on 1990 site studies. The estimated ultimate costs
based on the 1990 studies were $872 million and $1.4 billion for plants Hatch
and Vogtle, respectively. 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 assumed date of decommissioning,
changes in regulatory requirements, changes in technology, and changes in costs
of labor, materials, and equipment.
Plant Vogtle Phase-In Plans
In 1987 and 1989, the GPSC ordered that the allowed costs of Plant Vogtle Units
1 and 2 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.
Income Taxes
The Company provides deferred income taxes for all significant income tax
temporary differences. Investment tax credits utilized are deferred and
amortized to income over the average lives of the related property.
Effective January 1, 1993, the Company adopted FASB Statement No. 109,
Accounting for Income Taxes. Statement No. 109 required, among other things,
conversion to the liability method of accounting for accumulated deferred income
taxes. See Note 7 for additional information about Statement No. 109.
II-112
NOTES (continued)
Georgia Power Company 1994 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. For the years 1994, 1993 and 1992, the average AFUDC rates
were 6.18 percent, 4.96 percent and 7.16 percent, respectively. The reduction in
the average AFUDC rate in 1993 reflects the Company's greater use of lower cost
short-term debt. 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 1994, 1993 and 1992,
respectively.
Utility Plant
Utility plant is stated at original cost with the exception of Plant Vogtle,
which is stated at cost less regulatory disallowances. Original cost includes
materials; labor; appropriate administrative and general costs; payroll-related
costs such as taxes, pensions, and other benefits; and the 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 replacement of
property (exclusive of minor items of property) is charged to utility plant.
The Company's investment in generating plant, based on its ownership
interests and net of the accumulated provision for depreciation, by type of
generation as of December 31 was as follows:
==================================================================
Nameplate
Type of Generation Net Investment Capacity
-------------------- ----------------- ----------------
1994 1993 1994 1993
----------------- ----------------
(in millions) (megawatts)
Steam $1,674 $1,718 9,676 9,812
Nuclear 3,113 3,215 1,877 1,877
Hydro 335 338 862 862
Other 123 18 1,528 1,208
-----------------------------------------------------------------
Total $5,245 $5,289 13,943 13,759
=================================================================
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:
=============================================================
Long-Term Debt
-------------------------
Carrying Fair
Amount Value
------------------------
Year (in millions)
1994 $3,838 $3,697
1993 3,954 4,197
The fair values for long-term debt were based on either closing market
prices or closing prices of comparable instruments.
Materials and Supplies
Generally, materials and supplies include the cost of transmission, distribution
and generating plant materials. Materials are charged to inventory when
purchased and then expensed or capitalized to plant, as appropriate, when
installed.
Vacation Pay
Company employees earn vacation in one year and take it in the subsequent year.
However, for ratemaking purposes, vacation pay is recognized as an allowable
expense only when paid. Consistent with this ratemaking treatment, the Company
accrues a current liability for earned vacation pay and records a current
regulatory asset representing the future recoverability of this cost. This
amount was $41 million at December 31, 1994, and $42 million at December 31,
1993. In 1995, approximately 70 percent of the 1994 deferred vacation costs will
be expensed, and the balance will be charged to construction and other accounts.
II-113
NOTES (continued)
Georgia Power Company 1994 Annual Report
2. RETIREMENT BENEFITS
Pension Plan
The Company has a defined benefit, trusteed,
non-contributory pension plan covering substantially all regular employees.
Benefits are based on the greater of amounts resulting from two different
formulas: years of service and final average pay or years of service and a flat
dollar benefit. The Company uses the "entry age normal method with a frozen
initial liability" actuarial method for funding purposes, subject to limitations
under federal income tax regulations. Amounts funded to the pension 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
FERC. During 1994, the Company funded $22 million to the qualified trusts.
Amounts funded are primarily invested in debt and equity securities.
Effective January 1, 1993, the Company adopted FASB Statement No. 106,
Employers' Accounting for Postretirement Benefits Other Than Pensions, on a
prospective basis. Statement No. 106 requires that medical care and life
insurance benefits for retired employees be accounted for on an accrual basis
using a specified actuarial method, "benefit/years-of-service."
In October 1993, the GPSC ordered the Company to phase in the adoption of
Statement No. 106 to cost of service over a five-year period, whereby one-fifth
of the additional expense was recognized in 1993 and the remaining additional
expense was deferred. An additional one-fifth of the costs will be expensed each
succeeding year until the costs are fully reflected in cost of service in 1997.
The cost deferred during the five-year period will be amortized to expense over
a 15-year period beginning in 1998. As a result of the regulatory treatment
allowed by the GPSC, the adoption of Statement No. 106 did not have a material
impact on net income.
Prior to 1993, the Company recognized these costs on a cash basis as
payments were made. The total costs of such benefits recognized by the Company
in 1992 were $13 million.
Funded Status and Cost of Benefits
Shown in the following tables are actuarial results and assumptions for pension
and postretirement medical and life insurance benefits as computed under the
requirements of Statement Nos. 87 and 106, respectively. The funded status of
the plans at December 31 was as follows:
Pension
===============================================================
1994 1993
---------------------
Actuarial present value of (in millions)
benefit obligations:
Vested benefits $ 689 $ 655
Non-vested benefits 32 35
---------------------------------------------------------------
Accumulated benefit obligation 721 690
Additional amounts related
to projected salary increases 294 257
---------------------------------------------------------------
Projected benefit obligation 1,015 947
Less:
Fair value of plan assets 1,419 1,495
Unrecognized net gain (371) (490)
Unrecognized prior service cost 28 31
Unrecognized transition asset (58) (62)
---------------------------------------------------------------
Prepaid asset recognized in
the Balance Sheets $ 3 $ 27
===============================================================
II-114
NOTES (continued)
Georgia Power Company 1994 Annual Report
Postretirement Medical
===============================================================
1994 1993
--------------------
(in millions)
Actuarial present value of
benefit obligation:
Retirees and dependents $168 $136
Employees eligible to retire 7 12
Other employees 191 206
---------------------------------------------------------------
Accumulated benefit obligation 366 354
Less:
Fair value of plan assets 46 30
Unrecognized net loss 7 40
Unrecognized transition
obligation 236 251
---------------------------------------------------------------
Accrued liability recognized in the
Balance Sheets $ 77 $ 33
===============================================================
Postretirement Life
===============================================================
1994 1993
---------------
(in millions)
Actuarial present value of benefit obligation:
Retirees and dependents $35 $32
Employees eligible to retire - -
Other employees 38 40
---------------------------------------------------------------
Accumulated benefit obligation 73 72
Less:
Fair value of plan assets 6 1
Unrecognized net gain (8) (6)
Unrecognized transition
obligation 65 69
---------------------------------------------------------------
Accrued liability recognized in the
Balance Sheets $10 $ 8
===============================================================
Weighted average rates used in actuarial calculations:
=============================================================
1994 1993 1992
------------------------------
Discount 8.0% 7.5% 8.0%
Annual salary increase 5.5 5.0 6.0
Long-term return on plan
assets 8.5 8.5 8.5
-------------------------------------------------------------
An additional assumption used in measuring the accumulated postretirement
medical benefit obligation was a weighted average medical care cost trend rate
of 10.5 percent for 1994, decreasing gradually to 6 percent through the year
2000 and remaining at that level thereafter. An annual increase in the assumed
medical care cost trend rate of 1.0 percent would increase the accumulated
medical benefit obligation as of December 31, 1994, by $68 million and the
aggregate of the service and interest cost components of the net retiree medical
cost by $10 million.
The components of the plans' net costs are shown below:
Pension
==============================================================================
1994 1993 1992
----------------------------
(in millions)
Benefits earned during the year $ 34 $ 33 $ 34
Interest cost on projected
benefit obligation 71 69 65
Actual (return) loss on plan assets 35 (194) (61)
Net amortization and deferral (160) 84 (38)
------------------------------------------------------------------------------
Net pension cost $ (20) $ (8) $ -
==============================================================================
Net pension costs were negative in 1994 and 1993. Of net pension costs
recorded, $15 million in 1994 and $6 million in 1993, were recorded as a
reduction to operating expense, with the balance being recorded as a reduction
to construction and other accounts.
Postretirement Medical
===============================================================================
1994 1993
--------------
(in millions)
Benefits earned during the year $ 13 $ 11
Interest cost on accumulated
benefit obligation 27 23
Amortization of transition
obligation over 20 years 12 12
Actual (return) loss on plan assets 1 (4)
Net amortization and deferral (3) 2
-------------------------------------------------------------------------------
Net postretirement cost $ 50 $ 44
===============================================================================
Postretirement Life
===============================================================================
1994 1993
-----------
(in millions)
Benefits earned during the year $ 2 $ 3
Interest cost on accumulated
benefit obligation 6 6
Amortization of transition
obligation over 20 years 3 3
Actual return on plan assets - -
Net amortization and deferral - -
-------------------------------------------------------------------------------
Net postretirement cost $11 $12
===============================================================================
II-115
NOTES (continued)
Georgia Power Company 1994 Annual Report
Of the above net postretirement medical and life insurance costs recorded in
1994, $28 million was charged to operating expenses, $18 million was deferred,
and the remainder was charged to construction and other accounts. In 1993, $21
million was charged to operating expenses, $21 million was 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 the Company's programs were $82 million and $10 million for the
years 1994 and 1992, respectively. Additionally, in 1994, the Company recognized
$8 million for its share of costs associated with SCS's work force reduction
program.
3. LITIGATION AND REGULATORY MATTERS
Demand-Side Conservation Programs
In October 1993, a Superior Court of Fulton County, Georgia, judge ruled that
rate riders previously approved by the GPSC for recovery of the Company's costs
incurred in connection with demand-side conservation programs were unlawful. The
judge held that the GPSC lacked statutory authority to approve such rate riders
except through general rate case proceedings and that those procedures had not
been followed. The Company suspended collection of the demand-side conservation
costs and appealed the court's decision to the Georgia Court of Appeals. In
December 1993, the GPSC approved the Company's request for an accounting order
allowing the Company to defer all current unrecovered and future costs related
to these programs until the superior court's decision is reversed or until the
next general rate case proceedings. An association of industrial customers filed
a petition for review of the accounting order in superior court.
In July 1994, the Georgia Court of Appeals upheld the legality of the rate
riders. In November 1994, the Supreme Court of Georgia denied petitions for
review of this ruling. As a result, the Company resumed collection under the
rate riders in December 1994. In February 1995, the GPSC initiated a true-up
proceeding to review program costs which have been incurred by the Company and
costs expected to be incurred during 1995 in order to adjust the rate riders
accordingly. The proceeding will also address a plan for recovery of costs
deferred under the accounting order. The Company's costs related to these
conservation programs through 1994 were $115 million, of which $18 million has
been collected and the remainder deferred.
The final outcome of this matter cannot now be determined; however, in
management's opinion, the final outcome will not have a material adverse effect
on the Company's financial statements.
Tax Litigation
In June 1994, a tax deficiency notice was received from the Internal Revenue
Service (IRS) for the years 1984 through 1987 with regard to the tax accounting
by the Company 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 $28 million and $32
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 the Company has
filed a petition with the U. S. Tax Court challenging the IRS position. In order
to minimize additional interest charges should the IRS's position prevail, the
Company made a payment to the IRS related to the potential tax deficiency for
the years 1984 through 1987 in September 1994.
The final outcome of this matter cannot now be determined; however, in
management's opinion, the final outcome will not have a material adverse effect
on the Company's financial statements.
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.
II-116
NOTES (continued)
Georgia Power Company 1994 Annual Report
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 is scheduled to continue
until January 1996.
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 $35
million at December 31, 1994. Although the final outcome of this matter cannot
now be determined, in management's opinion, the final outcome will not result in
changes that would have a material adverse effect on the Company's financial
statements.
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 such request is pending before the FERC. 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.
While the outcome of this matter cannot be determined, in management's
opinion, it will not have a material adverse effect on the Company's financial
statements.
Plant Vogtle Phase-In Plans
Pursuant to orders from the GPSC, the Company recorded a deferred return under
phase-in plans for Plant Vogtle Units 1 and 2 until October 1991 when the
allowed investment was fully reflected in rates. In addition, the GPSC issued
two separate accounting orders that required the Company to defer substantially
all operating and financing costs related to both units until rate orders
addressed these costs. These GPSC orders provide for the recovery of deferred
costs within 10 years. The GPSC modified the phase-in plans in 1991 to
accelerate the recognition of costs previously deferred under the Plant Vogtle
Unit 2 phase-in plan and to levelize the remaining Plant Vogtle declining
capacity buyback expenses.
Under these orders, the Company has deferred and amortized these costs (as
recovered through rates) as follows:
=============================================================
1994 1993 1992
---------------------------
(in millions)
Deferred costs at beginning
of year $507 $383 $375
--------------------------------------------------------------
Deferred capacity buyback
expenses 10 38 100
Amortization of previously
deferred costs (85) (74) (69)
Less income taxes - - (23)
--------------------------------------------------------------
Net (amortization) deferral (75) (36) 8
--------------------------------------------------------------
Effect of adoption of FASB
Statement No. 109 - 160 -
--------------------------------------------------------------
Deferred costs at end of year $432 $507 $383
==============================================================
II-117
NOTES (continued)
Georgia Power Company 1994 Annual Report
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
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, 1994,
the remaining amount to be collected was $5 million.
4. COMMITMENTS AND CONTINGENCIES
Rocky Mountain Project Status
In its 1985 financing order, the GPSC concluded that completion of the Rocky
Mountain pumped storage hydroelectric project in 1991 as then planned was not
economically justifiable and reasonable and withheld authorization for the
Company to spend funds from approved securities issuances on that project. In
1988, the Company and OPC entered into a joint ownership agreement for OPC to
assume responsibility for the construction and operation of the project, as
discussed in Note 5. However, full recovery of the Company's costs depends on
the GPSC's treatment of the project's costs and disposition of the project's
capacity output. In the event the GPSC does not allow full recovery of the
project's costs, then the portion not allowed may have to be written off. AFUDC
accrued on the Rocky Mountain project has not been credited to income or
included in the project cost since December 1985. If accrual of AFUDC is not
resumed, the Company's estimated total investment in the project at completion
would be approximately $200 million. The plant is scheduled to begin commercial
operation in 1995.
The ultimate outcome of this matter cannot now be determined.
Construction Program
While the Company has no new baseload generating plants under construction,
the construction of five combustion turbine peaking units is planned to be
completed by 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 $579 million in 1995, $626 million in 1996 and
$724 million in 1997. These estimated additions include AFUDC of $27 million in
1995, $17 million in 1996, and $22 million in 1997. The estimates for property
additions for the three-year period include $92 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 commitments were approximately $4.6 billion at
December 31, 1994. Additional commitments for coal and for nuclear fuel will be
required in the future to supply the Company's fuel needs.
II-118
NOTES (continued)
Georgia Power Company 1994 Annual Report
Operating Leases
The Company has entered into coal rail car rental agreements with various terms
and expiration dates. These expenses totaled $13 million, $8 million, and $7
million for 1994, 1993, and 1992, respectively. At December 31, 1994, estimated
minimum rental commitments for noncancelable operating leases were as follows:
======================================================
Amounts
--------------
Year (in millions)
----
1995 $ 12
1996 11
1997 10
1998 10
1999 10
2000 and thereafter 136
------------------------------------------------------
Total minimum payments $189
======================================================
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. 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. In management's
opinion, however, based upon the nature and extent of the Company's activities
relating to the site, the final outcome will not have a material adverse effect
on the Company's financial statements.
In compliance with the recently enacted Georgia Hazardous Site Response Act,
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 $4 million in expenses
for the anticipated clean-up cost for two sites that the Company plans 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 $3 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 sites were required to be remediated, the Company could incur
expenses of up to approximately $25 million in additional clean-up costs, and
construction expenditures of up to $100 million to develop new waste management
facilities or install additional pollution control devices.
The final outcome of this matter cannot now be determined; however, in
management's opinion, the final outcome will not have a material adverse effect
on the Company's financial statements.
Nuclear Insurance
Under the Price-Anderson Amendments Act of 1988, the Company maintains
agreements of indemnity with the NRC that, together with private insurance,
cover third-party liability arising from any nuclear incident occurring at the
Company's nuclear power plants. The act 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 for the Company -- based on its ownership and
buyback interests -- is $163 million per incident but not more than an aggregate
of $21 million to be paid for each incident in any one year.
II-119
NOTES (continued)
Georgia Power Company 1994 Annual Report
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 $15 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 $25 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.
5. FACILITY SALES AND JOINT OWNERSHIP AGREEMENTS
Since 1975, the Company has sold undivided interests in plants Hatch, Wansley,
Vogtle, and Scherer Units 1 and 2, together with transmission facilities, to
OPC, an electric membership generation and transmission corporation; MEAG, a
public corporation and an instrumentality of the state of Georgia; and the City
of Dalton, Georgia. The Company has sold an interest in Plant Scherer Unit 3 to
Gulf Power, an affiliate.
Additionally, the Company has completed three of four separate transactions
to sell Unit 4 of Plant Scherer to Florida Power & Light Company (FPL) and
Jacksonville Electric Authority (JEA) for a total price of approximately $808
million, including any gains on these transactions. FPL will eventually own
approximately 76.4 percent of the unit, with JEA owning the remainder. Georgia
Power will continue to operate the unit.
The completed and scheduled remaining transactions are as follows:
=============================================================
Closing Percent After-Tax
Date Capacity Ownership Amount Gain
-------------------------------------------------------------
(in megawatts) (in millions)
July 1991 290 35.46% $291 $14
June 1993 258 31.44 253 18
June 1994 135 16.55 133 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 4, the Company and OPC have a joint ownership
arrangement for the Rocky Mountain pumped storage hydroelectric project under
which the Company will retain its present investment in the project and OPC will
II-120
NOTES (continued)
Georgia Power Company 1994 Annual Report
finance and complete the remainder of the project and operate the completed
facility. Based on current cost estimates the Company's ownership will be
approximately 25 percent of the project (194 megawatts of capacity) at
completion.
The Company will own six of eight 80 megawatt combustion turbine generating
units and 75 percent of the related common facilities being jointly constructed
at Plant McIntosh with Savannah Electric, an affiliate. The Company's investment
in the project at December 31, 1994, was $149 million and is expected to total
approximately $182 million when the project is completed. Four of the Company's
six units began commercial operation during 1994, and the remaining two units
are expected to be completed by June, 1995. Savannah Electric will operate these
units.
In 1994, the Company and FPC entered into a joint ownership agreement
regarding a 150 megawatt combustion turbine unit to be constructed near Orlando,
Florida. The unit is scheduled to be in commercial operation in early 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.
In connection with the joint ownership arrangements for plants Vogtle and
Scherer, the Company has made commitments to purchase declining fractions of
OPC's and MEAG's capacity and energy from these units. These commitments are in
effect during periods of up to 10 years following commercial operation (and with
regard to a portion of a 5 percent interest in Plant Vogtle owned by MEAG, until
the latter of the retirement of the plant or the latest stated maturity date of
MEAG's bonds issued to finance such ownership interest). The payments for
capacity are required whether or not any capacity is available. The energy cost
is a function of each unit's variable operating costs. Except as noted below,
the cost of such capacity and energy is included in purchased power from
non-affiliates in the Company's Statements of Income. Capacity payments totaled
$129 million, $183 million and $289 million in 1994, 1993 and 1992,
respectively. The Plant Scherer buyback agreements ended in 1993. The current
projected Plant Vogtle capacity payments for the next five years are as follows:
$77 million in 1995, $70 million in 1996, $59 million in 1997, $59 million in
1998, and $59 million in 1999. Portions of the payments noted above relate to
costs in excess of Plant Vogtle's allowed investment for ratemaking purposes.
The present value of these portions was written off in 1987 and 1990.
Additionally, the Plant Vogtle declining capacity buyback expense is being
levelized over a six-year period. See Note 3 for further information.
At December 31, 1994, 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
Unit 4 818 16.6
Plant McIntosh
Common Facilities N/A 75.0
(combustion-turbine)
=================================================================
Accumulated
Facility (Type) Investment Depreciation
-----------------------------------------------------------------
(in millions)
Plant Vogtle (nuclear) $3,289* $628
Plant Hatch (nuclear) 842 346
Plant Wansley (coal) 287 129
Plant Scherer (coal)
Units 1 and 2 112 36
Unit 3 540 121
Unit 4 119 18
Plant McIntosh
Common Facilities
(combustion-turbine) 17 **
-----------------------------------------------------------------
* Investment net of write-offs.
** Less than $1 million.
II-121
NOTES (continued)
Georgia Power Company 1994 Annual Report
The Company and an affiliate, Alabama Power, own equally all of the
outstanding capital stock of Southern Electric Generating Company (SEGCO), which
owns electric generating units with a total rated capacity of 1,020 megawatts,
as well as associated transmission facilities. The capacity of the units has
been sold equally to the Company and Alabama Power under a contract 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:
============================================================
1994 1993 1992
------------------------------------------------------------
(in millions)
Energy $43 $60 $47
Capacity 33 30 28
------------------------------------------------------------
Total $76 $90 $75
============================================================
Kilowatt-hours 2,429 3,352 2,664
------------------------------------------------------------
At December 31, 1994, 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.
6. LONG-TERM POWER SALES AGREEMENTS
The Company and the operating affiliates of The Southern Company have entered
into long-term contractual agreements for the sale of capacity and energy to
non-affiliated utilities located outside the system's service territory. These
agreements consist of firm unit power sales pertaining to capacity from specific
generating units and non-firm sales 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)
1994 $ 75 403 $ 9 101
1993 135 830 17 200
1992 223 1,363 10 124
Long-term non-firm power of 200 megawatts was sold by the Southern electric
system in 1994 to FPC, of which the Company's share was 101 megawatts, under a
contract that expired at year-end. Sales under these long-term non-firm power
sales agreements are made from available power pool energy, and the revenues
from the sales are shared by the operating affiliates.
Unit power from specific generating plants is being sold to FPL, JEA, and
the City of Tallahassee, Florida and beginning in 1994 to FPC. Under these
agreements, the Company sold approximately 403 megawatts of capacity in 1994 and
is scheduled to sell approximately 248 megawatts of capacity in 1995.
Thereafter, these sales will decline to an estimated 172 megawatts in 1996 then
will remain at an approximate level of 158 megawatts through 1999. After 2000,
capacity sales will decline to approximately 102 megawatts -- unless reduced by
FPL, FPC, and JEA -- until the expiration of the contracts in 2010.
II-122
NOTES (continued)
Georgia Power Company 1994 Annual Report
7. 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, 1994, the tax-related regulatory assets were $920 million and
the tax-related regulatory liabilities were $433 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:
==============================================================
1994 1993 1992
---------------------------
Total provision for income taxes: (in millions)
Federal:
Currently payable $306 $223 $139
Deferred -
Current year 86 181 170
Reversal of prior years (57) (40) (6)
Deferred investment tax
credits (1) (18) (6)
--------------------------------------------------------------
334 346 297
--------------------------------------------------------------
State:
Currently payable 52 41 24
Deferred -
Current year 15 31 35
Reversal of prior years (10) (3) (3)
--------------------------------------------------------------
57 69 56
--------------------------------------------------------------
Total 391 415 353
--------------------------------------------------------------
Less:
Income taxes charged
(credited) to other income (8) (37) (25)
--------------------------------------------------------------
Federal and state income
taxes charged to operations $399 $452 $378
==============================================================
The tax effects of temporary differences between the carrying amounts of
assets and liabilities in the financial statements and their respective tax
basis, which give rise to deferred tax assets and liabilities are as follows:
===============================================================
1994 1993
-----------------
(in millions)
Deferred tax liabilities:
Accelerated depreciation $1,541 $1,458
Property basis differences 1,085 1,163
Deferred Plant Vogtle costs 141 161
Premium on reacquired debt 68 63
Deferred regulatory costs 48 24
Fuel clause underrecovered 9 32
Other 23 38
---------------------------------------------------------------
Total 2,915 2,939
---------------------------------------------------------------
Deferred tax assets:
Other property basis differences 250 263
Federal effect of state deferred taxes 94 92
Other deferred costs 79 61
Disallowed Plant Vogtle buybacks 26 29
Accrued interest 10 24
Other 13 12
---------------------------------------------------------------
Total 472 481
---------------------------------------------------------------
Net deferred tax liabilities 2,443 2,458
Portion included in current assets 35 22
---------------------------------------------------------------
Accumulated deferred income taxes
in the Balance Sheets $2,478 $2,480
===============================================================
Deferred investment tax credits are amortized over the life of the related
property with such amortization normally applied as a credit to reduce
depreciation in the Statements of Income. Credits amortized in this manner
amounted to $25 million in 1994, $19 million in 1993, and $19 million in 1992.
At December 31, 1994, all investment tax credits available to reduce federal
income taxes payable had been utilized.
II-123
NOTES (continued)
Georgia Power Company 1994 Annual Report
A reconciliation of the federal statutory tax rate to the effective income
tax rate is as follows:
=============================================================
1994 1993 1992
------------------------
Federal statutory rate 35% 35% 34%
State income tax, net of
federal deduction 4 4 4
Non-deductible book
depreciation 3 3 3
Difference in prior years'
deferred and current tax rate (1) (1) (1)
Other - (1) (2)
-------------------------------------------------------------
Effective income tax rate 41% 40% 38%
=============================================================
The Southern Company and its subsidiaries file a consolidated federal income
tax return. Under a joint consolidated income tax agreement, each company's
current and deferred tax expense is computed on a stand-alone basis, and
consolidated tax savings are allocated to each company based on its ratio of
taxable income to total consolidated taxable income.
8. CAPITALIZATION
Common Stock Dividend Restrictions
The Company's first mortgage bond indenture contains various common stock
dividend restrictions that remain in effect as long as the bonds are
outstanding. At December 31, 1994, $742 million of retained earnings were
restricted against the payment of cash dividends on common stock under terms of
the mortgage indenture. Supplemental indentures in connection with future first
mortgage bond issues may contain more stringent common stock dividend
restrictions than those currently in effect.
The Company's charter limits cash dividends on common stock to the lesser of
the retained earnings balance or 75 percent of net income available for such
stock during a prior period of 12 months if the ratio of common stock equity to
total capitalization, including retained earnings, adjusted to reflect the
payment of the proposed dividend, is below 25 percent, and to 50 percent of such
net income if such ratio is less than 20 percent. At December 31, 1994, the
ratio as defined was 47.3 percent.
Preferred Securities
Georgia Power Capital, a limited partnership, was formed November 10, 1994, for
the purpose of issuing preferred securities and subsequently lending the
proceeds to the Company. In December 1994, Georgia Power Capital issued four
million shares of preferred securities at 9 percent and subsequently loaned the
proceeds of $100 million to the Company. This subordinated debt of the Company
is due December 19, 2024.
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 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 $651 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 1994 1993
------------------------------------------------------------
(in millions)
2004 5.70% $ 39 $ 39
2005-2008 5.375% to 6.75% 59 59
2011-2014 11.75% & Variable 10 477
2015-2019 6.00% to 10.60%
& Variable 786 830
2021-2024 5.40% to 7.25% &
Variable 784 256
------------------------------------------------------------
Total pollution control bonds $1,678 $1,661
============================================================
Bank Credit Arrangements
At the beginning of 1995, the Company had unused credit arrangements with banks
totaling $709 million, of which $268 million expires at various times during
1995, $41 million expires at May 1, 1997, and $400 million expires at June 30,
1997.
II-124
NOTES (continued)
Georgia Power Company 1994 Annual Report
The $400 million expiring June 30, 1997, is under revolving credit
arrangements with several banks providing the Company, Alabama Power, and The
Southern Company up to a total credit amount of $400 million. To provide
liquidity support for commercial paper programs and for other short-term cash
needs, $165 million and $135 million of the $400 million available credit are
currently dedicated for the Company and Alabama Power, respectively. However,
the allocations can be changed among the borrowers by notifying the respective
banks.
During the term of the agreements expiring in 1997, 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 $709 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, 1994, is
$219 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 1994.
Other Long-Term Debt
Assets acquired under capital leases are recorded in the Balance Sheets as
utility plant in service, and the related obligations are classified as
long-term debt. At December 31, 1994 and 1993, the Company had a capitalized
lease obligation for its corporate headquarters building of $88 million with an
interest rate of 8.1 percent. The maturity of this capital lease obligation
through 1999 is approximately as follows: $310 thousand in 1995, $336 thousand
in 1996, $365 thousand in 1997, $395 thousand in 1998, and $429 thousand in
1999.
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, 1994, and 1993, the interest and lease
amortization deferred on the Balance Sheets are $48 million and $47 million,
respectively.
In December 1993, the Company borrowed $37 million through a long-term note
due in 1995.
Assets Subject to Lien
The Company's mortgage dated as of March 1, 1941, as amended and supplemented,
securing the first mortgage bonds issued by the Company, constitutes a direct
lien on substantially all of the Company's fixed property and franchises.
Long-Term Debt Due Within One Year
The current portion of the Company's long-term debt is as follows:
================================================================
1994 1993
--------------
(in millions)
First mortgage bond maturity $130 $ -
Other long-term debt 37 11
----------------------------------------------------------------
Total $167 $11
================================================================
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 or reacquired bonds, or
by pledging additional property equal to 1 2/3 times the requirement. The 1994
requirement was funded in December 1993. The 1995 requirement of $23 million
II-125
NOTES (continued)
Georgia Power Company 1994 Annual Report
will be satisfied 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.
9. QUARTERLY FINANCIAL DATA (UNAUDITED)
Summarized quarterly financial information for 1994 and 1993 is as follows:
==================================================================
Net Income
After
Dividends on
Operating Operating Preferred
Quarter Ended Revenues Income Stock
------------------------------------------------------------------
(in millions)
March 1994 $ 992 $157 $ 58
June 1994 1,030 227 140
September 1994 1,213 331 233
December 1994 927 179 95
March 1993 $1,004 $221 $108
June 1993 1,096 219 141
September 1993 1,376 356 245
December 1993 975 176 76
------------------------------------------------------------------
Earnings in 1994 declined by $55 million as a result of work force
reduction programs. Of this amount, $52 million was recorded in the first
quarter of 1994.
The Company's business is influenced by seasonal weather
conditions.
II-126
SELECTED FINANCIAL AND OPERATING DATA
Georgia Power Company 1994 Annual Report
===================================================================================================
1994 1993 1992
---------------------------------------------------------------------------------------------------
Operating Revenues (in thousands) $4,162,403 $4,451,181 $4,297,436
Net Income after Dividends
on Preferred Stock (in thousands) $525,544 $569,853 $520,538
Cash Dividends on Common Stock (in thousands) $429,300 $402,400 $384,000
Return on Average Common Equity (percent) 12.84 14.37 13.60
Total Assets (in thousands) $13,712,658 $13,736,110 $10,964,442
Gross Property Additions (in thousands) $638,426 $674,432 $508,444
---------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $4,141,554 $4,045,458 $3,888,237
Preferred stock 692,787 692,787 692,792
Preferred stock subject to mandatory redemption - - 6,250
Preferred securities of subsidiary 100,000 - -
Long-term debt 3,757,823 4,031,387 4,131,016
---------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $8,692,164 $8,769,632 $8,718,295
===================================================================================================
Capitalization Ratios (percent):
Common stock equity 47.6 46.1 44.6
Preferred stock 8.0 7.9 8.0
Preferred securities of subsidiary 1.2 - -
Long-term debt 43.2 46.0 47.4
---------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0 100.0
===================================================================================================
First Mortgage Bonds (in thousands):
Issued - 1,135,000 975,000
Retired 133,559 1,337,822 1,381,300
Preferred Stock (in thousands):
Issued - 175,000 195,000
Retired - 245,005 165,004
Preferred Securities of subsidiary (in thousands):
Issued 100,000 - -
Retired - - -
---------------------------------------------------------------------------------------------------
Security Ratings:
First Mortgage Bonds -
Moody's A2 A3 A3
Standard and Poor's A A- A-
Duff & Phelps A+ A+ A-
Preferred Stock -
Moody's a3 baa1 baa1
Standard and Poor's A- BBB+ BBB+
Duff & Phelps A- A- BBB
---------------------------------------------------------------------------------------------------
Customers (year-end):
Residential 1,466,382 1,441,972 1,421,175
Commercial 193,648 188,820 183,784
Industrial 10,976 11,217 11,479
Other 2,426 2,322 2,269
---------------------------------------------------------------------------------------------------
Total 1,673,432 1,644,331 1,618,707
===================================================================================================
Employees (year-end) 11,765 12,528 12,600
II-127
SELECTED FINANCIAL AND OPERATING DATA
Georgia Power Company 1994 Annual Report
===================================================================================================
1991 1990 1989
---------------------------------------------------------------------------------------------------
Operating Revenues (in thousands) $4,301,428 $4,445,809 $4,145,240
Net Income after Dividends
on Preferred Stock (in thousands) $474,855 $208,066 $449,099
Cash Dividends on Common Stock (in thousands) $375,200 $389,600 $394,500
Return on Average Common Equity (percent) 12.76 5.52 11.72
Total Assets (in thousands) $10,842,538 $11,176,619 $11,372,346
Gross Property Additions (in thousands) $548,051 $558,727 $727,631
---------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $3,766,551 $3,673,913 $3,860,657
Preferred stock 607,796 607,796 607,844
Preferred stock subject to mandatory redemption 118,750 125,000 155,000
Preferred securities of subsidiary - - -
Long-term debt 4,553,189 5,000,225 5,054,001
---------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $9,046,286 $9,406,934 $9,677,502
===================================================================================================
Capitalization Ratios (percent):
Common stock equity 41.7 39.1 39.9
Preferred stock 8.0 7.8 7.9
Preferred securities of subsidiary - - -
Long-term debt 50.3 53.1 52.2
---------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0 100.0
===================================================================================================
First Mortgage Bonds (in thousands):
Issued - 300,000 250,000
Retired 598,384 91,117 91,516
Preferred Stock (in thousands):
Issued 100,000 - -
Retired 100,000 83,750 7,500
Preferred Securities of subsidiary (in thousands):
Issued - - -
Retired - - -
---------------------------------------------------------------------------------------------------
Security Ratings:
First Mortgage Bonds -
Moody's Baa1 Baa1 Baa2
Standard and Poor's BBB+ BBB+ BBB+
Duff & Phelps BBB+ BBB BBB
Preferred Stock -
Moody's baa1 baa1 baa2
Standard and Poor's BBB BBB BBB
Duff & Phelps BBB- BBB- BBB-
---------------------------------------------------------------------------------------------------
Customers (year-end):
Residential 1,397,682 1,378,888 1,355,211
Commercial 179,933 178,391 177,814
Industrial 11,946 12,115 12,311
Other 2,190 2,114 2,050
---------------------------------------------------------------------------------------------------
Total 1,591,751 1,571,508 1,547,386
===================================================================================================
Employees (year-end) 13,700 13,746 13,900
II-128A
SELECTED FINANCIAL AND OPERATING DATA
Georgia Power Company 1994 Annual Report
===================================================================================================
1988 1987 1986
---------------------------------------------------------------------------------------------------
Operating Revenues (in thousands) $3,897,479 $3,786,485 $3,561,603
Net Income after Dividends
on Preferred Stock (in thousands) $479,532 $240,057 $535,003
Cash Dividends on Common Stock (in thousands) $386,600 $377,800 $325,500
Return on Average Common Equity (percent) 13.06 6.85 16.51
Total Assets (in thousands) $11,130,539 $11,197,494 $10,465,063
Gross Property Additions (in thousands) $929,019 $1,034,059 $1,598,309
---------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $3,806,070 $3,538,182 $3,469,201
Preferred stock 657,844 657,844 732,844
Preferred stock subject to mandatory redemption 162,500 166,250 112,500
Preferred securities of subsidiary - - -
Long-term debt 4,861,378 4,825,760 4,464,857
---------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $9,487,792 $9,188,036 $8,779,402
===================================================================================================
Capitalization Ratios (percent):
Common stock equity 40.1 38.5 39.5
Preferred stock 8.6 9.0 9.6
Preferred securities of subsidiary - - -
Long-term debt 51.3 52.5 50.9
---------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0 100.0
===================================================================================================
First Mortgage Bonds (in thousands):
Issued 150,000 500,000 500,000
Retired 206,677 217,949 377,538
Preferred Stock (in thousands):
Issued - 125,000 100,000
Retired 3,750 150,000 7,500
Preferred Securities of subsidiary (in thousands):
Issued - - -
Retired - - -
---------------------------------------------------------------------------------------------------
Security Ratings:
First Mortgage Bonds -
Moody's Baa2 Baa2 Baa1
Standard and Poor's BBB BBB BBB+
Duff & Phelps 9 9 9
Preferred Stock -
Moody's baa2 baa2 baa1
Standard and Poor's BBB- BBB- BBB
Duff & Phelps 10 10 10
---------------------------------------------------------------------------------------------------
Customers (year-end):
Residential 1,329,173 1,303,721 1,268,983
Commercial 174,147 169,014 162,258
Industrial 12,353 12,307 12,315
Other 1,993 1,858 1,816
---------------------------------------------------------------------------------------------------
Total 1,517,666 1,486,900 1,445,372
===================================================================================================
Employees (year-end) 15,110 14,924 14,773
II-128B
SELECTED FINANCIAL AND OPERATING DATA
Georgia Power Company 1994 Annual Report
======================================================================================
1985 1984
--------------------------------------------------------------------------------------
Operating Revenues (in thousands) $3,609,140 $3,319,699
Net Income after Dividends
on Preferred Stock (in thousands) $493,717 $421,719
Cash Dividends on Common Stock (in thousands) $277,500 $225,500
Return on Average Common Equity (percent) 17.95 18.43
Total Assets (in thousands) $9,030,618 $7,880,072
Gross Property Additions (in thousands) $1,384,182 $1,396,846
--------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $3,013,707 $2,486,172
Preferred stock 632,844 482,844
Preferred stock subject to mandatory redemption 120,000 127,500
Preferred securities of subsidiary - -
Long-term debt 3,878,066 3,432,606
--------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $7,644,617 $6,529,122
======================================================================================
Capitalization Ratios (percent):
Common stock equity 39.4 38.1
Preferred stock 9.9 9.3
Preferred securities of subsidiary - -
Long-term debt 50.7 52.6
--------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0
======================================================================================
First Mortgage Bonds (in thousands):
Issued - 150,000
Retired 17,738 26,084
Preferred Stock (in thousands):
Issued 150,000 50,000
Retired 3,750
Preferred Securities of subsidiary (in thousands):
Issued - -
Retired - -
--------------------------------------------------------------------------------------
Security Ratings:
First Mortgage Bonds -
Moody's Baa1 Baa1
Standard and Poor's BBB+ BBB+
Duff & Phelps 9 8
Preferred Stock -
Moody's baa1 baa1
Standard and Poor's BBB BBB
Duff & Phelps 10 9
--------------------------------------------------------------------------------------
Customers (year-end):
Residential 1,231,140 1,189,670
Commercial 155,399 148,536
Industrial 12,309 12,276
Other 1,789 1,753
--------------------------------------------------------------------------------------
Total 1,400,637 1,352,235
======================================================================================
Employees (year-end) 14,947 14,562
II-128C
SELECTED FINANCIAL AND OPERATING DATA (continued)
Georgia Power Company 1994 Annual Report
===================================================================================================
1994 1993 1992
---------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $1,180,358 $1,291,035 $1,128,396
Commercial 1,367,315 1,354,130 1,285,681
Industrial 1,100,995 1,113,067 1,083,856
Other 42,983 41,399 39,504
---------------------------------------------------------------------------------------------------
Total retail 3,691,651 3,799,631 3,537,437
Sales for resale - non-affiliates 351,591 534,370 640,308
Sales for resale - affiliates 60,899 61,668 67,835
---------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 4,104,141 4,395,669 4,245,580
Other revenues 58,262 55,512 51,856
---------------------------------------------------------------------------------------------------
Total $4,162,403 $4,451,181 $4,297,436
===================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 15,680,709 16,649,859 14,939,172
Commercial 18,738,461 18,278,508 17,260,614
Industrial 24,337,632 23,635,363 22,978,312
Other 484,009 460,801 436,144
---------------------------------------------------------------------------------------------------
Total retail 59,240,811 59,024,531 55,614,242
Sales for resale - non-affiliates 7,968,475 14,307,030 15,870,222
Sales for resale - affiliates 3,056,050 3,027,733 3,320,060
---------------------------------------------------------------------------------------------------
Total 70,265,336 76,359,294 74,804,524
===================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 7.53 7.75 7.55
Commercial 7.30 7.41 7.45
Industrial 4.52 4.71 4.72
Total retail 6.23 6.44 6.36
Sales for resale 3.74 3.44 3.69
Total sales 5.84 5.76 5.68
Residential Average Annual Kilowatt-Hour Use Per Customer 10,766 11,630 10,603
Residential Average Annual Revenue Per Customer $810.39 $901.79 $800.88
Plant Nameplate Capacity Ratings (year-end) (megawatts) 13,943 13,759 14,076
Maximum Peak-Hour Demand (megawatts) (Note):
Winter 10,509 9,067 8,938
Summer 11,758 12,573 11,448
Annual Load Factor (percent) 63.0 58.5 60.5
Plant Availability (percent):
Fossil-steam 83.1 85.9 86.6
Nuclear 88.4 85.5 87.7
---------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 61.3 62.1 61.4
Nuclear 18.0 16.2 17.0
Hydro 2.6 2.3 2.5
Oil and gas 0.1 0.2 *
Purchased power -
From non-affiliates 9.7 10.2 12.2
From affiliates 8.3 9.0 6.9
---------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0
===================================================================================================
Total Fuel Economy Data:
BTU per net kilowatt-hour generated 9,915 9,912 9,900
Cost of fuel per million BTU (cents) 145.33 153.62 153.08
Average cost of fuel per net kilowatt-hour generated (cents) 1.44 1.52 1.52
===================================================================================================
Note: As of 9/1/91, Georgia Power Company's sales to Oglethorpe Power Company are not included in Peak-Hour Demand.
* Less than one-tenth of one percent.
II-129
SELECTED FINANCIAL AND OPERATING DATA (continued)
Georgia Power Company 1994 Annual Report
===================================================================================================
1991 1990 1989
---------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $1,111,358 $1,109,165 $1,022,781
Commercial 1,243,067 1,218,441 1,143,727
Industrial 1,057,702 1,061,830 1,006,416
Other 37,861 36,773 34,775
---------------------------------------------------------------------------------------------------
Total retail 3,449,988 3,426,209 3,207,699
Sales for resale - non-affiliates 736,643 784,086 760,809
Sales for resale - affiliates 65,586 168,251 150,394
---------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 4,252,217 4,378,546 4,118,902
Other revenues 49,211 67,263 26,338
---------------------------------------------------------------------------------------------------
Total $4,301,428 $4,445,809 $4,145,240
===================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 14,815,089 14,771,648 14,134,195
Commercial 16,885,833 16,627,128 15,843,181
Industrial 22,298,062 22,126,604 21,801,404
Other 429,016 428,459 414,107
---------------------------------------------------------------------------------------------------
Total retail 54,428,000 53,953,839 52,192,887
Sales for resale - non-affiliates 18,719,924 20,158,681 20,479,412
Sales for resale - affiliates 3,885,892 8,272,528 7,489,948
---------------------------------------------------------------------------------------------------
Total 77,033,816 82,385,048 80,162,247
===================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 7.50 7.51 7.24
Commercial 7.36 7.33 7.22
Industrial 4.74 4.80 4.62
Total retail 6.34 6.35 6.15
Sales for resale 3.55 3.35 3.26
Total sales 5.52 5.31 5.14
Residential Average Annual Kilowatt-Hour Use Per Customer 10,675 10,795 10,530
Residential Average Annual Revenue Per Customer $800.78 $810.56 $761.96
Plant Nameplate Capacity Ratings (year-end) (megawatts) 14,076 14,366 14,366
Maximum Peak-Hour Demand (megawatts) (Note):
Winter 10,001 8,977 10,101
Summer 13,090 13,196 12,735
Annual Load Factor (percent) 55.2 55.5 56.3
Plant Availability (percent):
Fossil-steam 93.3 92.5 93.0
Nuclear 81.6 81.3 89.2
---------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 63.6 65.1 64.0
Nuclear 15.3 13.7 14.1
Hydro 2.3 2.2 2.1
Oil and gas * 0.1 0.1
Purchased power -
From non-affiliates 10.3 11.0 10.2
From affiliates 8.5 7.9 9.5
---------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0
===================================================================================================
Total Fuel Economy Data:
BTU per net kilowatt-hour generated 9,960 9,939 10,020
Cost of fuel per million BTU (cents) 157.97 166.22 164.27
Average cost of fuel per net kilowatt-hour generated (cents) 1.57 1.65 1.65
===================================================================================================
Note: As of 9/1/91, Georgia Power Company's sales to Oglethorpe Power Company are not included in Peak-Hour Demand.
*Less than one-tenth of one percent.
II-130A
SELECTED FINANCIAL AND OPERATING DATA (continued)
Georgia Power Company 1994 Annual Report
===================================================================================================
1988 1987 1986
---------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $979,047 $904,218 $874,231
Commercial 1,054,995 915,540 854,755
Industrial 983,822 911,933 897,646
Other 31,743 29,350 27,948
---------------------------------------------------------------------------------------------------
Total retail 3,049,607 2,761,041 2,654,580
Sales for resale - non-affiliates 707,076 822,696 780,049
Sales for resale - affiliates 86,751 159,998 91,753
---------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 3,843,434 3,743,735 3,526,382
Other revenues 54,045 42,750 35,221
---------------------------------------------------------------------------------------------------
Total $3,897,479 $3,786,485 $3,561,603
===================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 13,800,038 13,675,730 13,234,248
Commercial 14,790,561 13,799,379 12,945,926
Industrial 21,412,845 20,884,454 20,339,235
Other 397,669 385,514 381,917
---------------------------------------------------------------------------------------------------
Total retail 50,401,113 48,745,077 46,901,326
Sales for resale - non-affiliates 18,544,705 20,910,185 18,198,186
Sales for resale - affiliates 3,327,814 6,032,889 3,160,242
---------------------------------------------------------------------------------------------------
Total 72,273,632 75,688,151 68,259,754
===================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 7.09 6.61 6.61
Commercial 7.13 6.63 6.60
Industrial 4.59 4.37 4.41
Total retail 6.05 5.66 5.66
Sales for resale 3.63 3.65 4.08
Total sales 5.32 4.95 5.17
Residential Average Annual Kilowatt-Hour Use Per Customer 10,484 10,623 10,577
Residential Average Annual Revenue Per Customer $743.82 $702.36 $698.72
Plant Nameplate Capacity Ratings (year-end) (megawatts) 13,018 13,018 11,875
Maximum Peak-Hour Demand (megawatts) (Note):
Winter 9,866 9,446 10,551
Summer 12,295 12,390 11,910
Annual Load Factor (percent) 59.1 56.1 57.5
Plant Availability (percent):
Fossil-steam 94.5 92.7 91.2
Nuclear 69.4 85.4 64.7
---------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 72.0 70.9 74.6
Nuclear 9.6 9.1 5.0
Hydro 1.2 1.7 1.2
Oil and gas 0.1 0.1 0.6
Purchased power -
From non-affiliates 8.2 8.5 8.9
From affiliates 8.9 9.7 9.7
---------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0
===================================================================================================
Total Fuel Economy Data:
BTU per net kilowatt-hour generated 9,969 9,932 10,016
Cost of fuel per million BTU (cents) 166.28 168.81 175.81
Average cost of fuel per net kilowatt-hour generated (cents) 1.66 1.68 1.76
===================================================================================================
Note: As of 9/1/91, Georgia Power Company's sales to Oglethorpe Power Company are not included in Peak-Hour Demand.
* Less than one-tenth of one percent.
II-130B
SELECTED FINANCIAL AND OPERATING DATA (continued)
Georgia Power Company 1994 Annual Report
======================================================================================
1985 1984
--------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $786,500 $754,163
Commercial 797,540 739,035
Industrial 873,554 858,536
Other 26,766 24,388
--------------------------------------------------------------------------------------
Total retail 2,484,360 2,376,122
Sales for resale - non-affiliates 941,743 779,028
Sales for resale - affiliates 149,463 136,047
--------------------------------------------------------------------------------------
Total revenues from sales of electricity 3,575,566 3,291,197
Other revenues 33,574 28,502
--------------------------------------------------------------------------------------
Total $3,609,140 $3,319,699
======================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 12,006,462 11,548,787
Commercial 11,945,938 10,902,163
Industrial 19,517,543 18,862,531
Other 382,238 342,047
--------------------------------------------------------------------------------------
Total retail 43,852,181 41,655,528
Sales for resale - non-affiliates 21,526,865 19,138,575
Sales for resale - affiliates 5,999,834 4,970,928
--------------------------------------------------------------------------------------
Total 71,378,880 65,765,031
======================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 6.55 6.53
Commercial 6.68 6.78
Industrial 4.48 4.55
Total retail 5.67 5.70
Sales for resale 3.96 3.80
Total sales 5.01 5.00
Residential Average Annual Kilowatt-Hour Use Per Customer 9,923 9,855
Residential Average Annual Revenue Per Customer $650.01 $643.53
Plant Nameplate Capacity Ratings (year-end) (megawatts) 11,875 11,767
Maximum Peak-Hour Demand (megawatts) (Note):
Winter 10,049 8,462
Summer 11,079 10,443
Annual Load Factor (percent) 56.3 56.9
Plant Availability (percent):
Fossil-steam 91.2 91.0
Nuclear 79.5 47.3
--------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 72.7 74.4
Nuclear 6.7 4.0
Hydro 1.5 2.7
Oil and gas * *
Purchased power -
From non-affiliates 9.4 9.2
From affiliates 9.7 9.7
--------------------------------------------------------------------------------------
Total 100.0 100.0
======================================================================================
Total Fuel Economy Data:
BTU per net kilowatt-hour generated 10,089 10,002
Cost of fuel per million BTU (cents) 178.11 184.63
Average cost of fuel per net kilowatt-hour generated (cents) 1.80 1.85
Note: As of 9/1/91, Georgia Power Company's sales to Oglethorpe Power Company are not included in Peak-Hour Demand.
* Less than one-tenth of one percent.
II-130C
STATEMENTS OF INCOME
Georgia Power Company
====================================================================================================
For the Years Ended December 31, 1994 1993 1992
----------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Operating Revenues:
Revenues $4,101,504 $4,389,513 $4,229,601
Revenues from affiliates 60,899 61,668 67,835
----------------------------------------------------------------------------------------------------
Total operating revenues 4,162,403 4,451,181 4,297,436
----------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
Fuel 870,653 951,507 929,780
Purchased power from non-affiliates 193,130 313,170 436,761
Purchased power from affiliates 158,063 194,024 158,306
Provision for separation benefits 82,238 - 9,778
Proceeds from settlement of disputed contracts - - (4,982)
Other 643,375 675,284 616,116
Maintenance 272,818 284,521 264,757
Depreciation and amortization 379,158 379,425 375,460
Deferred Plant Vogtle expenses, net 74,888 36,284 (30,804)
Taxes other than income taxes 194,566 192,671 179,460
Federal and state income taxes 399,413 452,122 377,542
----------------------------------------------------------------------------------------------------
Total operating expenses 3,268,302 3,479,008 3,312,174
----------------------------------------------------------------------------------------------------
Operating Income 894,101 972,173 985,262
Other Income (Expense):
Allowance for equity funds used during construction 5,663 3,168 5,855
Income from subsidiary 3,588 4,127 4,635
Deferred return on Plant Vogtle - - -
Write-off of Plant Vogtle costs - - -
Income tax reduction for write-off of Plant Vogtle costs - - -
Interest income 3,254 3,806 12,475
Other, net (See note) 10,626 11,902 (30,527)
Income taxes applicable to other income 7,975 37,661 25,163
----------------------------------------------------------------------------------------------------
Income Before Interest Charges 925,207 1,032,837 1,002,863
----------------------------------------------------------------------------------------------------
Interest Charges:
Interest on long-term debt 306,473 343,634 402,541
Allowance for debt funds used during construction (11,571) (8,271) (8,310)
Interest on interim obligations 17,529 15,530 9,694
Amortization of debt discount, premium, and expense, net 15,743 14,024 8,033
Other interest charges 23,483 47,393 12,425
----------------------------------------------------------------------------------------------------
Net interest charges 351,657 412,310 424,383
----------------------------------------------------------------------------------------------------
Net Income 573,550 620,527 578,480
Dividends on Preferred Stock 48,006 50,674 57,942
----------------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred Stock $ 525,544 $ 569,853 $ 520,538
====================================================================================================
Note: Reflects major sales of facilities to JEA, FP&L, OPC, MEAG, and Dalton.
Increases in net income, after total taxes, from these sales were $11,275,000 in 1994, $23,191,000 in 1993, $14,542,000 in 1991,
$6,336,000 in 1990, $3,851,000 in 1987, and $21,250,000 in 1984.
II-131
STATEMENTS OF INCOME
Georgia Power Company
===============================================================================================================
For the Years Ended December 31, 1991 1990 1989 1988
---------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Operating Revenues:
Revenues $4,235,842 $4,277,558 $3,994,846 $3,810,728
Revenues from affiliates 65,586 168,251 150,394 86,751
---------------------------------------------------------------------------------------------------------------
Total operating revenues 4,301,428 4,445,809 4,145,240 3,897,479
---------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
Fuel 998,701 1,120,933 1,078,586 1,023,173
Purchased power from non-affiliates 444,920 626,989 543,448 546,511
Purchased power from affiliates 193,114 173,716 195,355 164,873
Provision for separation benefits 52,952 - - -
Proceeds from settlement of disputed contracts (142,183) - - -
Other 596,565 524,665 504,743 541,975
Maintenance 295,012 280,304 233,680 246,877
Depreciation and amortization 382,549 380,394 346,091 306,492
Deferred Plant Vogtle expenses, net 16,008 31,146 (39,211) (8,333)
Taxes other than income taxes 172,893 151,124 128,518 146,759
Federal and state income taxes 349,284 270,561 273,287 204,222
---------------------------------------------------------------------------------------------------------------
Total operating expenses 3,359,815 3,559,832 3,264,497 3,172,549
---------------------------------------------------------------------------------------------------------------
Operating Income 941,613 885,977 880,743 724,930
Other Income (Expense):
Allowance for equity funds used during construction 9,083 6,985 40,525 96,530
Income from subsidiary 4,576 4,182 3,750 3,302
Deferred return on Plant Vogtle 34,549 82,721 48,096 107,310
Write-off of Plant Vogtle costs - (281,254) - -
Income tax reduction for write-off of Plant Vogtle costs - 63,231 - -
Interest income 10,563 7,552 10,333 28,445
Other, net (See note) 13,551 (21,199) (20,603) (3,746)
Income taxes applicable to other income (7,522) 20,859 15,573 6,583
---------------------------------------------------------------------------------------------------------------
Income Before Interest Charges 1,006,413 769,054 978,417 963,354
---------------------------------------------------------------------------------------------------------------
Interest Charges:
Interest on long-term debt 459,184 480,174 475,991 471,897
Allowance for debt funds used during construction (10,385) (9,325) (34,244) (95,818)
Interest on interim obligations 4,906 8,512 1,059 15,084
Amortization of debt discount, premium, and expense, net 6,214 6,100 5,865 5,466
Other interest charges 9,938 9,404 8,868 14,556
---------------------------------------------------------------------------------------------------------------
Net interest charges 469,857 494,865 457,539 411,185
---------------------------------------------------------------------------------------------------------------
Net Income 536,556 274,189 520,878 552,169
Dividends on Preferred Stock 61,701 66,123 71,779 72,637
---------------------------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred Stock $ 474,855 $ 208,066 $ 449,099 $ 479,532
===============================================================================================================
Note: Reflects major sales of facilities to JEA, FP&L, OPC, MEAG, and Dalton.
Increases in net income, after total taxes, from these sales were $11,275,000 in 1994, $23,191,000 in 1993, $14,542,000 in 1991,
$6,336,000 in 1990, $3,851,000 in 1987, and $21,250,000 in 1984.
II-132A
STATEMENTS OF INCOME
Georgia Power Company
===============================================================================================================
For the Years Ended December 31, 1987 1986 1985 1984
---------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Operating Revenues:
Revenues $3,626,487 $3,469,850 $3,459,677 $3,183,652
Revenues from affiliates 159,998 91,753 149,463 136,047
---------------------------------------------------------------------------------------------------------------
Total operating revenues 3,786,485 3,561,603 3,609,140 3,319,699
---------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
Fuel 1,064,552 1,012,949 1,077,092 1,000,434
Purchased power from non-affiliates 530,051 344,708 415,406 427,403
Purchased power from affiliates 199,831 192,297 204,848 188,938
Provision for separation benefits - - - -
Proceeds from settlement of disputed contracts - - - -
Other 575,182 513,974 482,468 412,803
Maintenance 274,672 275,533 254,510 228,377
Depreciation and amortization 254,929 215,763 201,524 191,205
Deferred Plant Vogtle expenses, net (141,977) - - -
Taxes other than income taxes 143,289 119,768 120,320 106,908
Federal and state income taxes 250,093 319,374 311,151 268,654
---------------------------------------------------------------------------------------------------------------
Total operating expenses 3,150,622 2,994,366 3,067,319 2,824,722
---------------------------------------------------------------------------------------------------------------
Operating Income 635,863 567,237 541,821 494,977
Other Income (Expense):
Allowance for equity funds used during construction 159,414 275,183 227,950 162,057
Income from subsidiary 3,440 2,967 3,417 3,181
Deferred return on Plant Vogtle 115,028 - - -
Write-off of Plant Vogtle costs (357,821) - - -
Income tax reduction for write-off of Plant Vogtle costs 128,923 - - -
Interest income 55,388 44,615 41,546 34,074
Other, net (See note) (55,081) (28,464) (6,815) 45,132
Income taxes applicable to other income 17,344 5,154 (9,114) (37,678)
---------------------------------------------------------------------------------------------------------------
Income Before Interest Charges 702,498 866,692 798,805 701,743
---------------------------------------------------------------------------------------------------------------
Interest Charges:
Interest on long-term debt 480,519 472,744 421,764 351,855
Allowance for debt funds used during construction (130,756) (225,897) (216,233) (150,931)
Interest on interim obligations 16,362 1,954 20,516 13,387
Amortization of debt discount, premium, and expense, net 3,573 2,681 2,335 1,680
Other interest charges 12,239 4,610 10,593 8,416
---------------------------------------------------------------------------------------------------------------
Net interest charges 381,937 256,092 238,975 224,407
---------------------------------------------------------------------------------------------------------------
Net Income 320,561 610,600 559,830 477,336
Dividends on Preferred Stock 80,504 75,597 66,113 55,617
---------------------------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred Stock $ 240,057 $ 535,003 $ 493,717 $ 421,719
===============================================================================================================
Note: Reflects major sales of facilities to JEA, FP&L, OPC, MEAG, and Dalton.
Increases in net income, after total taxes, from these sales were $11,275,000 in 1994, $23,191,000 in 1993, $14,542,000 in 1991,
$6,336,000 in 1990, $3,851,000 in 1987, and $21,250,000 in 1984.
II-132B
STATEMENTS OF CASH FLOWS
Georgia Power Company
==========================================================================================================
For the Years Ended December 31, 1994 1993 1992
----------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Operating Activities:
Net income $ 573,550 $ 620,527 $ 578,480
Adjustments to reconcile net income to net
cash provided by operating activities --
Depreciation and amortization 484,032 475,152 471,014
Deferred income taxes, net 33,567 169,009 194,955
Deferred investment tax credits, net - (18,274) (5,704)
Allowance for equity funds used during construction (5,663) (3,168) (5,855)
Deferred Plant Vogtle costs 74,888 36,284 (30,804)
Write-off of Plant Vogtle costs - - -
Provision for separation benefits 68,599 - -
Non-cash proceeds from settlement of disputed contracts - - (4,982)
Other, net (95,314) (46,227) (9,768)
Changes in certain current assets and liabilities:
Receivables, net 67,218 27,088 (31,348)
Inventories (63,545) 82,433 (65,621)
Payables 5,409 17,364 25,303
Other (5,675) (94,574) (85,961)
----------------------------------------------------------------------------------------------------------
Net cash provided from operating activities 1,137,066 1,265,614 1,029,709
----------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (638,426) (674,432) (508,444)
Sales of property 132,644 261,687 46
Other (41,273) (43,154) 42,892
----------------------------------------------------------------------------------------------------------
Net cash used for investing activities (547,055) (455,899) (465,506)
----------------------------------------------------------------------------------------------------------
Financing Activities and Capital Contributions:
Proceeds:
Preferred securities of subsidiary 100,000 - -
Preferred stock - 175,000 195,000
First mortgage bonds - 1,135,000 975,000
Pollution control bonds 527,210 145,425 161,955
Other long-term debt - 37,000 -
Capital contributions from parent company - - -
Retirements:
Preferred stock - (245,005) (165,004)
First mortgage bonds (133,559) (1,337,822) (1,381,300)
Pollution control bonds (510,320) (145,465) (160,205)
Other long-term debt (10,187) (19,451) (567)
Interim obligations, net (57,425) (51,444) 334,671
Payment of preferred stock dividends (47,147) (53,123) (60,475)
Payment of common stock dividends (429,300) (402,400) (384,000)
Miscellaneous (22,640) (63,648) (70,986)
----------------------------------------------------------------------------------------------------------
Net cash provided from (used for) financing activities (583,368) (825,933) (555,911)
----------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents 6,643 (16,218) 8,292
Cash and Cash Equivalents at Beginning of Year 5,896 22,114 13,822
Cash and Cash Equivalents at End of Year $ 12,539 $ 5,896 $ 22,114
==========================================================================================================
( ) Denotes use of cash.
II-133
STATEMENTS OF CASH FLOWS
Georgia Power Company
========================================================================================================================
For the Years Ended December 31, 1991 1990 1989 1988
------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Operating Activities:
Net income $ 536,556 $ 274,189 $ 520,878 $ 552,169
Adjustments to reconcile net income to net
cash provided by operating activities --
Depreciation and amortization 480,318 502,098 484,870 400,665
Deferred income taxes, net 53,219 88,667 184,490 160,774
Deferred investment tax credits, net (9,524) (52) (8,017) 11,605
Allowance for equity funds used during construction (9,083) (6,985) (40,525) (96,530)
Deferred Plant Vogtle costs (18,541) (51,575) (87,307) (115,643)
Write-off of Plant Vogtle costs - 281,254 - -
Provision for separation benefits - - - -
Non-cash proceeds from settlement of disputed contracts (103,846) - - -
Other, net (26,024) (50,804) (38,046) 6,983
Changes in certain current assets and liabilities:
Receivables, net 23,920 1,444 (59,035) 11,225
Inventories 24,130 (23,498) (33,123) (10,044)
Payables (23,075) (43,470) (38,976) (2,065)
Other 54,777 (9,991) 36,015 1,161
------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities 982,827 961,277 921,224 920,300
------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (548,051) (558,727) (727,631) (929,019)
Sales of property 291,075 34,573 - -
Other 931 1,937 47,260 35,328
------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities (256,045) (522,217) (680,371) (893,691)
------------------------------------------------------------------------------------------------------------------------
Financing Activities and Capital Contributions:
Proceeds:
Preferred securities of subsidiary - - - -
Preferred stock 100,000 - - -
First mortgage bonds - 300,000 250,000 150,000
Pollution control bonds 80,420 - 50,000 69,526
Other long-term debt - - - -
Capital contributions from parent company - - - 175,000
Retirements:
Preferred stock (100,000) (83,750) (7,500) (3,750)
First mortgage bonds (598,384) (91,117) (91,516) (206,677)
Pollution control bonds (83,265) (535) (505) (475)
Other long-term debt (1,130) (114,452) (3,806) (2,878)
Interim obligations, net 199,000 - - (302,261)
Payment of preferred stock dividends (60,766) (67,757) (72,259) (72,931)
Payment of common stock dividends (375,200) (389,600) (394,500) (386,600)
Miscellaneous (17,613) (7,663) (4,742) (13,440)
------------------------------------------------------------------------------------------------------------------------
Net cash provided from (used for) financing activities (856,938) (454,874) (274,828) (594,486)
------------------------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents (130,156) (15,814) (33,975) (567,877)
Cash and Cash Equivalents at Beginning of Year 143,978 159,792 193,767 761,644
Cash and Cash Equivalents at End of Year $ 13,822 $ 143,978 $ 159,792 $ 193,767
========================================================================================================================
( ) Denotes use of cash.
II-134A
STATEMENTS OF CASH FLOWS
Georgia Power Company
========================================================================================================================
For the Years Ended December 31, 1987 1986 1985 1984
------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Operating Activities:
Net income $ 320,561 $ 610,600 $ 559,830 $ 477,336
Adjustments to reconcile net income to net
cash provided by operating activities --
Depreciation and amortization 336,647 260,945 248,256 219,301
Deferred income taxes, net 76,445 236,822 104,102 145,266
Deferred investment tax credits, net (5,075) 106,407 115,144 61,252
Allowance for equity funds used during construction (159,414) (275,183) (227,950) (162,057)
Deferred Plant Vogtle costs (257,005) - - -
Write-off of Plant Vogtle costs 357,821 - - -
Provision for separation benefits - - - -
Non-cash proceeds from settlement of disputed contracts - - - -
Other, net (759) 5,554 34,311 (81,166)
Changes in certain current assets and liabilities:
Receivables, net (6,880) (7,474) (27,928) (68,325)
Inventories (72,540) (26,863) 77,667 (65,772)
Payables 74,341 133,044 (9,182) 161,479
Other 2,751 19,682 21,289 99,191
------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities 666,893 1,063,534 895,539 786,505
------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (1,034,059) (1,598,309) (1,384,182) (1,396,846)
Sales of property 12,276 - - 320,708
Other 45,801 168,518 92,826 82,741
------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities (975,982) (1,429,791) (1,291,356) (993,397)
------------------------------------------------------------------------------------------------------------------------
Financing Activities and Capital Contributions:
Proceeds:
Preferred securities of subsidiary - - - -
Preferred stock 125,000 100,000 150,000 50,000
First mortgage bonds 500,000 500,000 - 150,000
Pollution control bonds 191,736 350,001 500,962 190,577
Other long-term debt - 113,000 - -
Capital contributions from parent company 228,000 250,000 315,000 202,000
Retirements:
Preferred stock (150,000) (7,500) (3,750) (2,380)
First mortgage bonds (217,949) (377,538) (17,738) (26,084)
Pollution control bonds (90,000) - - -
Other long-term debt (2,824) (108) (843) (276)
Interim obligations, net 302,261 (36,715) (72,956) 109,356
Payment of preferred stock dividends (80,420) (73,665) (62,337) (55,433)
Payment of common stock dividends (377,800) (325,500) (277,500) (225,500)
Miscellaneous (51,745) (33,773) (17,503) (17,975)
------------------------------------------------------------------------------------------------------------------------
Net cash provided from (used for) financing activities 376,259 458,202 513,335 374,285
------------------------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents 67,170 91,945 117,518 167,393
Cash and Cash Equivalents at Beginning of Year 694,474 602,529 485,011 317,618
Cash and Cash Equivalents at End of Year $ 761,644 $ 694,474 $ 602,529 $ 485,011
========================================================================================================================
( ) Denotes use of cash.
II-134B
BALANCE SHEETS
Georgia Power Company
===================================================================================================
At December 31, 1994 1993 1992
---------------------------------------------------------------------------------------------------
(Thousands of Dollars)
ASSETS
Electric Plant:
Production-
Fossil $ 3,077,470 $ 2,976,806 $ 3,144,405
Nuclear 4,075,339 4,069,299 4,051,020
Hydro 443,466 442,888 434,341
---------------------------------------------------------------------------------------------------
Total production 7,596,275 7,488,993 7,629,766
Transmission 1,754,945 1,713,122 1,646,904
Distribution 3,777,279 3,600,115 3,413,681
General 926,418 941,291 923,010
Construction work in progress 541,889 584,013 405,606
Nuclear fuel, at amortized cost 136,425 135,742 155,194
---------------------------------------------------------------------------------------------------
Total electric plant 14,733,231 14,463,276 14,174,161
---------------------------------------------------------------------------------------------------
Steam Heat Plant - - -
---------------------------------------------------------------------------------------------------
Total utility plant 14,733,231 14,463,276 14,174,161
---------------------------------------------------------------------------------------------------
Accumulated Provision for Depreciation:
Electric 4,054,986 3,822,344 3,569,717
Steam heat - - -
---------------------------------------------------------------------------------------------------
Total accumulated provision for depreciation 4,054,986 3,822,344 3,569,717
---------------------------------------------------------------------------------------------------
Total 10,678,245 10,640,932 10,604,444
---------------------------------------------------------------------------------------------------
Less property-related accumulated deferred income taxes - - 1,589,743
---------------------------------------------------------------------------------------------------
Total 10,678,245 10,640,932 9,014,701
---------------------------------------------------------------------------------------------------
Other Property and Investments:
Securities received from settlement of disputed contracts - - -
Nuclear decommissioning trusts 54,297 37,937 20,311
Miscellaneous 116,527 61,142 55,463
---------------------------------------------------------------------------------------------------
Total 170,824 99,079 75,774
---------------------------------------------------------------------------------------------------
Current Assets:
Cash and cash equivalents 12,539 5,896 22,114
Investment securities - - 108,206
Receivables, net 389,279 515,178 385,227
Accrued utility revenues 103,223 99,550 88,164
Fossil fuel stock, at average cost 169,252 111,620 197,332
Materials and supplies, at average cost 293,464 287,551 284,272
Prepayments 55,383 65,269 91,447
Vacation pay deferred 40,823 41,575 40,169
---------------------------------------------------------------------------------------------------
Total 1,063,963 1,126,639 1,216,931
---------------------------------------------------------------------------------------------------
Deferred Charges:
Deferred charges related to income taxes 919,750 992,510 -
Deferred Plant Vogtle costs 432,092 506,980 383,025
Debt expense, being amortized 26,223 20,730 17,719
Premium on reacquired debt, being amortized 164,676 153,146 116,940
Miscellaneous 256,885 196,094 139,352
---------------------------------------------------------------------------------------------------
Total 1,799,626 1,869,460 657,036
---------------------------------------------------------------------------------------------------
Total Assets $13,712,658 $13,736,110 $10,964,442
===================================================================================================
II-135
BALANCE SHEETS
Georgia Power Company
==============================================================================================================
At December 31, 1991 1990 1989 1988
--------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
ASSETS
Electric Plant:
Production-
Fossil $ 3,128,594 $ 3,350,018 $ 3,319,876 $ 2,638,725
Nuclear 4,051,043 4,025,862 4,189,723 3,225,945
Hydro 432,674 412,157 411,235 407,771
--------------------------------------------------------------------------------------------------------------
Total production 7,612,311 7,788,037 7,920,834 6,272,441
Transmission 1,566,173 1,522,157 1,431,485 1,322,034
Distribution 3,252,111 3,056,825 2,863,011 2,598,714
General 896,477 876,989 859,013 737,621
Construction work in progress 390,437 370,243 403,365 1,963,283
Nuclear fuel, at amortized cost 191,726 210,320 254,101 307,109
--------------------------------------------------------------------------------------------------------------
Total electric plant 13,909,235 13,824,571 13,731,809 13,201,202
--------------------------------------------------------------------------------------------------------------
Steam Heat Plant - - - -
--------------------------------------------------------------------------------------------------------------
Total utility plant 13,909,235 13,824,571 13,731,809 13,201,202
--------------------------------------------------------------------------------------------------------------
Accumulated Provision for Depreciation:
Electric 3,315,247 3,040,298 2,762,937 2,445,404
Steam heat - - - -
--------------------------------------------------------------------------------------------------------------
Total accumulated provision for depreciation 3,315,247 3,040,298 2,762,937 2,445,404
--------------------------------------------------------------------------------------------------------------
Total 10,593,988 10,784,273 10,968,872 10,755,798
--------------------------------------------------------------------------------------------------------------
Less property-related accumulated deferred income taxes 1,465,408 1,397,647 1,313,626 1,178,291
--------------------------------------------------------------------------------------------------------------
Total 9,128,580 9,386,626 9,655,246 9,577,507
--------------------------------------------------------------------------------------------------------------
Other Property and Investments:
Securities received from settlement of disputed contracts 107,993 - - -
Nuclear decommissioning trusts 10,007 - - -
Miscellaneous 71,880 78,895 69,839 66,677
--------------------------------------------------------------------------------------------------------------
Total 189,880 78,895 69,839 66,677
--------------------------------------------------------------------------------------------------------------
Current Assets:
Cash and cash equivalents 13,822 143,978 159,792 193,767
Investment securities - - - -
Receivables, net 330,411 356,236 347,899 320,018
Accrued utility revenues 79,099 78,067 93,786 66,265
Fossil fuel stock, at average cost 200,248 225,966 214,487 225,274
Materials and supplies, at average cost 215,735 220,103 208,084 164,174
Prepayments 96,750 121,646 116,342 121,840
Vacation pay deferred 39,769 33,677 35,238 34,418
--------------------------------------------------------------------------------------------------------------
Total 975,834 1,179,673 1,175,628 1,125,756
--------------------------------------------------------------------------------------------------------------
Deferred Charges:
Deferred charges related to income taxes - - - -
Deferred Plant Vogtle costs 375,028 364,446 322,116 269,958
Debt expense, being amortized 12,368 12,708 13,032 12,476
Premium on reacquired debt, being amortized 70,855 60,653 61,889 62,352
Miscellaneous 89,993 93,618 74,596 15,813
--------------------------------------------------------------------------------------------------------------
Total 548,244 531,425 471,633 360,599
--------------------------------------------------------------------------------------------------------------
Total Assets $10,842,538 $11,176,619 $11,372,346 $11,130,539
==============================================================================================================
II-136A
BALANCE SHEETS
Georgia Power Company
==============================================================================================================
At December 31, 1987 1986 1985 1984
--------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
ASSETS
Electric Plant:
Production-
Fossil $ 2,616,741 $ 2,138,511 $ 2,118,863 $ 2,105,551
Nuclear 3,220,632 739,835 652,756 647,020
Hydro 404,291 399,120 388,832 303,334
--------------------------------------------------------------------------------------------------------------
Total production 6,241,664 3,277,466 3,160,451 3,055,905
Transmission 1,248,976 1,176,479 1,004,329 949,802
Distribution 2,318,185 2,096,498 1,892,127 1,722,546
General 657,258 578,236 501,477 452,119
Construction work in progress 1,710,769 4,430,152 3,581,065 2,694,628
Nuclear fuel, at amortized cost 287,492 314,225 253,418 231,456
--------------------------------------------------------------------------------------------------------------
Total electric plant 12,464,344 11,873,056 10,392,867 9,106,456
--------------------------------------------------------------------------------------------------------------
Steam Heat Plant 7 15,266 14,709 15,419
--------------------------------------------------------------------------------------------------------------
Total utility plant 12,464,351 11,888,322 10,407,576 9,121,875
--------------------------------------------------------------------------------------------------------------
Accumulated Provision for Depreciation:
Electric 2,193,395 2,001,605 1,851,649 1,693,788
Steam heat (5) 7,841 7,517 7,696
--------------------------------------------------------------------------------------------------------------
Total accumulated provision for depreciation 2,193,390 2,009,446 1,859,166 1,701,484
--------------------------------------------------------------------------------------------------------------
Total 10,270,961 9,878,876 8,548,410 7,420,391
--------------------------------------------------------------------------------------------------------------
Less property-related accumulated deferred income taxes 1,077,747 1,020,271 920,047 873,024
--------------------------------------------------------------------------------------------------------------
Total 9,193,214 8,858,605 7,628,363 6,547,367
--------------------------------------------------------------------------------------------------------------
Other Property and Investments:
Securities received from settlement of disputed contracts - - - -
Nuclear decommissioning trusts - - - -
Miscellaneous 54,148 50,749 39,357 38,143
--------------------------------------------------------------------------------------------------------------
Total 54,148 50,749 39,357 38,143
--------------------------------------------------------------------------------------------------------------
Current Assets:
Cash and cash equivalents 761,644 694,474 602,529 485,011
Investment securities - - - -
Receivables, net 342,315 374,590 367,226 350,197
Accrued utility revenues 68,370 55,513 55,403 44,504
Fossil fuel stock, at average cost 262,752 220,206 210,604 289,807
Materials and supplies, at average cost 116,652 86,658 69,397 67,861
Prepayments 113,381 44,800 8,506 6,697
Vacation pay deferred 30,100 29,800 28,700 26,600
--------------------------------------------------------------------------------------------------------------
Total 1,695,214 1,506,041 1,342,365 1,270,677
--------------------------------------------------------------------------------------------------------------
Deferred Charges:
Deferred charges related to income taxes - - - -
Deferred Plant Vogtle costs 172,990 - - -
Debt expense, being amortized 12,985 12,860 12,450 11,218
Premium on reacquired debt, being amortized 51,509 26,914 - -
Miscellaneous 17,434 9,894 8,083 12,667
--------------------------------------------------------------------------------------------------------------
Total 254,918 49,668 20,533 23,885
--------------------------------------------------------------------------------------------------------------
Total Assets $11,197,494 $10,465,063 $ 9,030,618 $ 7,880,072
==============================================================================================================
II-136B
BALANCE SHEETS
Georgia Power Company
==================================================================================================
At December 31, 1994 1993 1992
--------------------------------------------------------------------------------------------------
(Thousands of Dollars)
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock $ 344,250 $ 344,250 $ 344,250
Paid-in capital 2,384,348 2,384,348 2,384,140
Premium on preferred stock 413 413 467
Earnings retained in the business 1,412,543 1,316,447 1,159,380
--------------------------------------------------------------------------------------------------
Total common equity 4,141,554 4,045,458 3,888,237
Preferred stock 692,787 692,787 692,792
Preferred stock subject to mandatory redemption - - 6,250
Preferred securities of subsidiary 100,000 - -
Long-term debt 3,757,823 4,031,387 4,131,016
--------------------------------------------------------------------------------------------------
Total (excluding amount due within one year) 8,692,164 8,769,632 8,718,295
--------------------------------------------------------------------------------------------------
Current Liabilities:
Notes payable to banks 202,200 406,700 400,200
Commercial paper 222,602 75,527 133,471
Preferred stock due within one year - - 63,750
Long-term debt due within one year 167,420 10,543 95,823
Accounts payable 355,067 324,044 317,351
Customer deposits 47,017 45,922 45,145
Taxes accrued 93,019 153,493 138,289
Interest accrued 110,256 110,497 132,319
Vacation pay accrued 39,720 40,060 38,694
Miscellaneous 70,006 64,527 89,355
--------------------------------------------------------------------------------------------------
Total 1,307,307 1,231,313 1,454,397
--------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 2,477,661 2,479,720 -
Accumulated deferred investment tax credits 453,121 478,334 515,539
Disallowed Plant Vogtle capacity buyback costs 60,490 63,067 72,201
Deferred credits related to income taxes 433,334 452,819 -
Miscellaneous 288,581 261,225 204,010
--------------------------------------------------------------------------------------------------
Total 3,713,187 3,735,165 791,750
--------------------------------------------------------------------------------------------------
Total Capitalization and Liabilities $13,712,658 $13,736,110 $10,964,442
==================================================================================================
II-137
BALANCE SHEETS
Georgia Power Company
==============================================================================================================
At December 31, 1991 1990 1989 1988
--------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock $ 344,250 $ 344,250 $ 344,250 $ 344,250
Paid-in capital 2,383,800 2,383,800 2,383,800 2,383,800
Premium on preferred stock 489 1,089 1,089 1,089
Earnings retained in the business 1,038,012 944,774 1,131,518 1,076,931
--------------------------------------------------------------------------------------------------------------
Total common equity 3,766,551 3,673,913 3,860,657 3,806,070
Preferred stock 607,796 607,796 607,844 657,844
Preferred stock subject to mandatory redemption 118,750 125,000 155,000 162,500
Preferred securities of subsidiary - - - -
Long-term debt 4,553,189 5,000,225 5,054,001 4,861,378
--------------------------------------------------------------------------------------------------------------
Total (excluding amount due within one year) 9,046,286 9,406,934 9,677,502 9,487,792
--------------------------------------------------------------------------------------------------------------
Current Liabilities:
Notes payable to banks 199,000 - - -
Commercial paper - - - -
Preferred stock due within one year 6,250 - 53,750 3,750
Long-term debt due within one year 54,976 204,906 54,712 42,001
Accounts payable 275,932 310,676 372,968 429,807
Customer deposits 41,623 38,144 36,255 34,221
Taxes accrued 161,117 84,185 91,424 130,686
Interest accrued 151,171 175,959 162,513 170,090
Vacation pay accrued 38,531 33,677 35,238 34,418
Miscellaneous 106,810 135,392 130,546 51,289
--------------------------------------------------------------------------------------------------------------
Total 1,035,410 982,939 937,406 896,262
--------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes - - - -
Accumulated deferred investment tax credits 540,134 576,837 601,248 632,111
Disallowed Plant Vogtle capacity buyback costs 109,537 135,926 73,111 80,585
Deferred credits related to income taxes - - - -
Miscellaneous 111,171 73,983 83,079 33,789
--------------------------------------------------------------------------------------------------------------
Total 760,842 786,746 757,438 746,485
--------------------------------------------------------------------------------------------------------------
Total Capitalization and Liabilities $10,842,538 $11,176,619 $11,372,346 $11,130,539
==============================================================================================================
II-138A
BALANCE SHEETS
Georgia Power Company
==============================================================================================================
At December 31, 1987 1986 1985 1984
--------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock $ 344,250 $ 344,250 $ 344,250 $ 344,250
Paid-in capital 2,208,800 1,980,800 1,730,800 1,415,800
Premium on preferred stock 1,089 3,074 3,074 3,058
Earnings retained in the business 984,043 1,141,077 935,583 723,064
--------------------------------------------------------------------------------------------------------------
Total common equity 3,538,182 3,469,201 3,013,707 2,486,172
Preferred stock 657,844 732,844 632,844 482,844
Preferred stock subject to mandatory redemption 166,250 112,500 120,000 127,500
Preferred securities of subsidiary - - - -
Long-term debt 4,825,760 4,464,857 3,878,066 3,432,606
--------------------------------------------------------------------------------------------------------------
Total (excluding amount due within one year) 9,188,036 8,779,402 7,644,617 6,529,122
--------------------------------------------------------------------------------------------------------------
Current Liabilities:
Notes payable to banks 302,261 - 36,400 109,356
Commercial paper - - - -
Preferred stock due within one year 3,750 7,500 7,500 3,750
Long-term debt due within one year 65,774 47,683 48,229 21,324
Accounts payable 446,004 488,910 355,866 365,048
Customer deposits 31,106 29,520 29,752 34,838
Taxes accrued 114,947 140,968 92,028 151,438
Interest accrued 162,439 150,145 136,279 117,759
Vacation pay accrued 30,100 29,800 28,700 26,600
Miscellaneous 62,364 70,595 60,965 37,874
--------------------------------------------------------------------------------------------------------------
Total 1,218,745 965,121 795,719 867,987
--------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes - - - -
Accumulated deferred investment tax credits 640,694 665,447 572,509 471,640
Disallowed Plant Vogtle capacity buyback costs 79,376 - - -
Deferred credits related to income taxes - - - -
Miscellaneous 70,643 55,093 17,773 11,323
--------------------------------------------------------------------------------------------------------------
Total 790,713 720,540 590,282 482,963
--------------------------------------------------------------------------------------------------------------
Total Capitalization and Liabilities $11,197,494 $10,465,063 $ 9,030,618 $ 7,880,072
==============================================================================================================
II-138B
GEORGIA POWER COMPANY
OUTSTANDING SECURITIES AT DECEMBER 31, 1994
First Mortgage Bonds
Amount Interest Amount
Series Issued Rate Outstanding Maturity
-------------------------------------------------------------------
(Thousands) (Thousands)
1992 $ 130,000 5-1/8% $ 130,000 9/1/95
1993 150,000 4-3/4% 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
1989 250,000 9.23% 36,157 12/1/19
1992 100,000 8-3/4% 100,000 4/1/22
1992 100,000 8-5/8% 100,000 6/1/22
1993 160,000 7.95% 160,000 2/1/23
1993 100,000 7-5/8% 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
1992 100,000 Variable 100,000 4/1/32
1992 100,000 Variable 100,000 7/1/32
---------- ----------
$2,360,000 $2,146,157
========== ==========
Pollution Control Bonds
Amount Interest Amount
Series Issued Rate Outstanding Maturity
-------------------------------------------------------------------
(Thousands) (Thousands)
1992 $ 38,800 5.70% $ 38,800 9/1/04
1993 46,790 5-3/8% 46,790 3/1/05
1976 40,800 6-3/4% 1,940 11/1/06
1977 24,100 6.40% 1,960 6/1/07
1978 21,600 6-3/8% 8,130 4/1/08
1991 10,450 Variable 10,450 7/1/11
1985 150,000 10-1/8% 148,535 6/1/15
1985 200,000 10-1/2% 156,580 9/1/15
1985 100,000 10.60% 100,000 10/1/15
1985 100,000 10-1/2% 99,585 11/1/15
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 Variable 8,500 7/1/19
1991 51,345 7.25% 51,345 7/1/21
1991 10,125 Variable 10,125 7/1/21
1992 13,155 Variable 13,155 5/1/22
1992 75,000 6.20% 75,000 8/1/22
1992 35,000 6.20% 35,000 9/1/22
1993 11,935 5-3/4% 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 Variable 10,000 12/1/24
1994 7,000 Variable 7,000 12/1/24
---------- ----------
$1,797,910 $1,678,140
========== ==========
II-139
GEORGIA POWER COMPANY
OUTSTANDING SECURITIES AT DECEMBER 31, 1994 (Continued)
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 433,775 $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
---------- --------
21,027,865 $692,787
========== ========
(1)Issued by Georgia Power Capital, L.P., and unconditionally guaranteed
by GEORGIA.
(2)Issued in exchange for $5.00 preferred outstanding at the time of
company formation.
II-140
GEORGIA POWER COMPANY
SECURITIES RETIRED DURING 1994
First Mortgage Bonds
Principal Interest
Series Amount Rate
-----------------------------------------------------
(Thousands)
1986 $ 69,716 10.00%
1989 63,843 9.23%
--------
$133,559
========
Pollution Control Bonds
Principal Interest
Series Amount Rate
-----------------------------------------------------
(Thousands)
1976 $ 20 6-3/4%
1977 20 6.40%
1978 70 6-3/8%
1984 28,065 11-5/8%
1984 113,745 12-1/4%
1984 123,175 11-5/8%
1984 126,735 12%
1984 75,070 11-3/4%
1985 43,420 10-1/2%
--------
$510,320
========
II-141
GULF POWER COMPANY
FINANCIAL SECTION
II-142
MANAGEMENT'S REPORT
Gulf Power Company 1994 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 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
II-143
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors
of Gulf Power Company:
We have audited the accompanying balance sheets and statements of capitalization
of Gulf Power Company (a Maine corporation and a wholly owned subsidiary of The
Southern Company) as of December 31, 1994 and 1993, 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, 1994. These financial statements
are the responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
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, 1994 and 1993, and the
results of its operations and its cash flows for the periods stated, in
conformity with generally accepted accounting principles.
As explained in Notes 2 and 8 to the financial statements, effective January
1, 1993, Gulf Power Company changed its methods of accounting for postretirement
benefits other than pensions and for income taxes.
/s/ Arthur Andersen LLP
Atlanta, Georgia
February 15, 1995
II-144
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Gulf Power Company 1994 Annual Report
RESULTS OF OPERATIONS
Earnings
Gulf Power Company's net income after dividends on preferred stock for 1994
totaled $55.2 million, representing a $0.9 million increase from the prior year.
Major factors affecting earnings were a decrease in interest charges on
long-term debt as a result of security refinancings and an increase in
customers. These positive factors were offset by lower revenues primarily due to
mild summer weather, and an increase in other operation expenses and taxes.
Also, earnings decreased approximately $3.0 million, reflecting the first full
year of decreased industrial sales due to the Company's largest industrial
customer, Monsanto, installing its own cogeneration facility in August, 1993.
Earnings for 1994 increased from the 1993 level, even though 1993 earnings
included $4.0 million of unusual items pertaining to the gain on sale of Gulf
States Utilities Company (Gulf States) stock and the reversal of a wholesale
rate refund discussed below.
In 1993, earnings were $54.3 million, representing a $0.2 million increase
compared to the prior year. This increase resulted primarily from a $2.3 million
gain on the sale of Gulf States' stock and the reversal of a $1.7 million
wholesale rate refund as the result of a court order. The Company also
experienced growth in residential and commercial sales and a decrease in
interest expense on long-term debt as a result of security refinancings. These
positive events were offset by higher operation and maintenance expense and
decreased industrial sales, reflecting the loss of Monsanto, which is discussed
above.
The Company's return on average common equity was 13.15 percent for 1994, a
slight decrease from the 13.29 percent return earned in 1993.
Revenues
Changes in operating revenues over the last three years are the result of the
following factors:
===========================================================
Increase (Decrease)
From Prior Year
-------------------------------
1994 1993 1992
-------------------------------
(in thousands)
Retail --
Change in base rates $ 0 $ 1,571 $ 722
Sales growth 7,126 7,671 12,965
Weather (4,631) 4,049 (6,448)
Regulatory cost
recovery and other 8,938 (3,079) (1,839)
-----------------------------------------------------------
Total retail 11,433 10,212 5,400
-----------------------------------------------------------
Sales for resale--
Non-affiliates (6,098) 2,131* 442
Affiliates (5,813) (909) (5,268)
-----------------------------------------------------------
Total sales for resale (11,911) 1,222 (4,826)
-----------------------------------------------------------
Other operating
revenues (3,851) 806 5,121
-----------------------------------------------------------
Total operating
revenues $(4,329) $12,240 $ 5,695
===========================================================
Percent change (0.7)% 2.1% 1.0%
-----------------------------------------------------------
* Includes the non-interest portion of the wholesale rate refund
reversal discussed in "Earnings."
Retail revenues of $483.1 million in 1994 increased $11.4 million or 2.4
percent from last year, compared with an increase of 2.2 percent in 1993 and 1.2
percent in 1992. Revenues increased in the residential and commercial classes
primarily due to customer growth and favorable economic conditions, partially
offset by the effect of milder weather. Revenues in the industrial class
declined in 1994 and 1993 primarily due to the loss of Monsanto as discussed in
"Earnings." Also, in 1994, industrial sales decreased due to an unexpected six
month plant shutdown -- which ended in October 1994 -- by another major
industrial customer. The change in base rates for 1993 and 1992 reflects the
expiration of a retail rate penalty in September 1992.
The increase in regulatory cost recovery and other retail revenue is
primarily attributable to the first year of recovery under the Environmental
Cost Recovery (ECR) clause. Regulatory cost recovery and other primarily
includes recovery provisions for fuel expense and the energy component of
purchased power costs; energy conservation costs; purchased power capacity
II-145
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 1994 Annual Report
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.
Sales for resale were $83.5 million in 1994, decreasing $11.9 million or 12.5
percent from 1993. The majority of non-affiliated energy sales arise from
long-term contractual agreements. Non-affiliated long-term contracts include
capacity and energy components. Capacity revenues reflect the recovery of fixed
costs and return on investment. Energy is sold at its variable cost. The
capacity and energy components under these long-term contracts were as follows:
===========================================================
1994 1993 1992
------------------------------------
(in thousands)
Capacity $30,926 $33,805 $34,180
Energy 18,456 21,202 22,933
-----------------------------------------------------------
$49,382 $55,007 $57,113
===========================================================
Capacity revenues decreased in 1994, reflecting the 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 changes in other operating revenues for 1994 and 1993 are primarily due
to adjustments of 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 1994 and percent changes in sales since 1992 are
reported below.
=============================================================
(millions of Amount Percent Change
kilowatt-hours) ------ ----------------------
1994 1994 1993 1992
------ ----------------------
Residential 3,752 1.1% 3.2% 4.1%
Commercial 2,549 4.8 2.7 4.2
Industrial 1,847 (9.0) (6.9) 2.9
Other 17 - - (2.7)
------
Total retail 8,165 (0.3) 0.4 3.8
Sales for resale
Non-affiliates 1,419 (2.8) 2.0 (7.7)
Affiliates 874 (15.2) (14.8) (2.2)
------
Total 10,458 (2.1) (1.1) 1.4
=============================================================
Retail sales decreased in 1994 primarily due to mild summer weather and a
decline in sales in the industrial class, which reflects the loss of Monsanto
and a lengthy shutdown of another major customer. The decline in sales was
partially offset by a 2.4 percent increase in residential customers, a 2.9
percent increase in commercial customers, and an improving economy. Retail sales
were relatively flat in 1993.
In 1994, energy sales for resale to non-affiliates decreased 2.8 percent and
are predominantly related to unit power sales under long-term contracts to
Florida utilities, which are discussed above. Energy sales to affiliated
companies vary from year to year as mentioned previously.
Expenses
Total operating expenses for 1994 decreased $4.0 million or 0.8 percent from
1993. The decrease is primarily due to decreased fuel and purchased power
expenses, offset by an increase in other operation expenses and taxes. In 1993,
total operating expenses increased $16.6 million or 3.5 percent from 1992
primarily due to increased operation and maintenance expenses and higher taxes.
Fuel and purchased power expenses for 1994 declined $13.4 million or 6.5
percent from 1993. The decline reflects the decrease in generation due to the
mild weather experienced in 1994 and the lower cost of fuel. In 1993, fuel and
purchased power expenses decreased $3.8 million or 1.8 percent from 1992,
reflecting the lower cost of fuel.
II-146
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 1994 Annual Report
In 1994, other operation expenses increased $4.7 million or 4.3 percent from
the 1993 level. The increase is primarily attributable to additional costs of
$6.4 million related to the buyouts and renegotiation of coal supply contracts
and $1.3 million for the Company's pro rata share of affiliated companies'
workforce reduction costs. These costs are further discussed in Notes 2 and 5 to
the financial statements under "Work Force Reduction Programs" and "Fuel
Commitments," respectively. The increase in coal buyouts and workforce
reductions costs were partially offset by a decrease in various administrative
and general expenses. In 1993, other operation expenses increased $11.9 million
or 12.2 percent from the previous year, reflecting $7.4 million of additional
costs related to the buyouts and renegotiation of coal supply contracts. In
addition, in 1993, other operation expenses increased $3.5 million due to higher
employee benefit costs, the Company's pro rata share of the Southern electric
system's environmental cleanup costs of a research facility site, and costs
related to an automotive fleet reduction program.
Maintenance expense remained relatively flat in 1994 reflecting no major
changes in the scheduling of maintenance of production facilities. In 1993,
maintenance expense increased $4.1 million or 9.7 percent over 1992 due to
scheduled maintenance of production facilities.
Federal and state income taxes increased $1.2 million or 3.8 percent in 1994
primarily 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. In 1993, federal income taxes increased $0.7 million
primarily due to a corporate federal income tax rate increase from 34 percent to
35 percent. Taxes other than income taxes increased $2.3 million in 1993, an
increase of 6.1 percent over the 1992 expense primarily due to increases in
property and gross receipt taxes. Changes in gross receipt taxes and franchise
fee collections, which are collected from customers, have no impact on earnings.
In 1994, interest expense decreased $3.8 million or 10.5 percent under the
prior year. Interest expense in 1993 decreased $3.2 million or 8.1 percent from
the 1992 level. The decrease in both years is primarily attributable to the
refinancing of some of the Company's higher-cost securities.
Effects of Inflation
The Company is subject to rate regulation and income tax laws that are based on
the recovery of historical costs. Therefore, inflation creates an economic loss
because the Company is recovering its cost of investments in dollars that have
less purchasing power. While the inflation rate has been relatively low in
recent years, it continues to have an adverse effect on the Company because of
the large investment in long-lived utility plant. Conventional accounting for
historical cost does not recognize this economic loss nor the partially
offsetting gain that arises through financing facilities with fixed-money
obligations, such as long-term debt and preferred stock. Any recognition of
inflation by regulatory authorities is reflected in the rate of return allowed.
Future Earnings Potential
The results of operations for the past three years are not necessarily
indicative of future earnings potential. The level of future earnings depends on
a number of factors ranging from growth in energy sales to the effects of a less
regulated, more competitive environment.
Future earnings in the near term will depend upon growth in energy sales,
which is subject to a number of factors. Traditionally, these factors included
changes in contracts with neighboring utilities, energy conservation practiced
by customers, the elasticity of demand, weather, competition, and the rate of
economic growth in the Company's service area. However, the Energy Policy Act of
1992 (Energy Act) 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 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. Presently, 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. In order to address these
initiatives, numerous questions must be resolved, with the most complex ones
II-147
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 1994 Annual Report
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 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 is the loss 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 Florida Public Service Commission (FPSC) has set conservation goals for
the Company to reduce 148 megawatts of peak demand by the year 2003. The Company
will file conservation programs in 1995 to accomplish these goals. 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.
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. See Note 1 to the financial statements under
"Regulatory Assets and Liabilities" for additional information.
The Federal Energy Regulatory Commission (FERC) regulates wholesale rate
schedules and power sales contracts that the Company has with its sales for
resale customers. The FERC is currently reviewing the rate of return on common
equity included in these schedules and contracts that have a return on common
equity of 13.75 percent or greater, and may require such returns to be lowered,
possibly retroactively. See Note 3 to the financial statements under "FERC
Reviews Equity Returns" for additional information.
Compliance costs related to the Clean Air Act Amendments of 1990 (Clean Air
Act) could reduce earnings if such costs are not fully recovered. The Clean Air
Act is discussed later under "Environmental Matters." 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."
FINANCIAL CONDITION
Overview
The principal changes in the Company's financial condition during 1994 were
gross property additions of $78.9 million and an increase of $47.4 million in
notes payable. Funds for the property additions were provided by internal
sources. The Company continued to refinance higher-cost securities to lower the
Company's cost of capital. See "Financing Activities" below and the Statements
of Cash Flows for further details.
Financing Activities
The Company continued to lower its financing costs by issuing new securities and
other debt, and retiring higher-cost issues in 1994. The Company sold through
public authorities, $42 million of pollution control revenue bonds and obtained
$32.1 million of long-term bank notes. Retirements, including maturities during
1994, totaled $48.9 million of first mortgage bonds, $42.1 million of pollution
control bonds, $24.2 million of bank notes and other long-term debt, and $1
million of preferred stock. (See the Statements of Cash Flows for further
details.)
II-148
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 1994 Annual Report
Composite financing rates for the years 1992 through 1994 as of year end were
as follows:
===========================================================
1994 1993 1992
-------------------------
Composite interest rate on
long-term debt 6.5% 7.1% 8.0%
Composite preferred stock
dividend rate 6.6% 6.5% 7.3%
===========================================================
The continued decrease in the composite interest rate on long-term debt
reflects the Company's continued efforts to refinance higher-cost debt, which is
discussed above. The slight increase in the composite preferred dividend rate is
primarily due to an increase in dividends on the Company's adjustable rate
preferred stock, reflecting the recent rise in interest rates.
Capital Requirements for Construction
The Company's gross property additions, including those amounts related to
environmental compliance, are budgeted at $222 million for the three years
beginning 1995 ($62 million in 1995, $76 million in 1996, and $84 million in
1997). The estimates of property additions for the three-year period include $13
million committed to meeting the requirements of the Clean Air Act, the cost of
which is expected to be recovered through the ECR clause, which is discussed in
Note 3 to the financial statements under "Environmental Cost Recovery." Actual
construction costs may vary from this estimate because of factors such as the
granting of timely and adequate rate increases; changes in environmental
regulations; revised load projections; the cost and efficiency of construction
labor, equipment, and materials; and the cost of capital. The Company does not
have any baseload generating plants under construction. However, 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
$74.3 million will be required by the end of 1997 in connection with maturities
of long-term debt and preferred stock subject to mandatory redemption. Also, the
Company plans to continue a program to retire higher-cost debt and preferred
stock and replace these obligations with lower-cost capital 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 -- will have a
significant impact on the Company. Specific reductions in sulfur dioxide and
nitrogen oxide emissions from fossil-fired generating plants will be required in
two phases. Phase I compliance began in 1995 and affects eight generating plants
-- some 10,000 megawatts of capacity or 35 percent of total capacity -- in the
Southern electric system. Phase II compliance is required by 2000, and all
fossil-fired generating plants in the Southern electric system 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 rate-adjustment clause.
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 Environmental Cost Recovery clause.
In 1995, the Environmental Protection Agency (EPA) will begin 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 expects to achieve Phase I sulfur dioxide compliance at
the eight affected plants by switching to low-sulfur coal, which has required
some equipment upgrades. This compliance strategy is expected to result in
unused emission allowances being banked for later use. Additional construction
II-149
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 1994 Annual Report
expenditures are required to install equipment for the control of nitrogen oxide
emissions at these eight plants. Also, continuous emissions monitoring equipment
has been installed on all fossil-fired units. Construction expenditures for
Phase I are estimated to total approximately $300 million for The Southern
Company through 1995. Through 1994, the Company's construction expenditures for
Phase I were approximately $51 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 anticipated Phase II
limits. Therefore, during the period 1996 to 2000, the current compliance
strategy could require total construction expenditures of approximately $150
million for The Southern Company, including approximately $19 million for the
Company. However, the full impact of Phase II compliance cannot 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 4 percent in annual 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 by November 1995. 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 continues to evaluate the need for a new short-term ambient air
quality standard for sulfur dioxide. Preliminary results from an EPA study on
the impact of a new standard indicate that a number of plants could be required
to install sulfur dioxide controls. These controls would be in addition to the
controls already required to meet the acid rain provision of the Clean Air Act.
The EPA issued proposed rules in November 1994 and is required to take final
action on this issue in 1996. The impact of any new standard will depend on the
level chosen for the standard and cannot be determined at this time.
In addition, the EPA is evaluating the need to revise the ambient air quality
standards for particulate matter, nitrogen oxides, and ozone. The impact of any
new standard will depend on the level chosen for the standard and cannot be
determined at this time.
In 1995, 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. For additional information, see Note 3 to the financial
statements under "Environmental Cost Recovery."
II-150
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 1994 Annual Report
Several major pieces of environmental legislation are being considered for
reauthorization or amendment by Congress. These include: the Clean Water Act;
the Comprehensive Environmental Response, Compensation, and Liability Act; the
Resource Conservation and Recovery 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 new legislation related to global climate change,
electromagnetic fields, and other environmental and health concerns could
significantly affect the Company. The impact of new legislation -- if any --
will depend on the subsequent development and implementation of applicable
regulations. In addition, the potential for lawsuits alleging damages caused by
electromagnetic fields exists.
Sources of Capital
At December 31, 1994, the Company had $0.9 million of cash and cash equivalents
to meet its short-term cash needs.
It is anticipated that the funds required for construction and other
purposes, including compliance with environmental regulations, will be derived
from operations; the sale of additional first mortgage bonds, pollution control
bonds, and preferred stock; 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
STATEMENTS OF INCOME
For the Years Ended December 31, 1994, 1993, and 1992
Gulf Power Company 1994 Annual Report
=========================================================================================
1994 1993 1992
-----------------------------------------------------------------------------------------
(in thousands)
Operating Revenues:
Revenues $ 561,460 $ 559,976 $ 546,827
Revenues from affiliates 17,353 23,166 24,075
-----------------------------------------------------------------------------------------
Total operating revenues 578,813 583,142 570,902
-----------------------------------------------------------------------------------------
Operating Expenses:
Operation-
Fuel 161,168 170,485 182,754
Purchased power from non-affiliates 6,761 4,386 1,394
Purchased power from affiliates 25,819 32,273 26,788
Other 113,879 109,164 97,310
Maintenance 46,700 46,004 41,947
Depreciation and amortization 56,615 55,309 53,758
Taxes other than income taxes 41,701 40,204 37,898
Federal and state income taxes (Note 8) 33,957 32,730 32,078
-----------------------------------------------------------------------------------------
Total operating expenses 486,600 490,555 473,927
-----------------------------------------------------------------------------------------
Operating Income 92,213 92,587 96,975
Other Income (Expense):
Allowance for equity funds used during
construction (Note 1) 450 512 14
Interest income 1,429 1,328 2,733
Other, net (780) (1,238) (1,487)
Gain on sale of investment securities - 3,820 -
Income taxes applicable to other income 95 (921) 187
-----------------------------------------------------------------------------------------
Income Before Interest Charges 93,407 96,088 98,422
-----------------------------------------------------------------------------------------
Interest Charges:
Interest on long-term debt 27,124 31,344 35,792
Other interest charges 2,442 2,877 1,410
Interest on notes payable 1,509 870 1,041
Amortization of debt discount, premium, and expense, net 1,834 1,412 1,032
Allowance for debt funds used during
construction (Note 1) (656) (454) (46)
-----------------------------------------------------------------------------------------
Net interest charges 32,253 36,049 39,229
-----------------------------------------------------------------------------------------
Net Income 61,154 60,039 59,193
Dividends on Preferred Stock 5,925 5,728 5,103
-----------------------------------------------------------------------------------------
Net Income After Dividends on Preferred Stock $ 55,229 $ 54,311 $ 54,090
=========================================================================================
The accompanying notes are an integral part of these statements.
II-152
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1994, 1993, and 1992
Gulf Power Company 1994 Annual Report
=================================================================================================
1994 1993 1992
-------------------------------------------------------------------------------------------------
(in thousands)
Operating Activities:
Net income $ 61,154 $ 60,039 $ 59,193
Adjustments to reconcile net income to net
cash provided by operating activities --
Depreciation and amortization 86,098 72,111 68,021
Deferred income taxes and investment tax credits (6,986) 5,347 3,322
Allowance for equity funds used during construction (450) (512) (14)
Other, net 4,898 (864) (735)
Changes in certain current assets and liabilities --
Receivables, net 3,540 12,867 (11,041)
Inventories (13,901) 5,574 23,560
Payables (10,159) 5,386 1,580
Other 610 (9,504) (13,637)
-------------------------------------------------------------------------------------------------
Net cash provided from operating activities 124,804 150,444 130,249
-------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (78,869) (78,562) (64,671)
Other (3,493) (5,328) 3,970
-------------------------------------------------------------------------------------------------
Net cash used for investing activities (82,362) (83,890) (60,701)
-------------------------------------------------------------------------------------------------
Financing Activities and Capital Contributions:
Proceeds:
Preferred stock - 35,000 29,500
First mortgage bonds - 75,000 25,000
Pollution control bonds 42,000 53,425 8,930
Capital contributions from parent 98 11 121
Other long-term debt 32,108 25,000 -
Retirements:
Preferred stock (1,000) (21,060) (15,500)
First mortgage bonds (48,856) (88,809) (117,693)
Pollution control bonds (42,100) (40,650) (9,205)
Other long-term debt (24,240) (7,736) (5,783)
Notes payable, net 47,447 (37,947) 44,000
Payment of preferred stock dividends (5,925) (5,728) (5,103)
Payment of common stock dividends (44,000) (41,800) (39,900)
Miscellaneous (2,648) (6,888) (8,760)
-------------------------------------------------------------------------------------------------
Net cash used for financing activities (47,116) (62,182) (94,393)
-------------------------------------------------------------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents (4,674) 4,372 (24,845)
Cash and Cash Equivalents at Beginning of Year 5,576 1,204 26,049
-------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 902 $ 5,576 $ 1,204
=================================================================================================
Supplemental Cash Flow Information:
Cash paid during the year for --
Interest (net of amount capitalized) $30,139 $28,470 $38,164
Income taxes $43,089 $27,865 $37,569
-------------------------------------------------------------------------------------------------
( ) Denotes use of cash.
The accompanying notes are an integral part of these statements.
II-153
BALANCE SHEETS
At December 31, 1994 and 1993
Gulf Power Company 1994 Annual Report
========================================================================================
ASSETS 1994 1993
----------------------------------------------------------------------------------------
(in thousands)
Utility Plant:
Plant in service (Notes 1 and 6) $ 1,656,367 $ 1,611,704
Less accumulated provision for depreciation 622,911 610,542
----------------------------------------------------------------------------------------
1,033,456 1,001,162
Construction work in progress 24,288 34,591
----------------------------------------------------------------------------------------
Total 1,057,744 1,035,753
----------------------------------------------------------------------------------------
Other Property and Investments 7,997 13,242
----------------------------------------------------------------------------------------
Current Assets:
Cash and cash equivalents 902 5,576
Receivables-
Customer accounts receivable 57,637 57,226
Other accounts and notes receivable 2,268 5,904
Affiliated companies 1,079 1,241
Accumulated provision for uncollectible accounts (600) (447)
Fossil fuel stock, at average cost 35,686 20,652
Materials and supplies, at average cost 35,257 36,390
Current portion of deferred coal contract costs (Note 5) 2,521 12,535
Regulatory clauses under recovery (Note 1) 5,002 3,244
Prepayments 4,354 2,160
Vacation pay deferred (Note 1) 4,172 4,022
----------------------------------------------------------------------------------------
Total 148,278 148,503
----------------------------------------------------------------------------------------
Deferred Charges:
Deferred charges related to income taxes (Note 8) 30,433 31,334
Debt expense and loss, being amortized 22,119 21,247
Deferred coal contract costs (Note 5) 38,169 52,884
Miscellaneous 10,802 4,846
----------------------------------------------------------------------------------------
Total 101,523 110,311
----------------------------------------------------------------------------------------
Total Assets $ 1,315,542 $ 1,307,809
========================================================================================
The accompanying notes are an integral part of these statements.
II-154
BALANCE SHEETS (continued)
At December 31, 1994 and 1993
Gulf Power Company 1994 Annual Report
========================================================================================
CAPITALIZATION AND LIABILITIES 1994 1993
----------------------------------------------------------------------------------------
(in thousands)
Capitalization (See accompanying statements):
Common stock equity (Note 11) $ 425,472 $ 414,196
Preferred stock 89,602 89,602
Preferred stock subject to mandatory redemption - 1,000
Long-term debt 356,393 369,259
----------------------------------------------------------------------------------------
Total 871,467 874,057
----------------------------------------------------------------------------------------
Current Liabilities:
Preferred stock due within one year 1,000 1,000
Long-term debt due within one year (Note 10) 13,439 41,552
Notes payable 53,500 6,053
Accounts payable-
Affiliated companies 9,132 18,560
Other 14,524 20,139
Customer deposits 13,609 15,082
Taxes accrued-
Federal and state income 5,990 10,330
Other 7,475 2,685
Interest accrued 6,106 5,420
Regulatory clauses over recovery (Note 1) 3,960 840
Vacation pay accrued (Note 1) 4,172 4,022
Miscellaneous 7,828 8,527
----------------------------------------------------------------------------------------
Total 140,735 134,210
----------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes (Note 8) 151,681 151,743
Deferred credits related to income taxes (Note 8) 71,964 76,876
Accumulated deferred investment tax credits 38,391 40,770
Accumulated provision for property damage (Note 1) 11,522 10,509
Accumulated provision for postretirement benefits (Note 2) 13,680 10,749
Miscellaneous 16,102 8,895
----------------------------------------------------------------------------------------
Total 303,340 299,542
----------------------------------------------------------------------------------------
Commitments and Contingent Matters (Notes 1, 2, 3, 4, 5, and 7)
Total Capitalization and Liabilities $ 1,315,542 $ 1,307,809
========================================================================================
The accompanying notes are an integral part of these statements.
II-155
STATEMENTS OF CAPITALIZATION
At December 31, 1994 and 1993
Gulf Power Company 1994 Annual Report
=================================================================================================
1994 1993 1994 1993
-------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
Common Stock Equity:
Common stock, without par value --
Authorized and outstanding --
992,717 shares in 1994 and 1993 $ 38,060 $ 38,060
Paid-in capital 218,380 218,282
Premium on preferred stock 81 81
Retained earnings (Note 11) 168,951 157,773
-------------------------------------------------------------------------------------------------
Total common stock equity 425,472 414,196 48.8 % 47.4 %
-------------------------------------------------------------------------------------------------
Cumulative Preferred Stock:
$10 par value, authorized 10,000,000 shares,
Outstanding 2,580,000 shares at December 31, 1994
$25 stated capital --
6.72% 20,000 20,000
7.00% 14,500 14,500
7.30% 15,000 15,000
Adjustable Rate -- at January 1, 1995: 6.07% 15,000 15,000
$100 par value --
Authorized -- 791,626 shares
Outstanding -- 251,026 shares at December 31, 1994
4.64% 5,102 5,102
5.16% 5,000 5,000
5.44% 5,000 5,000
7.52% 5,000 5,000
7.88% 5,000 5,000
-------------------------------------------------------------------------------------------------
Total (annual dividend requirement -- $5,901,300) 89,602 89,602 10.3 10.3
-------------------------------------------------------------------------------------------------
Cumulative Preferred Stock Subject to Mandatory Redemption:
$100 par value --
Authorized -- 10,000 shares
Outstanding -- 10,000 shares at December 31, 1994
11.36% Series 1,000 2,000
-------------------------------------------------------------------------------------------------
Total (annual dividend requirement -- $113,600) 1,000 2,000
-------------------------------------------------------------------------------------------------
Less amount due within one year 1,000 1,000
-------------------------------------------------------------------------------------------------
Total excluding amount due within one year - 1,000 - 0.1
-------------------------------------------------------------------------------------------------
II-156
STATEMENTS OF CAPITALIZATION (continued)
At December 31, 1994 and 1993
Gulf Power Company 1994 Annual Report
=================================================================================================
1994 1993 1994 1993
-------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
First mortgage bonds --
Maturity Interest Rates
-------- --------------
October 1, 1994 4.625% - 12,000
June 1, 1996 6% - 15,000
August 1, 1997 5.875% 25,000 25,000
April 1, 1998 9.20% - 19,486
April 1, 1998 5.55% 15,000 15,000
July 1, 1998 5.00% 30,000 30,000
July 1, 2003 6.125% 30,000 30,000
September 1, 2008 9% 2,680 5,050
December 1, 2021 8.75% 50,000 50,000
-------------------------------------------------------------------------------------------------
Total first mortgage bonds 152,680 201,536
Pollution control obligations (Note 9) 169,755 169,855
Other long-term debt (Note 9) 50,388 42,520
Unamortized debt premium (discount), net (2,991) (3,100)
-------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
requirement -- $23,777,000) 369,832 410,811
Less amount due within one year (Note 10) 13,439 41,552
-------------------------------------------------------------------------------------------------
Long-term debt excluding amount due within one year 356,393 369,259 40.9 42.2
-------------------------------------------------------------------------------------------------
Total Capitalization $871,467 $874,057 100.0 % 100.0 %
=================================================================================================
The accompanying notes are an integral part of these statements.
II-157
STATEMENTS OF RETAINED EARNINGS
For the Years Ended December 31, 1994, 1993, and 1992
Gulf Power Company 1994 Annual Report
========================================================================================
1994 1993 1992
----------------------------------------------------------------------------------------
(in thousands)
Balance at Beginning of Year $ 157,773 $ 146,771 $ 134,372
Net income after dividends on preferred stock 55,229 54,311 54,090
Cash dividends on common stock (44,000) (41,800) (39,900)
Preferred stock transactions, net (51) (1,509) (1,791)
----------------------------------------------------------------------------------------
Balance at End of Year (Note 11) $ 168,951 $ 157,773 $ 146,771
========================================================================================
STATEMENTS OF PAID-IN CAPITAL
For the Years Ended December 31, 1994, 1993, and 1992
Gulf Power Company 1994 Annual Report
========================================================================================
1994 1993 1992
----------------------------------------------------------------------------------------
(in thousands)
Balance at Beginning of Year $ 218,282 $ 218,271 $ 218,150
Contributions to capital by parent company 98 11 121
----------------------------------------------------------------------------------------
Balance at End of Year $ 218,380 $ 218,282 $ 218,271
========================================================================================
The accompanying notes are an integral part of these financial statements.
II-158
NOTES TO FINANCIAL STATEMENTS
At December 31, 1994, 1993, and 1992
Gulf Power Company 1994 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) and The Southern Development and Investment Group (SDIG). 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, beginning in
mid-1995, will provide digital wireless communications services -- over the
800-megahertz frequency band--to The Southern Company's subsidiaries and also
will market these services to the public within the Southeast. Southern Electric
designs, builds, owns and operates power production facilities and provides a
broad range of technical services to industrial companies and utilities in the
United States and a number of international markets. Southern Nuclear provides
services to The Southern Company's nuclear power plants. SDIG 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.
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:
===========================================================
1994 1993
-----------------------
(in thousands)
Current & deferred fuel charges $ 40,690 $ 65,419
Deferred income taxes 30,433 31,334
Premium on reacquired debt 18,494 17,554
Environmental remediation 7,800 -
Vacation pay 4,172 4,022
Regulatory clauses under (over)
recovery, net 1,042 2,404
Deferred income tax credits (71,964) (76,876)
Accumulated provision for
property damage (11,522) (10,509)
Other, net (2,691) (1,697)
-----------------------------------------------------------
Total $ 16,454 $ 31,651
===========================================================
In the event that a portion of the Company's operations are 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 to their fair value.
II-159
NOTES (continued)
Gulf Power Company 1994 Annual Report
Revenues and Regulatory Cost Recovery Clauses
The Company accrues revenues for service rendered but unbilled at the end of
each fiscal period. The Company's electric rates include provisions to
periodically adjust billings for fluctuations in fuel and the energy component
of purchased power costs; purchased power capacity costs; energy conservation
costs; and environmental compliance costs. Revenues are adjusted monthly for
differences between recoverable costs and amounts actually reflected in current
rates.
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 3.8
percent in 1994, 1993, and 1992. When property subject to depreciation is
retired or otherwise disposed of in the normal course of business, its cost --
together with the cost of removal, less salvage -- is charged to the accumulated
provision for depreciation. Minor items of property included in the original
cost of the plant are retired when the related property unit is retired.
Income Taxes
The Company provides deferred income taxes for all significant income tax
temporary differences. Investment tax credits utilized are deferred and
amortized to income over the average lives of the related property.
Effective January 1, 1993, the Company adopted FASB Statement No. 109,
Accounting for Income Taxes. Statement No. 109 required, among other things,
conversion to the liability method of accounting for accumulated deferred income
taxes. See Note 8 for additional information about Statement No. 109. The
Company is included in the consolidated federal income tax return of The
Southern Company.
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 1994 and the second half of 1993, and 8.03 percent for the
first half of 1993 and all of 1992. AFUDC amounts for 1994, 1993, and 1992 were
$1.1 million, $966 thousand, and $60 thousand, respectively. The increase in
1994 and 1993 is primarily due to an increase in construction projects at Plant
Daniel.
Utility Plant
Utility plant is stated at original cost. Original cost includes: materials;
labor; minor items of property; appropriate administrative and general costs;
payroll-related costs such as taxes, pensions, and other benefits; and the
estimated cost of funds used during construction. The cost of maintenance,
repairs, and replacement of minor items of property is charged to maintenance
expense. The cost of replacements of property (exclusive of minor items of
property) is charged to utility plant.
Cash and Cash Equivalents
For purposes of the Statements of Cash Flows, temporary cash investments are
considered cash equivalents. Temporary cash investments are securities with
original maturities of 90 days or less.
II-160
NOTES (continued)
Gulf Power Company 1994 Annual Report
Financial Instruments
In accordance with FASB Statement No. 107, Disclosure About Fair Values of
Financial Instruments, all financial instruments of the Company -- for which the
carrying amount does not approximate fair value -- are shown in the table below
as of December 31:
============================================================
1994
-----------------------
Carrying Fair
Amount Value
-----------------------
(in thousands)
Long-term debt $369,832 $355,019
Preferred stock subject to
mandatory redemption 1,000 1,030
============================================================
============================================================
1993
-----------------------
Carrying Fair
Amount Value
-----------------------
(in thousands)
Long-term debt $410,811 $431,251
Preferred stock subject to
mandatory redemption 2,000 2,040
============================================================
The fair values for long-term debt and preferred stock subject to mandatory
redemption were based on either closing market prices or closing prices of
comparable instruments.
Materials and Supplies
Generally, materials and supplies include the cost of transmission,
distribution, and generating plant materials. Materials are charged to inventory
when purchased and then expensed or capitalized to plant, as appropriate, when
installed.
Vacation Pay
The Company's employees earn their vacation in one year and take it in the
subsequent year. However, for ratemaking purposes, vacation pay is recognized as
an allowable expense only when paid. Consistent with this ratemaking treatment,
the Company accrues a current liability for earned vacation pay and records a
current asset representing the future recoverability of this cost. The amount
was $4.2 million and $4.0 million at December 31, 1994, and 1993, respectively.
In 1995, an estimated 81.3 percent of the 1994 deferred vacation cost will be
expensed and the balance will be charged to construction and other accounts.
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 $2.5 million and $2.2 million
at December 31, 1994, and 1993, respectively, is included in miscellaneous
current liabilities in the accompanying Balance Sheets.
Provision for Property Damage
Due to a significant increase in the cost of traditional insurance, effective in
1993, the Company became self-insured for the full cost of storm and other
damage to its transmission and distribution property. As permitted by regulatory
authorities, the Company provides for the estimated cost of uninsured property
damage by charges to income amounting to $1.2 million annually. At December 31,
1994, and 1993, the accumulated provision for property damage amounted to $11.5
million and $10.5 million, respectively. The expense of repairing such damage as
occurs from time to time is charged to the provision to the extent it is
available.
2. RETIREMENT BENEFITS
Pension Plan
The Company has a defined benefit, trusteed, non-contributory pension plan that
covers substantially all regular employees. Benefits are based on the greater of
amounts resulting from two different formulas: years of service and final
average pay or years of service and a flat-dollar benefit. The Company uses the
"entry age normal method with a frozen initial liability" actuarial method for
funding purposes, subject to limitations under federal income tax regulations.
Amounts funded to the pension trust fund are primarily invested in equity and
fixed-income securities. FASB Statement No. 87, Employers' Accounting for
Pensions, requires use of the "projected unit credit" actuarial method for
financial reporting purposes.
II-161
NOTES (continued)
Gulf Power Company 1994 Annual Report
Postretirement Benefits
The Company also provides certain medical care and life insurance benefits for
retired employees. Substantially all employees may become eligible for these
benefits when they retire. A qualified trust for medical benefits is funded to
the extent deductible under federal income tax regulations. Amounts funded are
primarily invested in debt and equity securities.
Effective January 1, 1993, the Company adopted FASB Statement No. 106,
Employers' Accounting for Postretirement Benefits Other Than Pensions, on a
prospective basis. Statement No. 106 requires that medical care and life
insurance benefits for retired employees be accounted for on an accrual basis
using a specified actuarial method, "benefit/years-of-service." The costs of
such benefits recognized by the Company in 1994 and 1993 were $4.3 million and
$3.9 million, respectively.
Prior to 1993, the Company recognized these benefit costs on an accrual basis
using the "aggregate cost" actuarial method, which spreads the expected cost of
such benefits over the remaining periods of employees' service as a level
percentage of payroll costs. The cost of such benefits recognized by the Company
in 1992 was $3.1 million.
Status and Cost of Benefits
Shown in the following tables are actuarial results and assumptions for pension
and postretirement medical and life insurance benefits as computed under the
requirements of FASB Statement Nos. 87 and 106, respectively. The funded status
of the plans at December 31 was as follows:
=================================================================
Pension
-------------------------
1994 1993
-------------------------
(in thousands)
Actuarial present value of
benefit obligation:
Vested benefits $ 73,552 $ 73,925
Non-vested benefits 3,016 3,217
-----------------------------------------------------------------
Accumulated benefit obligation 76,568 77,142
Additional amounts related to
projected salary increases 29,451 25,648
-----------------------------------------------------------------
Projected benefit obligation 106,019 102,790
Less:
Fair value of plan assets 151,337 159,192
Unrecognized net gain (36,599) (49,376)
Unrecognized prior service cost 2,802 3,152
Unrecognized transition asset (8,034) (8,765)
-----------------------------------------------------------------
Prepaid asset recognized in
the Balance Sheets $ 3,487 $ 1,413
=================================================================
=================================================================
Postretirement Medical
-------------------------
1994 1993
-------------------------
(in thousands)
Actuarial present value of benefit obligation:
Retirees and dependents $ 7,768 $ 7,857
Employees eligible to retire 4,043 4,054
Other employees 14,598 14,927
-----------------------------------------------------------------
Accumulated benefit obligation 26,409 26,838
Less:
Fair value of plan assets 5,655 5,638
Unrecognized net loss (gain) 615 2,653
Unrecognized transition
obligation 12,714 13,420
-----------------------------------------------------------------
Accrued liability recognized in
the Balance Sheets $ 7,425 $ 5,127
=================================================================
II-162
NOTES (continued)
Gulf Power Company 1994 Annual Report
=================================================================
Postretirement Life
--------------------
1994 1993
--------------------
(in thousands)
Actuarial present value of benefit obligation:
Retirees and dependents $3,032 $2,929
Employees eligible to retire - -
Other employees 5,041 5,058
-----------------------------------------------------------------
Accumulated benefit obligation 8,073 7,987
Less:
Fair value of plan assets 85 52
Unrecognized net loss (gain) (1,073) (641)
Unrecognized transition
obligation 2,806 2,954
-----------------------------------------------------------------
Accrued liability recognized in
the Balance Sheets $6,255 $5,622
=================================================================
The weighted average rates assumed in the actuarial calculations were:
=================================================================
1994 1993 1992
---------------------------
Discount 8.0% 7.5% 8.0%
Annual salary increase 5.5% 5.0% 6.0%
Long-term return on plan
assets 8.5% 8.5% 8.5%
=================================================================
An additional assumption used in measuring the accumulated postretirement
medical benefit obligation was a weighted average medical care cost trend rate
of 10.5 percent for 1994, decreasing to 6.0 percent through the year 2000 and
remaining at that level thereafter. An annual increase in the assumed medical
care cost trend rate of 1 percent would increase the accumulated medical benefit
obligation at December 31,1994, by $4.8 million and the aggregate of the service
and interest cost components of the net retiree medical cost by $660 thousand.
Components of the plans' net costs are shown below:
=================================================================
Pension
-----------------------------------
1994 1993 1992
-----------------------------------
(in thousands)
Benefits earned during
the year $ 3,775 $ 3,710 $ 3,550
Interest cost on projected
benefit obligation 7,484 7,319 6,939
Actual (return) loss on
plan assets 3,721 (20,672) (6,431)
Net amortization
and deferral (17,054) 8,853 (4,054)
-----------------------------------------------------------------
Net pension cost
(income) $ (2,074) $ (790) $ 4
=================================================================
Of the above net pension amounts, pension expense/(income) of $(1.5) million
in 1994, $(601) thousand in 1993, and $3 thousand in 1992, were recorded in
operating expenses, and the remainder was recorded in construction and other
accounts.
=================================================================
Postretirement Medical
-----------------------
1994 1993
-----------------------
(in thousands)
Benefits earned during the year $1,092 $ 874
Interest cost on accumulated
benefit obligation 1,952 1,714
Amortization of transition
obligation 706 706
Actual (return) loss on plan assets 117 (726)
Net amortization and deferral (575) 309
-----------------------------------------------------------------
Net postretirement cost $3,292 $2,877
=================================================================
=================================================================
Postretirement Life
-----------------------
1994 1993
-----------------------
(in thousands)
Benefits earned during the year $270 $ 292
Interest cost on accumulated
benefit obligation 583 625
Amortization of transition
obligation 148 148
Actual (return) loss on plan assets 12 (5)
Net amortization and deferral (16) 1
-----------------------------------------------------------------
Net postretirement cost $997 $1,061
=================================================================
II-163
NOTES (continued)
Gulf Power Company 1994 Annual Report
Of the above net postretirement medical and life insurance amounts, $3.1
million in 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 has not had a work force reduction program but has incurred its pro
rata share of affiliated companies' costs. The costs related to these programs
were $1.3 million, $109 thousand, and $138 thousand for the years 1994, 1993,
and 1992, 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 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 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 began in October 1994 and is scheduled to continue until
January 1996.
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 $5.4
million at December 31, 1994. Although the final outcome of this matter cannot
now be determined, in management's opinion, the final outcome will not result in
changes that would have a material adverse effect on the Company's financial
statements.
Environmental Cost Recovery
In April 1993, the Florida Legislature adopted legislation for an Environmental
Cost Recovery (ECR) clause, which allows a utility to petition the FPSC for
recovery of all prudent environmental compliance costs that are not being
recovered through base rates or any other rate-adjustment clause. Such
environmental costs include operation and maintenance expense, depreciation, and
a return on invested capital.
On January 12, 1994, the FPSC approved the Company's initial petition under
the ECR clause for recovery of environmental costs that were projected to be
incurred from July 1993 through September 1994. After this initial period,
recovery under the ECR clause is determined semi-annually and includes a true-up
of the prior period and a projection of the ensuing six month period. During
1994 and 1993, the Company recorded $7.2 million and $2.6 million, respectively,
of ECR revenues net of over/under recovery true-up amounts.
In 1994, the Company accrued a liability of $7.8 million for the estimated
costs of environmental remediation projects for known sites. These estimated
costs are expected to be expended during the period 1995 to 1999. These projects
have been approved by the FPSC for recovery through the ECR clause discussed
above. Therefore, the Company recorded $2.1 million in current assets and $5.7
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 $62 million in 1995, $76 million in 1996, and
$84 million in 1997. 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, 1994, significant purchase commitments were outstanding in
connection with the construction program. The Company does not have any new
II-164
NOTES (continued)
Gulf Power Company 1994 Annual Report
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 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, 1994, the Company had $25 million in revolving credit lines
subject to renewal June 1, 1997, and $22 million of lines of credit with banks
subject to renewal June 1 of each year. In connection with these credit lines,
the Company has agreed to pay certain fees and/or maintain compensating balances
with the banks. The compensating balances, which represent substantially all the
cash of the Company except for daily working funds and like items, are not
legally restricted from withdrawal. The Company had $19 million of these lines
of credit committed at December 31, 1994. In addition, the Company has bid-loan
facilities with fourteen major money center banks that total $275 million, of
which $34.5 million was committed at December 31, 1994.
Assets Subject to Lien
The Company's mortgage, which secures the first mortgage bonds issued by the
Company, constitutes a direct first lien on substantially all of the Company's
fixed property and franchises.
Fuel Commitments
To supply a portion of the fuel requirements of its generating plants, the
Company has entered into long-term commitments for the procurement of fuel. In
most cases, these contracts contain provisions for price escalations, minimum
purchase levels, and other financial commitments. Total estimated long-term
obligations were approximately $1.1 billion at December 31, 1994. Additional
commitments will be required in the future to supply the Company's fuel needs.
To take advantage of lower-cost coal supplies, agreements were reached in
1986 to terminate two long-term contracts for the supply of coal to Plant
Daniel, which is jointly owned by the Company and Mississippi Power, an
operating affiliate. The Company's portion of this payment was $60 million. This
amount is being amortized to expense on a per ton basis over a nine-year period
ending in 1995. The remaining unamortized amount was $10.1 million at December
31, 1994.
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 $30.5 million
at December 31, 1994.
Also, in 1993, the Company made a payment of $16.4 million to a coal supplier
under an arrangement to suspend the purchase of coal under an existing contract
for one year. This amount was amortized to expense on a per ton basis during
1993 and 1994, with a remainder of $118 thousand to be amortized to expense in
the first quarter of 1995.
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.
II-165
NOTES (continued)
Gulf Power Company 1994 Annual Report
Lease Agreements
In 1989, the Company and Mississippi Power Company jointly entered into a
twenty-two year operating lease agreement for the use of 495 aluminum railcars.
In 1995, a second lease agreement for the use of 250 additional aluminum
railcars will begin and continue 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 were $1.2
million in 1994, 1993, and 1992. For the year 1995, the Company's annual lease
payments associated with both leases will be approximately $2.6 million. The
Company's annual lease payments for 1996 through 1999 will be approximately $1.7
million and after 1999, lease payments total approximately $26.0 million. The
Company has the option after three years from the date of the original contract
on each lease to purchase the respective number of 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.
6. JOINT OWNERSHIP AGREEMENTS
The Company and Mississippi Power jointly own Plant Daniel, a steam-electric
generating plant, located in Jackson County, Mississippi. In accordance with an
operating agreement, Mississippi Power acts as the Company's agent with respect
to the construction, operation, and maintenance of the plant.
The Company and Georgia Power jointly own Plant Scherer Unit No. 3, a
steam-electric generating plant, located near Forsyth, Georgia. In accordance
with an operating agreement, Georgia Power acts as the Company's agent with
respect to the construction, operation, and maintenance of the unit.
The Company's pro rata share of expenses related to both plants is included
in the corresponding operating expense accounts in the Statements of Income.
At December 31, 1994, the Company's percentage ownership and its amount of
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 $185,339(1) $220,125
Accumulated Depreciation $45,814 $93,110
Construction Work in Progress $941 $1,163
Nameplate Capacity (2)
(In megawatts) 205 500
Ownership 25% 50%
================================================================
(1) Includes net plant acquisition adjustment.
(2) Total megawatt nameplate capacity:
Plant Scherer Unit No. 3: 818
Plant Daniel: 1,000
7. LONG-TERM POWER SALES AGREEMENTS
General
The Company and the other operating affiliates of The Southern Company 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:
================================================================
Other
Unit Long-
Year Power Term Total
---- -----------------------------------------
(in thousands)
1994 $29,653 $1,273 $30,926
1993 31,162 2,643 33,805
1992 32,679 1,501 34,180
================================================================
II-166
NOTES (continued)
Gulf Power Company 1994 Annual Report
In 1994, long-term non-firm power of 200 megawatts was sold to Florida Power
Corporation (FPC) under a contract that expired at year-end. Capacity and energy
sales under these long-term non-firm power sales agreements were made from
available power pool capacity, and the revenues from the sales were shared by
the operating affiliates.
Unit power from specific generating plants is currently being sold to FPC,
Florida Power & Light Company (FP&L), Jacksonville Electric Authority (JEA), and
the City of Tallahassee, Florida. Under these agreements, 210 megawatts of net
dependable capacity were sold by the Company during 1994, 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 $29.3 million in 1994, $39.5 million in 1993, and $46.2
million in 1992, or 5.1 percent, 6.8 percent, and 8.1 percent of operating
revenues, respectively.
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, 1994, the tax-related regulatory assets to be recovered from
customers were $30.4 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, 1994, the tax-related regulatory liabilities
to be refunded to customers were $72.0 million. 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:
=================================================================
1994 1993 1992
-----------------------------
(in thousands)
Total provision for income taxes:
Federal--
Currently payable $34,941 $24,354 $24,287
Deferred--current year 18,556 26,396 18,173
--reversal of
prior years (24,787) (22,102) (15,506)
-----------------------------------------------------------------
28,710 28,648 26,954
-----------------------------------------------------------------
State--
Currently payable 5,907 3,950 4,282
Deferred--current year 2,549 3,838 2,662
--reversal of
prior years (3,304) (2,785) (2,007)
-----------------------------------------------------------------
5,152 5,003 4,937
-----------------------------------------------------------------
Total 33,862 33,651 31,891
Less income taxes charged
(credited) to other income (95) 921 (187)
-----------------------------------------------------------------
Federal and state income
taxes charged
to operations $33,957 $32,730 $32,078
=================================================================
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:
=====================================================================
1994 1993
-----------------------
(in thousands)
Deferred tax liabilities:
Accelerated depreciation $146,686 $146,657
Property basis differences 18,468 15,140
Coal contract buyout 6,896 15,427
Other 11,846 6,724
---------------------------------------------------------------------
Total 183,896 183,948
---------------------------------------------------------------------
Federal effect of state deferred taxes 9,732 10,136
Postretirement benefits 4,383 3,406
Property insurance 5,200 4,730
Other 7,566 6,500
---------------------------------------------------------------------
Total 26,881 24,772
---------------------------------------------------------------------
Net deferred tax liabilities 157,015 159,176
Portion included in current liabilities, net 5,334 7,433
---------------------------------------------------------------------
Accumulated deferred income
taxes in the Balance Sheets $151,681 $151,743
=====================================================================
II-167
NOTES (continued)
Gulf Power Company 1994 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 Statements of Income. Credits amortized in this manner
amounted to $2.3 million in 1994, 1993 and 1992. At December 31, 1994, 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:
=============================================================
1994 1993 1992
--------------------------
Federal statutory rate 35% 35% 34%
State income tax,
net of federal deduction 4 3 4
Non-deductible book
depreciation 1 1 1
Difference in prior years'
deferred and current tax rate (2) (2) (2)
Other (2) (1) (2)
-------------------------------------------------------------
Effective income tax rate 36% 36% 35%
=============================================================
The Company and the other subsidiaries of The Southern Company file a
consolidated federal tax return. Under a joint consolidated income tax
agreement, each company's current and deferred tax expense is computed on a
stand-alone basis, and consolidated tax savings are allocated to each company
based on its ratio of taxable income to total consolidated taxable income.
9. POLLUTION CONTROL OBLIGATIONS AND OTHER LONG-TERM DEBT
Details of long-term debt are as follows:
==============================================================
December 31,
1994 1993
----------------------
(in thousands)
Obligations incurred in
connection with the sale by
public authorities of
tax-exempt pollution control
revenue bonds:
Collateralized
6% due 2006* $ 12,200 $ 12,300
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 -
Variable Rate
Remarketed daily 20,000 -
Non-collateralized
10.50% due 2014 - 42,000
--------------------------------------------------------------
$169,755 $169,855
--------------------------------------------------------------
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 16,388 -
8.25% due 1995 - 17,520
--------------------------------------------------------------
50,388 42,520
--------------------------------------------------------------
Total $220,143 $212,375
==============================================================
* Sinking fund requirement applicable to the 6 percent pollution control
bonds is $125 thousand for 1995 with increasing increments 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.
II-168
NOTES (continued)
Gulf Power Company 1994 Annual Report
The 5.39 percent and 5.72 percent notes payable are 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). These
notes refinanced the remaining balance of the 8.25 percent note payable. The
proceeds from the 6.44 percent note were used to refinance the remaining balance
of the 9.2 percent first mortgage bond, which was redeemed in June, 1994. The
estimated annual maturities of the notes payable through 1998 are as follows:
$13.3 million in 1995, $29.6 million in 1996, $4.9 million in 1997, and $2.6
million in 1998.
10. LONG-TERM DEBT DUE WITHIN ONE YEAR
A summary of the improvement fund requirement and scheduled maturities and
redemptions of long-term debt due within one year is as follows:
==============================================================
December 31
1994 1993
--------------------
(in thousands)
Bond improvement fund requirement $ 1,750 $ 2,370
Less: Portion to be satisfied by cash
or certifying property
additions 1,750 -
--------------------------------------------------------------
Cash sinking fund requirement - 2,370
Maturities of first mortgage bonds - 3,676
Redemptions of first mortgage bonds - 27,000
Current portion of notes payable 13,314 8,406
(Note 9)
Pollution control bond maturity 125 100
(Note 9)
--------------------------------------------------------------
Total $13,439 $41,552
==============================================================
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.
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, 1994, $101 million of retained earnings was
restricted against the payment of cash dividends on common stock under the terms
of the mortgage indenture.
The Company's charter limits cash dividends on common stock to 50 percent of
net income available for such stock during a prior period 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, 1994, the ratio was 47.2 percent.
12. QUARTERLY FINANCIAL DATA (Unaudited)
Summarized quarterly financial data for 1994 and 1993 are as follows:
=================================================================
Net Income
After Dividends
Operating Operating on Preferred
Quarter Ended Revenues Income Stock
-----------------------------------------------------------------
(in thousands)
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
March 31, 1993 $127,036 $17,646 $10,426
June 30, 1993 138,863 19,562 7,312
Sept. 30, 1993 175,964 32,783 22,366
Dec. 31, 1993 141,279 22,596 14,207
=================================================================
The Company's business is influenced by seasonal weather conditions and the
timing of rate changes, among other factors.
II-169
SELECTED FINANCIAL AND OPERATING DATA
Gulf Power Company 1994 Annual Report
====================================================================================================
1994 1993 1992
----------------------------------------------------------------------------------------------------
Operating Revenues (in thousands) $578,813 $583,142 $570,902
Net Income after Dividends
on Preferred Stock (in thousands) $55,229 $54,311 $54,090
Cash Dividends on Common Stock (in thousands) $44,000 $41,800 $39,900
Return on Average Common Equity (percent) 13.15 13.29 13.62
Total Assets (in thousands) $1,315,542 $1,307,809 $1,062,699
Gross Property Additions (in thousands) $78,869 $78,562 $64,671
----------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $425,472 $414,196 $403,190
Preferred stock 89,602 89,602 74,662
Preferred stock subject to mandatory redemption - 1,000 2,000
Long-term debt 356,393 369,259 382,047
----------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $871,467 $874,057 $861,899
----------------------------------------------------------------------------------------------------
Capitalization Ratios (percent):
Common stock equity 48.8 47.4 46.8
Preferred stock 10.3 10.4 8.9
Long-term debt 40.9 42.2 44.3
----------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0 100.0
====================================================================================================
First Mortgage Bonds (in thousands):
Issued - 75,000 25,000
Retired 48,856 88,809 117,693
Preferred Stock (in thousands):
Issued - 35,000 29,500
Retired 1,000 21,060 15,500
----------------------------------------------------------------------------------------------------
Security Ratings:
First Mortgage Bonds -
Moody's A2 A2 A2
Standard and Poor's A A A
Duff & Phelps A+ A+ A
Preferred Stock -
Moody's a2 a2 a2
Standard and Poor's A- A- A-
Duff & Phelps A A A-
----------------------------------------------------------------------------------------------------
Customers (year-end):
Residential 280,859 274,194 267,591
Commercial 40,398 39,253 37,105
Industrial 283 274 270
Other 106 86 74
----------------------------------------------------------------------------------------------------
Total 321,646 313,807 305,040
====================================================================================================
Employees (year-end) 1,540 1,565 1,613
II-170
SELECTED FINANCIAL AND OPERATING DATA
Gulf Power Company 1994 Annual Report
====================================================================================================
1991 1990 1989
----------------------------------------------------------------------------------------------------
Operating Revenues (in thousands) $565,207 $567,825 $527,821
Net Income after Dividends
on Preferred Stock (in thousands) $57,796 $38,714 $37,361
Cash Dividends on Common Stock (in thousands) $38,000 $37,000 $37,200
Return on Average Common Equity (percent) 15.17 10.51 10.32
Total Assets (in thousands) $1,095,736 $1,084,579 $1,093,430
Gross Property Additions (in thousands) $64,323 $62,462 $70,726
----------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $390,981 $371,185 $365,471
Preferred stock 55,162 55,162 55,162
Preferred stock subject to mandatory redemption 7,500 9,250 11,000
Long-term debt 434,648 475,284 484,608
----------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $888,291 $910,881 $916,241
----------------------------------------------------------------------------------------------------
Capitalization Ratios (percent):
Common stock equity 44.0 40.8 39.9
Preferred stock 7.1 7.1 7.2
Long-term debt 48.9 52.1 52.9
----------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0 100.0
====================================================================================================
First Mortgage Bonds (in thousands):
Issued 50,000 - -
Retired 32,807 6,455 9,344
Preferred Stock (in thousands):
Issued - - -
Retired 2,500 1,750 1,250
----------------------------------------------------------------------------------------------------
Security Ratings:
First Mortgage Bonds -
Moody's A2 A2 A1
Standard and Poor's A A A
Duff & Phelps A A AA-
Preferred Stock -
Moody's a2 a2 a1
Standard and Poor's A- A- A-
Duff & Phelps A- A- A+
----------------------------------------------------------------------------------------------------
Customers (year-end):
Residential 261,210 256,111 251,341
Commercial 34,685 34,019 33,678
Industrial 264 252 240
Other 72 67 67
----------------------------------------------------------------------------------------------------
Total 296,231 290,449 285,326
====================================================================================================
Employees (year-end) 1,598 1,615 1,614
II-171A
SELECTED FINANCIAL AND OPERATING DATA
Gulf Power Company 1994 Annual Report
====================================================================================================
1988 1987 1986
----------------------------------------------------------------------------------------------------
Operating Revenues (in thousands) $550,827 $587,860 $542,919
Net Income after Dividends
on Preferred Stock (in thousands) $45,698 $42,217 $46,421
Cash Dividends on Common Stock (in thousands) $35,400 $34,200 $33,100
Return on Average Common Equity (percent) 13.41 13.23 15.06
Total Assets (in thousands) $1,097,225 $1,051,182 $1,028,864
Gross Property Additions (in thousands) $67,042 $97,511 $90,160
----------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $358,310 $323,012 $314,995
Preferred stock 55,162 55,162 55,162
Preferred stock subject to mandatory redemption 12,750 14,000 16,500
Long-term debt 497,069 474,640 482,869
----------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $923,291 $866,814 $869,526
----------------------------------------------------------------------------------------------------
Capitalization Ratios (percent):
Common stock equity 38.8 37.2 36.2
Preferred stock 7.4 8.0 8.3
Long-term debt 53.8 54.8 55.5
----------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0 100.0
====================================================================================================
First Mortgage Bonds (in thousands):
Issued 35,000 - 50,000
Retired 9,369 - 46,640
Preferred Stock (in thousands):
Issued - - -
Retired 1,750 2,500 750
----------------------------------------------------------------------------------------------------
Security Ratings:
First Mortgage Bonds -
Moody's A1 A1 A1
Standard and Poor's A A A+
Duff & Phelps 4 4 4
Preferred Stock -
Moody's a1 a1 a1
Standard and Poor's A- A- A
Duff & Phelps 5 5 5
----------------------------------------------------------------------------------------------------
Customers (year-end):
Residential 246,450 241,138 235,329
Commercial 33,030 32,139 31,142
Industrial 206 206 197
Other 61 61 62
----------------------------------------------------------------------------------------------------
Total 279,747 273,544 266,730
====================================================================================================
Employees (year-end) 1,601 1,603 1,544
II-171B
SELECTED FINANCIAL AND OPERATING DATA
Gulf Power Company 1994 Annual Report
======================================================================================
1985 1984
--------------------------------------------------------------------------------------
Operating Revenues (in thousands) $562,068 $505,812
Net Income after Dividends
on Preferred Stock (in thousands) $45,484 $40,336
Cash Dividends on Common Stock (in thousands) $30,800 $27,200
Return on Average Common Equity (percent) 15.61 15.11
Total Assets (in thousands) $921,635 $892,924
Gross Property Additions (in thousands) $92,541 $156,443
--------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $301,674 $280,990
Preferred stock 55,162 55,162
Preferred stock subject to mandatory redemption 18,250 19,000
Long-term debt 410,917 394,859
--------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $786,003 $750,011
--------------------------------------------------------------------------------------
Capitalization Ratios (percent):
Common stock equity 38.4 37.5
Preferred stock 9.3 9.9
Long-term debt 52.3 52.6
--------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0
======================================================================================
First Mortgage Bonds (in thousands):
Issued - -
Retired 2,860 10,415
Preferred Stock (in thousands):
Issued - -
Retired 750 1,500
--------------------------------------------------------------------------------------
Security Ratings:
First Mortgage Bonds -
Moody's A1 A1
Standard and Poor's A+ A+
Duff & Phelps 4 4
Preferred Stock -
Moody's a1 a1
Standard and Poor's A A
Duff & Phelps 5 5
--------------------------------------------------------------------------------------
Customers (year-end):
Residential 227,845 217,138
Commercial 29,603 27,939
Industrial 183 177
Other 62 63
--------------------------------------------------------------------------------------
Total 257,693 245,317
======================================================================================
Employees (year-end) 1,509 1,460
II-171C
SELECTED FINANCIAL AND OPERATING DATA (continued)
Gulf Power Company 1994 Annual Report
====================================================================================================
1994 1993 1992
----------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $252,598 $244,967 $235,296
Commercial 146,394 137,308 133,071
Industrial 82,169 87,526 91,320
Other 1,955 1,882 1,784
----------------------------------------------------------------------------------------------------
Total retail 483,116 471,683 461,471
Sales for resale - non-affiliates 66,111 72,209 70,078
Sales for resale - affiliates 17,353 23,166 24,075
----------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 566,580 567,058 555,624
Other revenues 12,233 16,084 15,278
----------------------------------------------------------------------------------------------------
Total $578,813 $583,142 $570,902
====================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 3,751,932 3,712,980 3,596,515
Commercial 2,548,846 2,433,382 2,369,236
Industrial 1,847,114 2,029,936 2,179,435
Other 17,354 16,944 16,649
----------------------------------------------------------------------------------------------------
Total retail 8,165,246 8,193,242 8,161,835
Sales for resale - non-affiliates 1,418,977 1,460,105 1,430,908
Sales for resale - affiliates 874,050 1,029,787 1,208,771
----------------------------------------------------------------------------------------------------
Total 10,458,273 10,683,134 10,801,514
====================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 6.73 6.60 6.54
Commercial 5.74 5.64 5.62
Industrial 4.45 4.31 4.19
Total retail 5.92 5.76 5.65
Sales for resale 3.64 3.83 3.57
Total sales 5.42 5.31 5.14
Average Annual Kilowatt-Hour Use Per Residential Customer 13,486 13,671 13,553
Average Annual Revenue Per Residential Customer $907.92 $901.96 $886.66
Plant Nameplate Capacity Ratings (year-end) (megawatts) 2,174 2,174 2,174
Maximum Peak-Hour Demand (megawatts):
Winter 1,801 1,571 1,533
Summer 1,795 1,898 1,828
Annual Load Factor (percent) 56.7 54.5 55.0
Plant Availability - Fossil-Steam (percent) 92.2 88.9 91.2
----------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 87.2 84.5 87.7
Oil and gas 0.2 0.5 0.1
Purchased power -
From non-affiliates 2.8 1.5 0.8
From affiliates 9.8 13.5 11.4
----------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0
====================================================================================================
Total Fuel Economy Data:
BTU per net kilowatt-hour generated 10,614 10,390 10,347
Cost of fuel per million BTU (cents) 189.55 197.37 200.30
Average cost of fuel per net kilowatt-hour generated (cents) 2.01 2.05 2.07
====================================================================================================
II-172
SELECTED FINANCIAL AND OPERATING DATA (continued)
Gulf Power Company 1994 Annual Report
====================================================================================================
1991 1990 1989
----------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $231,220 $217,843 $203,781
Commercial 130,691 124,066 118,897
Industrial 92,300 91,041 84,671
Other 1,860 1,805 1,586
----------------------------------------------------------------------------------------------------
Total retail 456,071 434,755 408,935
Sales for resale - non-affiliates 69,636 73,855 67,554
Sales for resale - affiliates 29,343 38,563 39,244
----------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 555,050 547,173 515,733
Other revenues 10,157 20,652 12,088
----------------------------------------------------------------------------------------------------
Total $565,207 $567,825 $527,821
====================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 3,455,100 3,360,838 3,293,750
Commercial 2,272,690 2,217,568 2,169,497
Industrial 2,117,408 2,177,872 2,094,670
Other 17,118 18,866 17,209
----------------------------------------------------------------------------------------------------
Total retail 7,862,316 7,775,144 7,575,126
Sales for resale - non-affiliates 1,550,018 1,775,703 1,640,355
Sales for resale - affiliates 1,236,223 1,435,558 1,461,036
----------------------------------------------------------------------------------------------------
Total 10,648,557 10,986,405 10,676,517
====================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 6.69 6.48 6.19
Commercial 5.75 5.59 5.48
Industrial 4.36 4.18 4.04
Total retail 5.80 5.59 5.40
Sales for resale 3.55 3.50 3.44
Total sales 5.21 4.98 4.83
Average Annual Kilowatt-Hour Use Per Residential Customer 13,320 13,173 13,173
Average Annual Revenue Per Residential Customer $891.38 $853.86 $815.00
Plant Nameplate Capacity Ratings (year-end) (megawatts) 2,174 2,174 2,174
Maximum Peak-Hour Demand (megawatts):
Winter 1,418 1,310 1,814
Summer 1,740 1,778 1,691
Annual Load Factor (percent) 57.0 55.2 52.6
Plant Availability - Fossil-Steam (percent) 92.2 89.2 89.1
----------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 82.0 69.8 78.3
Oil and gas 0.1 0.5 0.2
Purchased power -
From non-affiliates 0.5 0.6 0.4
From affiliates 17.4 29.1 21.1
----------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0
====================================================================================================
Total Fuel Economy Data:
BTU per net kilowatt-hour generated 10,636 10,765 10,621
Cost of fuel per million BTU (cents) 203.60 206.06 193.70
Average cost of fuel per net kilowatt-hour generated (cents) 2.17 2.22 2.06
====================================================================================================
II-173A
SELECTED FINANCIAL AND OPERATING DATA (continued)
Gulf Power Company 1994 Annual Report
====================================================================================================
1988 1987 1986
----------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $184,036 $199,701 $200,725
Commercial 107,615 116,057 116,253
Industrial 72,634 80,295 79,873
Other 1,402 1,357 1,343
----------------------------------------------------------------------------------------------------
Total retail 365,687 397,410 398,194
Sales for resale - non-affiliates 117,466 134,456 106,892
Sales for resale - affiliates 48,277 55,955 27,113
----------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 531,430 587,821 532,199
Other revenues 19,397 39 10,720
----------------------------------------------------------------------------------------------------
Total $550,827 $587,860 $542,919
====================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 3,154,541 3,055,041 2,963,502
Commercial 2,088,598 1,986,332 1,913,139
Industrial 1,968,091 1,839,931 1,745,074
Other 16,257 15,241 14,903
----------------------------------------------------------------------------------------------------
Total retail 7,227,487 6,896,545 6,636,618
Sales for resale - non-affiliates 1,911,759 2,138,390 1,609,146
Sales for resale - affiliates 2,326,238 2,689,487 1,078,500
----------------------------------------------------------------------------------------------------
Total 11,465,484 11,724,422 9,324,264
====================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 5.83 6.54 6.77
Commercial 5.15 5.84 6.08
Industrial 3.69 4.36 4.58
Total retail 5.06 5.76 6.00
Sales for resale 3.91 3.94 4.99
Total sales 4.64 5.01 5.71
Average Annual Kilowatt-Hour Use Per Residential Customer 12,883 12,763 12,729
Average Annual Revenue Per Residential Customer $751.60 $834.31 $862.16
Plant Nameplate Capacity Ratings (year-end) (megawatts) 2,174 2,174 1,969
Maximum Peak-Hour Demand (megawatts):
Winter 1,395 1,354 1,406
Summer 1,613 1,617 1,678
Annual Load Factor (percent) 56.5 54.4 50.5
Plant Availability - Fossil-Steam (percent) 88.2 92.8 90.5
----------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 93.2 93.5 85.8
Oil and gas 0.4 0.4 0.5
Purchased power -
From non-affiliates 0.4 0.4 1.9
From affiliates 6.0 5.7 11.8
----------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0
====================================================================================================
Total Fuel Economy Data:
BTU per net kilowatt-hour generated 10,461 10,512 10,639
Cost of fuel per million BTU (cents) 178.00 197.53 239.26
Average cost of fuel per net kilowatt-hour generated (cents) 1.86 2.08 2.55
====================================================================================================
II-173B
SELECTED FINANCIAL AND OPERATING DATA (continued)
Gulf Power Company 1994 Annual Report
======================================================================================
1985 1984
--------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $186,415 $174,302
Commercial 109,631 98,408
Industrial 81,621 83,538
Other 1,346 1,334
--------------------------------------------------------------------------------------
Total retail 379,013 357,582
Sales for resale - non-affiliates 126,789 106,802
Sales for resale - affiliates 43,844 35,712
--------------------------------------------------------------------------------------
Total revenues from sales of electricity 549,646 500,096
Other revenues 12,422 5,716
--------------------------------------------------------------------------------------
Total $562,068 $505,812
======================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 2,736,432 2,560,648
Commercial 1,777,418 1,559,344
Industrial 1,770,587 1,771,100
Other 14,702 14,555
--------------------------------------------------------------------------------------
Total retail 6,299,139 5,905,647
Sales for resale - non-affiliates 2,388,591 2,183,631
Sales for resale - affiliates 1,562,452 1,308,410
--------------------------------------------------------------------------------------
Total 10,250,182 9,397,688
======================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 6.81 6.81
Commercial 6.17 6.31
Industrial 4.61 4.72
Total retail 6.02 6.05
Sales for resale 4.32 4.08
Total sales 5.36 5.32
Average Annual Kilowatt-Hour Use Per Residential Customer 12,221 12,057
Average Annual Revenue Per Residential Customer $832.55 $820.71
Plant Nameplate Capacity Ratings (year-end) (megawatts) 1,969 1,969
Maximum Peak-Hour Demand (megawatts):
Winter 1,517 1,209
Summer 1,448 1,381
Annual Load Factor (percent) 53.4 54.9
Plant Availability - Fossil-Steam (percent) 84.8 87.7
--------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 79.7 83.9
Oil and gas 0.2 0.2
Purchased power -
From non-affiliates 0.4 (1.4)
From affiliates 19.7 17.3
--------------------------------------------------------------------------------------
Total 100.0 100.0
======================================================================================
Total Fuel Economy Data:
BTU per net kilowatt-hour generated 10,609 10,639
Cost of fuel per million BTU (cents) 254.53 240.40
Average cost of fuel per net kilowatt-hour generated (cents) 2.70 2.60
=======================================================================================
II-173C
STATEMENTS OF INCOME
Gulf Power Company
==============================================================================================
For the Years Ended December 31, 1994 1993 1992
----------------------------------------------------------------------------------------------
(Thousands of Dollars)
Operating Revenues:
Revenues $ 561,460 $559,976 $546,827
Revenues from affiliates 17,353 23,166 24,075
----------------------------------------------------------------------------------------------
Total operating revenues 578,813 583,142 570,902
----------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
Fuel 161,168 170,485 182,754
Purchased power from non-affiliates 6,761 4,386 1,394
Purchased power from affiliates 25,819 32,273 26,788
Proceeds from settlement of disputed contracts - - (920)
Other 113,879 109,164 98,230
Maintenance 46,700 46,004 41,947
Depreciation and amortization 56,615 55,309 53,758
Taxes other than income taxes 41,701 40,204 37,898
Federal and state income taxes 33,957 32,730 32,078
----------------------------------------------------------------------------------------------
Total operating expenses 486,600 490,555 473,927
----------------------------------------------------------------------------------------------
Operating Income 92,213 92,587 96,975
Other Income (Expense):
Allowance for equity funds used during construction 450 512 14
Interest income 1,429 1,328 2,733
Other, net (780) (1,238) (1,487)
Gain on sale of investment securities - 3,820 -
Income taxes applicable to other income 95 (921) 187
----------------------------------------------------------------------------------------------
Income Before Interest Charges 93,407 96,088 98,422
----------------------------------------------------------------------------------------------
Interest Charges:
Interest on long-term debt 27,124 31,344 35,792
Allowance for debt funds used during construction (656) (454) (46)
Interest on notes payable 1,509 870 1,041
Amortization of debt discount, premium, and expense, net 1,834 1,412 1,032
Other interest charges 2,442 2,877 1,410
----------------------------------------------------------------------------------------------
Net interest charges 32,253 36,049 39,229
----------------------------------------------------------------------------------------------
Net Income 61,154 60,039 59,193
Dividends on Preferred Stock 5,925 5,728 5,103
----------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred Stock $ 55,229 $ 54,311 $ 54,090
==============================================================================================
II-174
STATEMENTS OF INCOME
Gulf Power Company
======================================================================================================
For the Years Ended December 31, 1991 1990 1989 1988
------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Operating Revenues:
Revenues $ 535,864 $529,262 $488,577 $502,550
Revenues from affiliates 29,343 38,563 39,244 48,277
------------------------------------------------------------------------------------------------------
Total operating revenues 565,207 567,825 527,821 550,827
------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
Fuel 176,038 156,712 158,858 191,687
Purchased power from non-affiliates 896 1,427 1,251 1,468
Purchased power from affiliates 32,579 67,729 48,972 27,267
Proceeds from settlement of disputed contracts (20,385) - - -
Other 94,411 90,045 82,231 93,028
Maintenance 45,468 45,491 44,295 41,919
Depreciation and amortization 52,195 50,899 48,760 47,530
Taxes other than income taxes 42,359 39,110 30,718 27,087
Federal and state income taxes 33,893 24,780 23,621 26,239
------------------------------------------------------------------------------------------------------
Total operating expenses 457,454 476,193 438,706 456,225
------------------------------------------------------------------------------------------------------
Operating Income 107,753 91,632 89,115 94,602
Other Income (Expense):
Allowance for equity funds used during construction 54 - (446) 457
Interest income 2,427 4,508 3,271 2,858
Other, net (3,484) (6,360) (3,800) (3,491)
Gain on sale of investment securities - - - -
Income taxes applicable to other income 1,104 1,303 779 1,001
------------------------------------------------------------------------------------------------------
Income Before Interest Charges 107,854 91,083 88,919 95,427
------------------------------------------------------------------------------------------------------
Interest Charges:
Interest on long-term debt 41,665 43,215 43,265 42,538
Allowance for debt funds used during construction (95) 1 242 (808)
Interest on notes payable 280 693 180 182
Amortization of debt discount, premium, and expense, net 699 603 613 600
Other interest charges 2,272 2,422 1,636 1,456
------------------------------------------------------------------------------------------------------
Net interest charges 44,821 46,934 45,936 43,968
------------------------------------------------------------------------------------------------------
Net Income 63,033 44,149 42,983 51,459
Dividends on Preferred Stock 5,237 5,435 5,622 5,761
------------------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred Stock $ 57,796 $ 38,714 $ 37,361 $ 45,698
======================================================================================================
II-175A
STATEMENTS OF INCOME
Gulf Power Company
======================================================================================================
For the Years Ended December 31, 1987 1986 1985 1984
------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Operating Revenues:
Revenues $ 531,905 $515,806 $518,224 $470,100
Revenues from affiliates 55,955 27,113 43,844 35,712
------------------------------------------------------------------------------------------------------
Total operating revenues 587,860 542,919 562,068 505,812
------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
Fuel 227,233 215,262 230,944 214,885
Purchased power from non-affiliates 1,792 4,533 1,638 (3,698)
Purchased power from affiliates 28,326 37,172 55,119 42,967
Proceeds from settlement of disputed contracts - - - -
Other 100,032 70,117 59,851 56,352
Maintenance 38,748 35,251 35,654 28,773
Depreciation and amortization 44,619 39,386 37,775 33,061
Taxes other than income taxes 26,246 24,854 22,886 21,696
Federal and state income taxes 31,703 39,948 40,061 35,831
------------------------------------------------------------------------------------------------------
Total operating expenses 498,699 466,523 483,928 429,867
------------------------------------------------------------------------------------------------------
Operating Income 89,161 76,396 78,140 75,945
Other Income (Expense):
Allowance for equity funds used during construction 1,013 7,809 6,893 2,877
Interest income 4,507 2,445 3,235 8,777
Other, net (1,207) (1,077) (1,131) (704)
Gain on sale of investment securities - - - -
Income taxes applicable to other income (642) (648) (862) (3,524)
------------------------------------------------------------------------------------------------------
Income Before Interest Charges 92,832 84,925 86,275 83,371
------------------------------------------------------------------------------------------------------
Interest Charges:
Interest on long-term debt 43,689 39,479 40,769 36,952
Allowance for debt funds used during construction (1,004) (8,651) (7,676) (3,261)
Interest on notes payable - 106 - 1,628
Amortization of debt discount, premium, and expense, net 555 488 287 265
Other interest charges 1,350 869 1,120 1,111
------------------------------------------------------------------------------------------------------
Net interest charges 44,590 32,291 34,500 36,695
------------------------------------------------------------------------------------------------------
Net Income 48,242 52,634 51,775 46,676
Dividends on Preferred Stock 6,025 6,213 6,291 6,340
------------------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred Stock $ 42,217 $ 46,421 $ 45,484 $ 40,336
======================================================================================================
II-175B
STATEMENTS OF CASH FLOWS
Gulf Power Company
============================================================================================================
For the Years Ended December 31, 1994 1993 1992
------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Operating Activities:
Net income $ 61,154 $ 60,039 $ 59,193
Adjustments to reconcile net income to net
cash provided by operating activities --
Depreciation and amortization 86,098 72,111 68,021
Deferred income taxes, net (6,986) 5,347 3,322
Deferred investment tax credits, net - - -
Allowance for equity funds used during construction (450) (512) (14)
Non-cash proceeds from settlement of disputed contracts - - (920)
Other, net 4,898 (864) 185
Changes in certain current assets and liabilities --
Receivables, net 3,540 12,867 (11,041)
Inventories (13,901) 5,574 23,560
Payables (10,159) 5,386 1,580
Other 610 (9,504) (13,637)
------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities 124,804 150,444 130,249
------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (78,869) (78,562) (64,671)
Other (3,493) (5,328) 3,970
------------------------------------------------------------------------------------------------------------
Net cash used for investing activities (82,362) (83,890) (60,701)
------------------------------------------------------------------------------------------------------------
Financing Activities and Capital Contributions:
Proceeds:
Preferred stock - 35,000 29,500
First mortgage bonds - 75,000 25,000
Pollution control bonds 42,000 53,425 8,930
Capital contributions from parent company 98 11 121
Other long-term debt 32,108 25,000 -
Retirements:
Preferred stock (1,000) (21,060) (15,500)
First mortgage bonds (48,856) (88,809) (117,693)
Pollution control bonds (42,100) (40,650) (9,205)
Other long-term debt (24,240) (7,736) (5,783)
Notes payable, net 47,447 (37,947) 44,000
Payment of preferred stock dividends (5,925) (5,728) (5,103)
Payment of common stock dividends (44,000) (41,800) (39,900)
Miscellaneous (2,648) (6,888) (8,760)
------------------------------------------------------------------------------------------------------------
Net cash provided from (used for) financing activities (47,116) (62,182) (94,393)
------------------------------------------------------------------------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents (4,674) 4,372 (24,845)
Cash and Cash Equivalents at Beginning of Year 5,576 1,204 26,049
------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 902 $ 5,576 $ 1,204
============================================================================================================
( ) Denotes use of cash.
II-176
STATEMENTS OF CASH FLOWS
Gulf Power Company
==========================================================================================================================
For the Years Ended December 31, 1991 1990 1989 1988
--------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Operating Activities:
Net income $ 63,033 $ 44,149 $ 42,983 $ 51,459
Adjustments to reconcile net income to net
cash provided by operating activities --
Depreciation and amortization 65,584 63,650 59,955 56,260
Deferred income taxes, net (3,392) 1,837 5,319 10,138
Deferred investment tax credits, net - - - -
Allowance for equity funds used during construction (54) - 446 (457)
Non-cash proceeds from settlement of disputed contracts (19,734) - - -
Other, net 3,079 1,544 3,827 11,449
Changes in certain current assets and liabilities --
Receivables, net 12,421 (2,468) 492 8,984
Inventories (2,397) (11,807) 16,306 (16,160)
Payables (2,003) (3,440) 6,142 (5,340)
Other 8,012 5,781 4,466 (18,432)
--------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities 124,549 99,246 139,936 97,901
--------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (64,323) (62,462) (70,726) (67,042)
Other (8,097) (1,597) 419 (62,782)
--------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities (72,420) (64,059) (70,307) (129,824)
--------------------------------------------------------------------------------------------------------------------------
Financing Activities and Capital Contributions:
Proceeds:
Preferred stock - - - -
First mortgage bonds 50,000 - - 35,000
Pollution control bonds 21,200 - - 3,677
Capital contributions from parent company - 4,000 7,000 25,000
Other long-term debt - - - -
Retirements:
Preferred stock (2,500) (1,750) (1,250) (1,750)
First mortgage bonds (32,807) (6,455) (9,344) (9,369)
Pollution control bonds (21,250) (50) (50) (50)
Other long-term debt (7,981) (6,083) (5,611) (5,175)
Notes payable, net - - - -
Payment of preferred stock dividends (5,237) (5,435) (5,622) (5,761)
Payment of common stock dividends (38,000) (37,000) (37,200) (35,400)
Miscellaneous (3,715) 5 (3) (233)
--------------------------------------------------------------------------------------------------------------------------
Net cash provided from (used for) financing activities (40,290) (52,768) (52,080) 5,939
--------------------------------------------------------------------------------------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents 11,839 (17,581) 17,549 (25,984)
Cash and Cash Equivalents at Beginning of Year 14,210 31,791 14,242 40,226
--------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 26,049 $ 14,210 $ 31,791 $ 14,242
==========================================================================================================================
( ) Denotes use of cash.
II-177A
STATEMENTS OF CASH FLOWS
Gulf Power Company
===========================================================================================================================
For the Years Ended December 31, 1987 1986 1985 1984
--------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Operating Activities:
Net income $ 48,242 $ 52,634 $ 51,775 $ 46,676
Adjustments to reconcile net income to net
cash provided by operating activities --
Depreciation and amortization 51,672 41,619 39,595 34,784
Deferred income taxes, net 2,377 45,213 18,467 3,877
Deferred investment tax credits, net 868 1,634 5,716 10,667
Allowance for equity funds used during construction (1,013) (7,809) (6,893) (2,877)
Non-cash proceeds from settlement of disputed contracts - - - -
Other, net 12,913 5,860 (2,535) 243
Changes in certain current assets and liabilities --
Receivables, net (8,849) (6,012) (5,401) 19,173
Inventories 23,691 (1,342) 1,870 2,053
Payables 10,173 449 1,756 601
Other 6,208 (113) (13,331) 11,169
--------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities 146,282 132,133 91,019 126,366
--------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (97,511) (90,160) (92,541) (156,443)
Other (692) (55,652) 7,693 2,086
--------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities (98,203) (145,812) (84,848) (154,357)
--------------------------------------------------------------------------------------------------------------------------
Financing Activities and Capital Contributions:
Proceeds:
Preferred stock - - - -
First mortgage bonds - 50,000 - -
Pollution control bonds 35,996 9,900 18,776 16,424
Capital contributions from parent company - - 6,000 15,000
Other long-term debt - 60,663 - -
Retirements:
Preferred stock (2,500) (750) (750) (1,500)
First mortgage bonds - (46,640) (2,860) (10,415)
Pollution control bonds (32,050) (50) (50) (50)
Other long-term debt (4,774) - - -
Notes payable, net - - - -
Payment of preferred stock dividends (6,025) (6,213) (6,291) (6,340)
Payment of common stock dividends (34,200) (33,100) (30,800) (27,200)
Miscellaneous (1,632) (6,064) (227) (680)
--------------------------------------------------------------------------------------------------------------------------
Net cash provided from (used for) financing activities (45,185) 27,746 (16,202) (14,761)
--------------------------------------------------------------------------------------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents 2,894 14,067 (10,031) (42,752)
Cash and Cash Equivalents at Beginning of Year 37,332 23,265 33,296 76,048
--------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 40,226 $ 37,332 $ 23,265 $ 33,296
==========================================================================================================================
( ) Denotes use of cash.
II-177B
BALANCE SHEETS
Gulf Power Company
============================================================================================================
At December 31, 1994 1993 1992
------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
ASSETS
Utility Plant:
Production-fossil $ 896,236 $ 863,223 $ 841,489
Transmission 155,967 154,304 148,824
Distribution 487,986 464,182 443,352
General 116,178 129,995 127,826
Construction work in progress 24,288 34,591 29,564
------------------------------------------------------------------------------------------------------------
Total utility plant 1,680,655 1,646,295 1,591,055
Accumulated provision for depreciation 622,911 610,542 578,851
------------------------------------------------------------------------------------------------------------
Total 1,057,744 1,035,753 1,012,204
Less property-related accumulated deferred income taxes - - 200,904
------------------------------------------------------------------------------------------------------------
Total 1,057,744 1,035,753 811,300
------------------------------------------------------------------------------------------------------------
Other Property and Investments:
Securities received from settlement of disputed contracts - - -
Miscellaneous 7,997 13,242 7,074
------------------------------------------------------------------------------------------------------------
Total 7,997 13,242 7,074
------------------------------------------------------------------------------------------------------------
Current Assets:
Cash and cash equivalents 902 5,576 1,204
Investment securities - - 22,322
Receivables, net 60,384 63,924 60,047
Fossil fuel stock, at average cost 35,686 20,652 29,492
Materials and supplies, at average cost 35,257 36,390 33,124
Current portion of deferred coal contract costs 2,521 12,535 3,071
Regulatory clauses under recovery 5,002 3,244 1,680
Prepayments 4,354 2,160 1,395
Vacation pay deferred 4,172 4,022 3,779
------------------------------------------------------------------------------------------------------------
Total 148,278 148,503 156,114
------------------------------------------------------------------------------------------------------------
Deferred Charges:
Deferred charges related to income taxes 30,433 31,334 -
Debt expense, being amortized 3,625 3,693 3,253
Premium on reacquired debt, being amortized 18,494 17,554 15,319
Deferred coal contract costs 38,169 52,884 63,723
Miscellaneous 10,802 4,846 5,916
------------------------------------------------------------------------------------------------------------
Total 101,523 110,311 88,211
------------------------------------------------------------------------------------------------------------
Total Assets $ 1,315,542 $1,307,809 $1,062,699
============================================================================================================
II-178
BALANCE SHEETS
Gulf Power Company
=======================================================================================================================
At December 31, 1991 1990 1989 1988
-----------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
ASSETS
Utility Plant:
Production-fossil $ 837,712 $ 817,490 $ 807,546 $ 796,052
Transmission 143,275 136,813 133,926 113,177
Distribution 419,228 400,016 375,521 343,421
General 125,330 123,059 119,779 115,273
Construction work in progress 13,684 16,868 10,166 29,572
-----------------------------------------------------------------------------------------------------------------------
Total utility plant 1,539,229 1,494,246 1,446,938 1,397,495
Accumulated provision for depreciation 535,408 501,739 464,944 425,520
-----------------------------------------------------------------------------------------------------------------------
Total 1,003,821 992,507 981,994 971,975
Less property-related accumulated deferred income taxes 197,138 192,749 186,084 178,657
-----------------------------------------------------------------------------------------------------------------------
Total 806,683 799,758 795,910 793,318
-----------------------------------------------------------------------------------------------------------------------
Other Property and Investments:
Securities received from settlement of disputed contracts 19,938 - - -
Miscellaneous 6,410 5,439 6,933 6,756
-----------------------------------------------------------------------------------------------------------------------
Total 26,348 5,439 6,933 6,756
-----------------------------------------------------------------------------------------------------------------------
Current Assets:
Cash and cash equivalents 26,049 14,210 31,791 14,242
Investment securities - - - -
Receivables, net 49,006 61,427 58,959 59,451
Fossil fuel stock, at average cost 52,106 50,469 37,526 55,286
Materials and supplies, at average cost 34,070 33,310 34,446 32,992
Current portion of deferred coal contract costs 4,626 6,212 5,534 6,194
Regulatory clauses under recovery - 7,008 4,503 1,218
Prepayments 1,410 2,168 2,490 3,577
Vacation pay deferred 3,776 3,631 3,425 3,340
-----------------------------------------------------------------------------------------------------------------------
Total 171,043 178,435 178,674 176,300
-----------------------------------------------------------------------------------------------------------------------
Deferred Charges:
Deferred charges related to income taxes - - - -
Debt expense, being amortized 3,232 2,954 3,117 3,281
Premium on reacquired debt, being amortized 8,855 6,256 6,574 6,892
Deferred coal contract costs 74,502 87,102 97,833 106,263
Miscellaneous 5,073 4,635 4,389 4,415
-----------------------------------------------------------------------------------------------------------------------
Total 91,662 100,947 111,913 120,851
-----------------------------------------------------------------------------------------------------------------------
Total Assets $ 1,095,736 $1,084,579 $1,093,430 $1,097,225
=======================================================================================================================
II-179A
BALANCE SHEETS
Gulf Power Company
=======================================================================================================================
At December 31, 1987 1986 1985 1984
-----------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
ASSETS
Utility Plant:
Production-fossil $ 801,600 $ 608,340 $ 599,613 $ 582,139
Transmission 106,352 99,507 98,683 96,686
Distribution 325,037 295,052 274,656 241,557
General 102,664 66,092 56,427 43,539
Construction work in progress 10,113 188,966 148,969 130,027
-----------------------------------------------------------------------------------------------------------------------
Total utility plant 1,345,766 1,257,957 1,178,348 1,093,948
Accumulated provision for depreciation 388,248 350,117 318,308 287,349
-----------------------------------------------------------------------------------------------------------------------
Total 957,518 907,840 860,040 806,599
Less property-related accumulated deferred income taxes 166,707 152,589 135,388 112,684
-----------------------------------------------------------------------------------------------------------------------
Total 790,811 755,251 724,652 693,915
-----------------------------------------------------------------------------------------------------------------------
Other Property and Investments:
Securities received from settlement of disputed contracts - - - -
Miscellaneous 2,932 2,619 601 2,216
-----------------------------------------------------------------------------------------------------------------------
Total 2,932 2,619 601 2,216
-----------------------------------------------------------------------------------------------------------------------
Current Assets:
Cash and cash equivalents 40,226 37,332 23,265 33,296
Investment securities - - - -
Receivables, net 68,435 59,586 53,574 48,173
Fossil fuel stock, at average cost 43,290 69,785 73,890 76,039
Materials and supplies, at average cost 28,828 26,024 20,577 20,298
Current portion of deferred coal contract costs 2,642 - - -
Regulatory clauses under recovery - - - -
Prepayments 677 788 633 474
Vacation pay deferred 3,200 3,000 2,775 2,517
-----------------------------------------------------------------------------------------------------------------------
Total 187,298 196,515 174,714 180,797
-----------------------------------------------------------------------------------------------------------------------
Deferred Charges:
Deferred charges related to income taxes - - - -
Debt expense, being amortized 3,203 2,736 2,768 2,636
Premium on reacquired debt, being amortized 7,210 - - -
Deferred coal contract costs 55,889 60,663 - -
Miscellaneous 3,839 11,080 18,900 13,360
-----------------------------------------------------------------------------------------------------------------------
Total 70,141 74,479 21,668 15,996
-----------------------------------------------------------------------------------------------------------------------
Total Assets $ 1,051,182 $1,028,864 $ 921,635 $ 892,924
=======================================================================================================================
II-179B
BALANCE SHEETS
Gulf Power Company
============================================================================================================
At December 31, 1994 1993 1992
------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock $ 38,060 $ 38,060 $ 38,060
Paid-in capital 218,380 218,282 218,271
Premium on preferred stock 81 81 88
Earnings retained in the business 168,951 157,773 146,771
------------------------------------------------------------------------------------------------------------
Total common equity 425,472 414,196 403,190
Preferred stock 89,602 89,602 74,662
Preferred stock subject to mandatory redemption - 1,000 2,000
Long-term debt 356,393 369,259 382,047
------------------------------------------------------------------------------------------------------------
Total (excluding amount due within one year) 871,467 874,057 861,899
------------------------------------------------------------------------------------------------------------
Current Liabilities:
Notes payable to banks 53,500 6,053 44,000
Preferred stock due within one year 1,000 1,000 1,000
Long-term debt due within one year 13,439 41,552 13,820
Accounts payable 23,656 38,699 33,461
Customer deposits 13,609 15,082 15,532
Taxes accrued 13,465 13,015 11,419
Interest accrued 6,106 5,420 6,370
Regulatory clauses over recovery 3,960 840 -
Vacation pay accrued 4,172 4,022 3,779
Miscellaneous 7,828 8,527 3,950
------------------------------------------------------------------------------------------------------------
Total 140,735 134,210 133,331
------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 151,681 151,743 -
Deferred credits related to income taxes 71,964 76,876 -
Accumulated deferred investment tax credits 38,391 40,770 43,117
Miscellaneous 41,304 30,153 24,352
------------------------------------------------------------------------------------------------------------
Total 303,340 299,542 67,469
------------------------------------------------------------------------------------------------------------
Total Capitalization and Liabilities $ 1,315,542 $1,307,809 $1,062,699
============================================================================================================
II-180
BALANCE SHEETS
Gulf Power Company
========================================================================================================================
At December 31, 1991 1990 1989 1988
------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock $ 38,060 $ 38,060 $ 38,060 $ 38,060
Paid-in capital 218,150 218,150 214,150 207,150
Premium on preferred stock 399 399 399 399
Earnings retained in the business 134,372 114,576 112,862 112,701
------------------------------------------------------------------------------------------------------------------------
Total common equity 390,981 371,185 365,471 358,310
Preferred stock 55,162 55,162 55,162 55,162
Preferred stock subject to mandatory redemption 7,500 9,250 11,000 12,750
Long-term debt 434,648 475,284 484,608 497,069
------------------------------------------------------------------------------------------------------------------------
Total (excluding amount due within one year) 888,291 910,881 916,241 923,291
------------------------------------------------------------------------------------------------------------------------
Current Liabilities:
Notes payable to banks - - - -
Preferred stock due within one year 1,000 1,750 1,750 1,250
Long-term debt due within one year 59,111 9,452 12,588 15,005
Accounts payable 25,315 27,447 34,764 29,595
Customer deposits 15,513 15,551 15,752 15,316
Taxes accrued 19,274 19,610 12,388 10,683
Interest accrued 9,720 10,820 10,105 10,247
Regulatory clauses over recovery 1,114 - - -
Vacation pay accrued 3,776 3,631 3,425 3,340
Miscellaneous 3,545 12,177 7,759 2,748
------------------------------------------------------------------------------------------------------------------------
Total 138,368 100,438 98,531 88,184
------------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 1,775 6,736 13,381 17,678
Deferred credits related to income taxes - - - -
Accumulated deferred investment tax credits 45,446 47,776 50,109 52,451
Miscellaneous 21,856 18,748 15,168 15,621
------------------------------------------------------------------------------------------------------------------------
Total 69,077 73,260 78,658 85,750
------------------------------------------------------------------------------------------------------------------------
Total Capitalization and Liabilities $ 1,095,736 $1,084,579 $1,093,430 $1,097,225
========================================================================================================================
II-181A
BALANCE SHEETS
Gulf Power Company
========================================================================================================================
At December 31, 1987 1986 1985 1984
------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock $ 38,060 $ 38,060 $ 38,060 $ 38,060
Paid-in capital 182,150 182,150 182,150 176,150
Premium on preferred stock 399 399 399 399
Earnings retained in the business 102,403 94,386 81,065 66,381
------------------------------------------------------------------------------------------------------------------------
Total common equity 323,012 314,995 301,674 280,990
Preferred stock 55,162 55,162 55,162 55,162
Preferred stock subject to mandatory redemption 14,000 16,500 18,250 19,000
Long-term debt 474,640 482,869 410,917 394,859
------------------------------------------------------------------------------------------------------------------------
Total (excluding amount due within one year) 866,814 869,526 786,003 750,011
------------------------------------------------------------------------------------------------------------------------
Current Liabilities:
Notes payable to banks - - - -
Preferred stock due within one year 1,750 1,750 750 750
Long-term debt due within one year 13,225 4,823 2,910 2,910
Accounts payable 34,500 24,014 23,565 21,809
Customer deposits 15,565 14,715 13,753 12,624
Taxes accrued 7,850 10,986 13,240 22,038
Interest accrued 9,584 11,024 11,783 11,707
Regulatory clauses over recovery 9,330 - - -
Vacation pay accrued 3,200 3,000 2,775 2,517
Miscellaneous 2,144 3,869 4,966 4,474
------------------------------------------------------------------------------------------------------------------------
Total 97,148 74,181 73,742 78,829
------------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 22,992 23,550 - -
Deferred credits related to income taxes - - - -
Accumulated deferred investment tax credits 54,597 55,843 55,846 53,242
Miscellaneous 9,631 5,764 6,044 10,842
------------------------------------------------------------------------------------------------------------------------
Total 87,220 85,157 61,890 64,084
------------------------------------------------------------------------------------------------------------------------
Total Capitalization and Liabilities $ 1,051,182 $1,028,864 $ 921,635 $ 892,924
========================================================================================================================
II-181B
GULF POWER COMPANY
OUTSTANDING SECURITIES AT DECEMBER 31, 1994
First Mortgage Bonds
Amount Interest Amount
Series Issued Rate Outstanding Maturity
----------------------------------------------------------------
(Thousands) (Thousands)
1992 $ 25,000 5-7/8% $ 25,000 8/1/97
1993 15,000 5.55% 15,000 4/1/98
1993 30,000 5% 30,000 7/1/98
1993 30,000 6-1/8% 30,000 7/1/03
1978 25,000 9% 2,680 9/1/08
1991 50,000 8-3/4% 50,000 12/1/21
--------- --------
$ 175,000 $152,680
========= ========
Pollution Control Bonds
Amount Interest Amount
Series Issued Rate Outstanding Maturity
----------------------------------------------------------------
(Thousands) (Thousands)
1976 $ 12,500 6% $ 12,200 10/1/06
1987 32,000 8-1/4% 32,000 6/1/17
1991 21,200 7-1/8% 21,200 4/1/21
1992 8,930 6-3/4% 8,930 3/1/22
1993 13,000 6.20% 13,000 4/1/23
1993 32,550 5.80% 32,550 6/1/23
1993 7,875 5.70% 7,875 11/1/23
1994 22,000 6.30% 22,000 9/1/24
1994 20,000 Variable 20,000 9/1/24
--------- --------
$ 170,055 $169,755
========= ========
Preferred Stock
Shares Dividend Amount
Series Outstanding Rate Outstanding
----------------------------------------------------------------
(Thousands)
1950 51,026 4.64% $ 5,102
1960 50,000 5.16% 5,000
1966 50,000 5.44% 5,000
1969 50,000 7.52% 5,000
1972 50,000 7.88% 5,000
1980 (1) 10,000 11.36% 1,000
1992 580,000 7% 14,500
1992 600,000 7.30% 15,000
1993 800,000 6.72% 20,000
1993 600,000 Adjustable 15,000
--------- --------
2,841,026 $ 90,602
========= ========
(1) The outstanding balance of $1 million was redeemed on February 1, 1995.
II-182
GULF POWER COMPANY
SECURITIES RETIRED DURING 1994
First Mortgage Bonds
Principal Interest
Series Amount Rate
-----------------------------------------------------
(Thousands)
1964 $12,000 4-5/8%
1966 15,000 6%
1978 2,370 9%
1988 19,486 9.20%
-------
$48,856
=======
Pollution Control Bonds
Principal Interest
Series Amount Rate
-----------------------------------------------------
(Thousands)
1976 $ 100 6%
1984 42,000 10-1/2%
-------
$42,100
=======
Preferred Stock
Principal Dividend
Series Amount Rate
-----------------------------------------------------
(Thousands)
1980 $ 1,000 11.36%
II-183
MISSISSIPPI POWER COMPANY
FINANCIAL SECTION
II-184
MANAGEMENT'S REPORT
Mississippi Power Company 1994 Annual Report
The management of Mississippi Power Company has prepared--and is responsible
for--the financial statements and related information included in this report.
These statements were prepared in accordance with generally accepted accounting
principles appropriate in the circumstances and necessarily include amounts that
are based on best estimates and judgments of management. Financial information
throughout this annual report is consistent with the financial statements.
The Company maintains a system of internal accounting controls to provide
reasonable assurance that assets are safeguarded and that books and records
reflect only authorized transactions of the Company. Limitations exist in any
system of internal controls, however, based upon a recognition that the cost of
the system should not exceed its benefits. The Company believes its system of
internal accounting control maintains an appropriate cost/benefit relationship.
The Company's system of internal accounting controls is evaluated on an
ongoing basis by the internal audit staff. The Company's independent public
accountants also consider certain elements of the internal control system in
order to determine their auditing procedures for the purpose of expressing an
opinion on the financial statements.
The audit committee of the board of directors, composed of four directors
who are not employees, provides a broad overview of management's financial
reporting and control functions. Periodically, this committee meets with
management, the internal auditors, and the independent public accountants to
ensure that these groups are fulfilling their obligations and to discuss
auditing, internal controls, and financial reporting matters. The internal
auditors and independent public accountants have access to the members of the
audit committee at any time.
Management believes that its policies and procedures provide reasonable
assurance that the Company's operations are conducted according to a high
standard of business ethics.
In management's opinion, the financial statements present fairly, in all
material respects, the financial position, results of operations, and cash flows
of Mississippi Power Company in conformity with generally accepted accounting
principles.
/s/ David M. Ratcliffe
David M. Ratcliffe
President and Chief Executive Officer
/s/ Michael W. Southern
Michael W. Southern
Vice President, Secretary, Treasurer and
Chief Financial Officer
II-185
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of Mississippi Power Company:
We have audited the accompanying balance sheets and statements of capitalization
of Mississippi Power Company (a Mississippi corporation and a wholly owned
subsidiary of The Southern Company) as of December 31, 1994 and 1993, 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, 1994. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements (pages II-194 through II-209)
referred to above present fairly, in all material respects, the financial
position of Mississippi Power Company as of December 31, 1994 and 1993, and the
results of its operations and its cash flows for the periods stated, in
conformity with generally accepted accounting principles.
As explained in Notes 2 and 8 to the financial statements, effective January
1, 1993, Mississippi Power changed its methods of accounting for postretirement
benefits other than pensions and for income taxes.
/S/ ARTHUR ANDERSEN LLP
Atlanta, Georgia
February 15, 1995
II-186
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Mississippi Power Company 1994 Annual Report
RESULTS OF OPERATIONS
Earnings
Mississippi Power Company's net income after dividends on preferred stock for
1994 totaled $49.2 million, an increase of $6.7 million over the prior year.
This improvement is attributable primarily to increased energy sales and rate
increases. A retail rate increase under the Company's Performance Evaluation
Plan (PEP) of $6.4 million annually became effective in July 1993. Under the
Environmental Compliance Overview Plan (ECO Plan), retail rates increased by
$7.6 million annually effective April 1994. Also, effective in April 1994 was a
$3.6 million wholesale rate increase.
A comparison of 1993 to 1992 reflects an increase in 1993 earnings of $5.6
million. As was the case in 1994, earnings in 1993 increased because of higher
energy sales and retail rate increases.
Revenues
The following table summarizes the factors impacting operating revenues for the
past three years:
================================================================
Increase (Decrease)
from Prior Year
-----------------------------------
1994 1993 1992
-----------------------------------
(in thousands)
Retail --
Change in
base rates $ 9,314* $ 5,079* $ 6,605
Sales growth 9,560 5,606 7,181
Weather 1,752 4,735 (3,915)
Fuel cost
recovery
and other 6,594 15,028 (2,743)
----------------------------------------------------------------
Total retail 27,220 30,448 7,128
----------------------------------------------------------------
Sales for resale --
Non-affiliates 4,611 3,298 1,387
Affiliates (5,981) 5,464 (7,989)
----------------------------------------------------------------
Total sales for
resale (1,370) 8,762 (6,602)
Other operating
revenues (1,571) 1,226 1,535
----------------------------------------------------------------
Total operating
revenues $ 24,279 $ 40,436 $ 2,061
================================================================
Percent change 5.1% 9.3% 0.5%
----------------------------------------------------------------
*Includes the effect of the retail rate increases approved under the ECO Plan.
Retail revenues of $395 million in 1994 increased 7.4 percent over the prior
year, compared with increases of 9.0 percent and 2.2 percent in 1993 and 1992,
respectively. The increase in retail revenues for 1994 was a result of growth in
energy sales and customers and retail rate increases. Changes in base rates
reflect rate changes made under PEP and the ECO Plan as approved by the
Mississippi Public Service Commission (MPSC).
Under the fuel cost recovery provision, recorded fuel revenues are equal to
recorded fuel expenses, including the fuel component and the operation and
maintenance component of purchased energy. Therefore, changes in recoverable
fuel expenses are offset with corresponding changes in fuel revenues and have no
effect on net income.
II-187
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 1994 Annual Report
Included in sales for resale to non-affiliates are revenues from rural
electric cooperative associations and municipalities located in southeastern
Mississippi. Energy sales to these customers increased 7.8 percent in 1994 and
9.0 percent in 1993 with the related revenues rising 14.0 percent and 14.1
percent, respectively. The customer demand experienced by these utilities is
determined by factors very similar to Mississippi Power's.
Sales for resale to non-affiliated non-territorial utilities are primarily
under long-term contracts consisting of capacity and energy components. Capacity
revenues reflect the recovery of fixed costs and a return on investment under
the contracts. Energy is generally sold at variable cost. Under these long-term
contracts, the capacity and energy components were:
=============================================================
1994 1993 1992
----------------------------------------
(in thousands)
Capacity $ 1,965 $ 4,191 $ 3,573
Energy 8,473 12,120 19,538
-------------------------------------------------------------
Total $10,438 $16,311 $23,111
=============================================================
Capacity revenues for Mississippi Power varied due to changes in the
contracts and in the allocation of transmission capacity revenues throughout the
Southern electric system. Most of the Company's capacity revenues are derived
from transmission charges.
Sales to affiliated companies within the Southern electric system will vary
from year to year depending on demand and the availability and cost of
generating resources at each company. These sales have no material impact on
earnings.
Below is a breakdown of kilowatt-hour sales for 1994 and the percent change
for the last three years:
==================================================================
Amount Percent Change
(millions of -------- -----------------------------
kilowatt-hours 1994 1994 1993 1992
-------- -----------------------------
Residential 1,922 (0.4)% 6.9 % (1.5)%
Commercial 2,101 8.6 6.8 2.4
Industrial 3,847 6.2 2.5 7.3
Other 38 (0.5) 0.3 (57.2)
-----
Total retail 7,908 5.1 4.7 2.9
Sales for
resale --
Non-affiliates 2,556 0.4 (5.3) (0.7)
Affiliates 174 (59.2) 52.2 (54.6)
------
Total 10,638 1.3% 3.3% (1.5)%
==================================================================
Total retail energy sales in 1994 increased, compared to the previous year,
due primarily to the improvement in the economy. The most notable factor that
increased commercial energy sales was the recent establishment of casinos within
the Company's service area. It is expected that the establishment of new casinos
should slow appreciably. However, growth in ancillary services (lodging, food,
transportation, etc.) should continue. Also, energy demand is expected to grow
as a result of a larger and more fully employed population. The improvement in
the economy also carried over to the industrial sector. Retail energy sales in
1993 increased due to an improving economy and weather influences. Industrial
sales increased in 1992 as a result of new contracts with two large industrial
customers.
In addition to the previously discussed long-term contracts, energy sales to
non-affiliates include economy sales and amounts sold under short-term
contracts. Sales for resale to non-affiliates are influenced by those utilities'
own customer demand, plant availability, and the cost of their predominant fuels
-- oil and natural gas.
Expenses
Total operating expenses for 1994 were higher than the previous year because of
higher taxes and an increase in maintenance expenses and depreciation and
amortization. Additionally, included in other operation expenses are increased
costs associated with work force reduction programs. (See Note 2 to the
financial statements for information on these programs.) Expenses in 1993 were
higher than 1992 primarily because of higher production expenses stemming from
II-188
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 1994 Annual Report
increased demand, an increase in the federal income tax rate, and higher
employee related costs.
Fuel costs constitute the single largest expense for Mississippi Power.
These costs decreased in 1994 due to a 5.5 percent decrease in generation, which
reflects lower demand on the rest of the Southern electric system and, hence,
the availability of lower cost generation from affiliates. Fuel expenses in
1993, compared to 1992, were higher because of increased generation reflecting
higher demand.
Purchased power consists primarily of energy purchases from the affiliates
of the Southern electric system. Purchased power transactions (both sales and
purchases) among Mississippi Power and its affiliates will vary from period to
period depending on demand and the availability and variable production cost at
each generating unit in the Southern electric system.
The increase in depreciation and amortization is primarily the result of the
commercial operation of a 75 megawatt combustion turbine unit in May 1994.
Taxes other than income taxes increased in 1994 because of higher ad valorem
taxes, which are property based, and municipal franchise taxes, which are
revenue based.
The change in income taxes for 1994 reflected the change in operating
income. Income tax expense in 1993 increased because of the enactment of a
higher corporate income tax rate retroactive to January 1, 1993, coupled with
higher earnings.
Effects of Inflation
Mississippi Power is subject to rate regulation and income tax laws that are
based on the recovery of historical costs. Therefore, inflation creates an
economic loss because the Company is recovering its costs of investments in
dollars that have less purchasing power. While the inflation rate has been
relatively low in recent years, it continues to have an adverse effect on the
Company because of the large investment in long-lived utility plant.
Conventional accounting for historical costs does not recognize this economic
loss nor the partially offsetting gain that arises through financing facilities
with fixed-money obligations, such as long-term debt and preferred stock. Any
recognition of inflation by regulatory authorities is reflected in the rate of
return allowed.
Future Earnings Potential
The results of operations for the past three years are not necessarily
indicative of future earnings potential. The level of future earnings depends on
numerous factors ranging from regulatory matters to growth in energy sales to a
less regulated, more competitive environment. Expenses are subject to constant
review and cost control programs. Among the efforts to control costs are
utilizing employees more effectively through a functionalization program for the
Southern electric system, redesigning compensation and benefit packages, and
re-engineering work processes. Mississippi Power is also maximizing the utility
of invested capital and minimizing the need for capital by refinancing,
decreasing the average fuel stockpile, raising generating plant availability and
efficiency, and managing the construction budget. Operating revenues will be
affected by any changes in rates under the PEP, the Company's performance based
ratemaking plan. PEP has proven to be a stabilizing force on electric rates,
with only moderate changes in rates taking place.
The ECO Plan, approved by the MPSC in 1992, provides for recovery of costs
associated with environmental projects approved by the MPSC, most of which are
required to comply with Clean Air Act Amendments of 1990 (Clean Air Act)
regulations. The ECO Plan is operated independently of PEP. The Clean Air Act
and other important environmental items are discussed later under "Environmental
Matters."
The Federal Energy Regulatory Commission (FERC) regulates wholesale rate
schedules and power sales contracts that Mississippi Power has with its sales
for resale customers. The FERC is currently reviewing the rate of return on
common equity included in these schedules and contracts and may require such
returns to be lowered, possibly retroactively.
Further discussion of PEP, the ECO Plan, and proceedings before the FERC is
made in Note 3 to the financial statements herein.
II-189
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 1994 Annual Report
Future earnings in the near term will depend upon growth in energy sales,
which are subject to a number of factors. Traditionally, these factors have
included changes in contracts with neighboring utilities, energy conservation
practiced by customers, the elasticity of demand, weather, competition, and the
rate of economic growth in Mississippi Power's service area. However, the Energy
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 may enhance the incentive of IPPs to build cogeneration plants
for a utility's large industrial and commercial customers and sell excess
generation to other utilities. 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. 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 Mississippi Power 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.
Mississippi Power is subject to the provisions of Financial Accounting
Standards Board 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. See Note 1 to the financial statements under
"Regulatory Assets and Liabilities," for additional information.
FINANCIAL CONDITION
Overview
The principal changes in Mississippi Power's financial condition during 1994
were gross property additions to utility plant of $104 million, including the
commercial operation of a 75 megawatt capacity combustion turbine unit. Funding
for gross property additions and other capital requirements came primarily from
capital contributions from The Southern Company, the sale of first mortgage
bonds, the issuance of long-term notes payable, earnings and other operating
cash flows. The Statements of Cash Flows provide additional details.
Financing Activity
Mississippi Power continued to lower its financing costs in 1994 by issuing new
debt securities and retiring high-cost issues. The Company sold $35 million of
first mortgage bonds and issued $85 million in term notes. Retirements,
including maturities during 1994, totaled some $42 million of such securities.
(See the Statements of Cash Flows for further details.) Composite financing
rates for the years 1992 through 1994 as of year-end were as follows:
===========================================================
1994 1993 1992
---------------------------
Composite interest rate on
long-term debt 6.44% 6.57% 6.91%
Composite preferred stock
dividend rate 6.58% 6.58% 7.29%
===========================================================
Capital Structure
At year-end 1994, the Company's ratio of common equity to total capitalization
was 48.7 percent, compared to 49.8 percent in 1993 and 47.3 percent in 1992. The
lower equity ratio in 1994 can be attributed primarily to additional long-term
debt.
Capital Requirements for Construction
The Company's projected construction expenditures for the next three years total
$223 million ($78 million in 1995, $73 million in 1996, and $72 million in
1997). The major emphasis within the construction program will be on upgrading
existing facilities. Also included in the estimates for property additions for
II-190
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 1994 Annual Report
the three-year period is $2.9 million committed to meeting the requirements of
Clean Air Act regulations. Revisions may be necessary because of factors such as
revised load projections, the availability and cost of capital, and changes in
environmental regulations.
Other Capital Requirements
In addition to the funds required for the Company's construction program,
approximately $96 million will be required by the end of 1997 for present
sinking fund requirements and maturities of long-term debt. Mississippi Power
plans to continue, when economically feasible, to retire higher cost debt and
preferred stock and replace these obligations with lower-cost capital.
Environmental Matters
In November 1990, the Clean Air Act was signed into law. Title IV of the Clean
Air Act -- the acid rain compliance provision of the law -- will have a
significant impact on Mississippi Power and the other operating companies of The
Southern Company. Specific reductions in sulfur dioxide and nitrogen oxide
emissions from fossil-fired generating plants will be required in two phases.
Phase I compliance began in 1995 and affects eight generating plants -- some 10
thousand megawatts of capacity or 35 percent of total capacity -- in the
Southern electric system. Phase II compliance is required in 2000, and all
fossil-fired generating plants in the Southern electric system will be affected.
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 take advantage of allowances as a compliance option.
The Southern Company expects to achieve Phase I sulfur dioxide compliance at
the eight affected plants by switching to low-sulfur coal, which has required
some equipment upgrades. This compliance strategy is expected to result in
unused emission allowances being banked for later use. Additional construction
expenditures were required to install equipment for the control of nitrogen
oxide emissions at these eight plants. Also, continuous emissions monitoring
equipment will be installed on all fossil-fired units. Under this Phase I
compliance approach, additional construction expenditures are estimated to total
approximately $300 million through 1995 for The Southern Company, of which
Mississippi Power's portion is approximately $65 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 anticipated Phase II
limits. Therefore, during the period 1996 to 2000, current compliance strategy
for The Southern Company could require total construction expenditures of
approximately $150 million, of which Mississippi Power's portion is
approximately $5 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 2 percent in revenue requirements from
customers could be necessary to fully recover the Company's cost of compliance
for both Phase I and 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.
Mississippi Power's ECO Plan is designed to allow recovery of costs of
compliance with the Clean Air Act, as well as other environmental statutes and
regulations. The MPSC reviews environmental projects and the Company's
environmental policy through the ECO Plan. Under the ECO Plan, any increase in
II-191
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 1994 Annual Report
the annual revenue requirement is limited to 2 percent of retail revenues.
However, the plan also provides for carryover of any amount over the 2 percent
limit into the next year's revenue requirement. Mississippi Power's management
believes that the ECO Plan provides for recovery of the Clean Air Act costs.
Title III of the Clean Air Act requires a multi-year EPA study of power
plant emissions of hazardous air pollutants. The EPA is scheduled to submit a
report to Congress on the results of this study by November 1995. The report
will include a decision on whether additional regulatory control of these
substances is warranted. Compliance with any new control standard could result
in significant additional costs. The impact of new standards -- if any -- will
depend on the development and implementation of applicable regulations.
The EPA continues to evaluate the need for a new short-term ambient air
quality standard for sulfur dioxide. Preliminary results from an EPA study on
the impact of a new standard indicate that a number of plants could be required
to install sulfur dioxide controls. These controls would be in addition to the
controls already required to meet the acid rain provisions of the Clean Air Act.
The EPA issued proposed rules in November 1994 and is required to take final
action on this issue in 1996. The impact of any new standard will depend on the
level chosen for the standard and cannot be determined at this time.
In addition, the EPA is evaluating the need to revise the ambient air
quality standards for particulate matter, nitrogen oxides, and ozone. The impact
of any new standard will depend on the level chosen for the standard and cannot
be determined at this time.
In 1995, 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. Upon identifying potential sites, the Company conducts
studies, when possible, to determine the extent of any required cleanup costs.
Should remediation be determined to be probable, reasonable estimates of costs
to clean up such sites are developed and recognized in the financial statements.
A currently owned site where manufactured gas plant operations were located
prior to the Company's ownership is under investigation for potential
remediation, but no prediction can presently be made regarding the extent, if
any, of contamination or possible cleanup. Results of this investigation are
expected to be available in early 1995. If this site were required to be
remediated, industry studies show the Company could incur cleanup costs ranging
from $1.5 million to $10 million before giving consideration to possible
recovery of clean-up costs from other parties. Accordingly, no accrual has been
made for remediation in the accompanying financial statements.
Several major pieces of environmental legislation are in the process of
being reauthorized or amended by Congress. These include: the Clean Water Act;
the Resource Conservation and Recovery Act; the Comprehensive Environmental
Response, Compensation, and Liability 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 new legislation related to global climate change,
electromagnetic fields, and other environmental and health concerns could
significantly affect the Company. The impact of new legislation -- if any --
will depend on the subsequent development and implementation of applicable
regulations. In addition, the potential for lawsuits alleging damages caused by
electromagnetic fields exists.
II-192
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 1994 Annual Report
Sources of Capital
At December 31, 1994, the Company had $70 million of committed credit in
revolving credit agreements and also had $27 million of committed short-term
credit lines. The Company had no short-term notes payable outstanding at year
end 1994.
It is anticipated that the funds required for construction and other
purposes, including compliance with environmental regulations, will be derived
from operations, the sale of additional first mortgage bonds, pollution control
obligations, and preferred stock, and the receipt of additional capital
contributions from The Southern Company. Mississippi Power is required to meet
certain coverage requirements specified in its mortgage indenture and corporate
charter to issue new first mortgage bonds and preferred stock. The Company's
coverage ratios are sufficiently high enough to permit, at present interest rate
levels, any foreseeable security sales. The amount of securities which the
Company will be permitted to issue in the future will depend upon market
conditions and other factors prevailing at that time.
II-193
STATEMENTS OF INCOME
For the Years Ended December 31, 1994, 1993, and 1992
Mississippi Power Company 1994 Annual Report
==========================================================================================
1994 1993 1992
------------------------------------------------------------------------------------------
(in thousands)
Operating Revenues (Notes 1 and 3):
Revenues $ 489,624 $ 459,364 $ 424,392
Revenues from affiliates 9,538 15,519 10,055
------------------------------------------------------------------------------------------
Total operating revenues 499,162 474,883 434,447
------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
Fuel 102,216 113,986 96,743
Purchased power from non-affiliates 2,711 2,198 1,337
Purchased power from affiliates 68,543 58,019 60,689
Other 97,988 100,381 90,392
Maintenance 45,785 44,001 43,165
Depreciation and amortization 35,716 33,099 32,789
Taxes other than income taxes 41,742 37,145 34,664
Federal and state income taxes (Note 8) 31,386 22,668 16,378
------------------------------------------------------------------------------------------
Total operating expenses 426,087 411,497 376,157
------------------------------------------------------------------------------------------
Operating Income 73,075 63,386 58,290
Other Income (Expense):
Allowance for equity funds used during construction 1,099 1,010 642
Interest income 87 517 766
Other, net 2,033 3,971 5,501
Income taxes applicable to other income (227) (1,158) (1,427)
------------------------------------------------------------------------------------------
Income Before Interest Charges 76,067 67,726 63,772
------------------------------------------------------------------------------------------
Interest Charges:
Interest on long-term debt 19,725 17,688 22,357
Allowance for debt funds used during construction (1,039) (788) (563)
Interest on notes payable 1,442 1,000 362
Amortization of debt discount, premium, and expense 1,479 1,262 630
Other interest charges 404 728 339
------------------------------------------------------------------------------------------
Net interest charges 22,011 19,890 23,125
------------------------------------------------------------------------------------------
Net Income 54,056 47,836 40,647
Dividends on Preferred Stock 4,899 5,400 3,857
------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred Stock $ 49,157 $ 42,436 $ 36,790
==========================================================================================
The accompanying notes are an integral part of these statements.
II-194
STATEMENTS OF CASH FLOWS
For the Years ended December 31, 1994, 1993, and 1992
Mississippi Power Company 1994 Annual Report
==========================================================================================
1994 1993 1992
------------------------------------------------------------------------------------------
(in thousands)
Operating Activities:
Net income $ 54,056 $ 47,836 $ 40,647
Adjustments to reconcile net income to net
cash provided by operating activities --
Depreciation and amortization 47,827 45,660 41,472
Deferred income taxes 1,563 5,039 (5,473)
Allowance for equity funds used during construction (1,099) (1,010) (642)
Other, net 5,230 3,005 7,904
Changes in certain current assets and liabilities --
Receivables, net 3,066 (4,347) 1,002
Inventories (9,856) 11,119 975
Payables (8,754) 4,133 460
Other 3,334 (8,033) 6,095
------------------------------------------------------------------------------------------
Net cash provided from operating activities 95,367 103,402 92,440
------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (104,014) (139,976) (68,189)
Other (14,087) 7,562 4,235
------------------------------------------------------------------------------------------
Net cash used for investing activities (118,101) (132,414) (63,954)
------------------------------------------------------------------------------------------
Financing Activities:
Proceeds:
Capital contributions 25,000 30,036 26
Preferred stock - 23,404 35,000
First mortgage bonds 35,000 70,000 40,000
Pollution control bonds - 38,875 23,300
Other long-term debt 85,310 - -
Retirements:
Preferred stock - (23,404) -
First mortgage bonds (32,628) (51,300) (104,703)
Pollution control bonds (10) (25,885) (23,650)
Other long-term debt (9,299) (8,170) (6,212)
Notes payable, net (40,000) 9,000 26,500
Payment of preferred stock dividends (4,899) (5,400) (3,857)
Payment of common stock dividends (34,100) (29,000) (28,000)
Miscellaneous (1,201) (5,683) (7,821)
------------------------------------------------------------------------------------------
Net cash provided from (used for) financing activities 23,173 22,473 (49,417)
------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents 439 (6,539) (20,931)
Cash and Cash Equivalents at Beginning of Year 878 7,417 28,348
------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 1,317 $ 878 $ 7,417
==========================================================================================
Supplemental Cash Flow Information:
Cash paid during the year for --
Interest (net of amount capitalized) $19,196 $15,697 $22,941
Income taxes 31,115 29,009 19,514
------------------------------------------------------------------------------------------
( ) Denotes use of cash.
The accompanying notes are an integral part of these statements.
II-195
BALANCE SHEETS
At December 31, 1994 and 1993
Mississippi Power Company 1994 Annual Report
============================================================================================
ASSETS 1994 1993
--------------------------------------------------------------------------------------------
(in thousands)
Utility Plant:
Plant in service, at original cost (Notes 1 and 6) $ 1,385,032 $ 1,238,847
Less accumulated provision for depreciation 477,098 462,725
--------------------------------------------------------------------------------------------
907,934 776,122
Construction work in progress 44,838 108,063
--------------------------------------------------------------------------------------------
Total 952,772 884,185
--------------------------------------------------------------------------------------------
Other Property and Investments 3,353 11,289
--------------------------------------------------------------------------------------------
Current Assets:
Cash and cash equivalents 1,317 878
Receivables-
Customer accounts receivable 27,865 31,376
Other accounts and notes receivable 6,599 5,581
Affiliated companies 6,058 6,698
Accumulated provision for uncollectible accounts (670) (737)
Fossil fuel stock, at average cost 16,885 11,185
Materials and supplies, at average cost 25,301 21,145
Current portion of deferred fuel charges (Note 5) 1,068 440
Current portion of accumulated deferred income taxes (Note 8) 5,410 4,316
Prepaid federal income taxes 5,019 3,648
Prepayments 760 1,007
Vacation pay deferred (Note 1) 4,588 4,797
--------------------------------------------------------------------------------------------
Total 100,200 90,334
--------------------------------------------------------------------------------------------
Deferred Charges:
Debt expense and loss, being amortized 10,929 11,666
Deferred fuel charges (Note 5) 9,000 17,520
Deferred charges related to income taxes (Note 8) 25,036 25,267
Deferred early retirement program costs (Note 2) 11,286 -
Miscellaneous 11,135 10,073
--------------------------------------------------------------------------------------------
Total 67,386 64,526
--------------------------------------------------------------------------------------------
Total Assets $ 1,123,711 $ 1,050,334
============================================================================================
The accompanying notes are an integral part of these statements.
II-196
BALANCE SHEETS
At December 31, 1994 and 1993
Mississippi Power Company 1994 Annual Report
============================================================================================
CAPITALIZATION AND LIABILITIES 1994 1993
--------------------------------------------------------------------------------------------
(in thousands)
Capitalization (See accompanying statements):
Common stock equity $ 361,753 $ 321,768
Preferred stock 74,414 74,414
Long-term debt 306,522 250,391
--------------------------------------------------------------------------------------------
Total 742,689 646,573
--------------------------------------------------------------------------------------------
Current Liabilities:
Long-term debt due within one year (Note 10) 41,199 19,345
Notes payable (Note 5) - 40,000
Accounts payable-
Affiliated companies 3,337 10,197
Other 31,144 50,731
Customer deposits 2,712 2,786
Taxes accrued-
Federal and state income (Note 8) 433 186
Other 31,224 26,952
Interest accrued 4,427 4,237
Miscellaneous 14,613 14,120
--------------------------------------------------------------------------------------------
Total 129,089 168,554
--------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes (Note 8) 129,505 124,334
Accumulated deferred investment tax credits 31,228 32,710
Deferred credits related to income taxes (Note 8) 45,832 48,228
Accumulated provision for property damage (Note 1) 10,905 10,538
Miscellaneous 34,463 19,397
--------------------------------------------------------------------------------------------
Total 251,933 235,207
--------------------------------------------------------------------------------------------
Commitments and Contingent Matters (Notes 2, 3, 4, and 5)
Total Capitalization and Liabilities $ 1,123,711 $ 1,050,334
============================================================================================
The accompanying notes are an integral part of these statements.
II-197
STATEMENTS OF CAPITALIZATION
At December 31, 1994 and 1993
Mississippi Power Company 1994 Annual Report
=========================================================================================================
1994 1993 1994 1993
---------------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
Common Stock Equity:
Common stock, without par value --
Authorized -- 1,130,000 shares
Outstanding -- 1,121,000 shares in
1994 and 1993 $ 37,691 $ 37,691
Paid-in capital 179,362 154,362
Premium on preferred stock 372 372
Retained earnings (Note 11) 144,328 129,343
---------------------------------------------------------------------------------------------------------
Total common stock equity 361,753 321,768 48.7 % 49.8 %
---------------------------------------------------------------------------------------------------------
Cumulative Preferred Stock:
$100 par value --
Authorized -- 1,244,139 shares
Outstanding -- 744,139 shares in 1994
and 1993
4.40% 4,000 4,000
4.60% 2,010 2,010
4.72% 5,000 5,000
6.32% 15,000 15,000
6.65% 8,404 8,404
7.00% 5,000 5,000
7.25% 35,000 35,000
--------------------------------------------------------------------------------------------------------
Total (annual dividend requirement -- $4,899,000) 74,414 74,414 10.0 11.5
--------------------------------------------------------------------------------------------------------
Long-Term Debt:
First mortgage bonds --
Maturity Interest Rates
-------- --------------
June 1, 1994 4 5/8% - 10,000
July 1, 1995 4 3/4% - 11,000
August 1, 1996 6% - 10,000
March 1, 1998 5 3/8% 35,000 35,000
2000 to 2003 6 5/8% to 7 5/8% 40,000 40,000
March 1, 2004 6.60% 35,000 -
May 1, 2021 9 1/4% 47,072 48,700
June 1, 2023 7.45% 35,000 35,000
--------------------------------------------------------------------------------------------------------
Total first mortgage bonds 192,072 189,700
Pollution control obligations (Note 9) 63,155 63,165
Other long-term debt (Note 9) 95,689 19,678
Unamortized debt premium (discount), net (3,195) (2,807)
--------------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
requirement--$22,606,000) 347,721 269,736
Less amount due within one year (Note 10) 41,199 19,345
--------------------------------------------------------------------------------------------------------
Long-term debt excluding amount due within one year 306,522 250,391 41.3 38.7
--------------------------------------------------------------------------------------------------------
Total Capitalization $ 742,689 $ 646,573 100.0% 100.0%
========================================================================================================
The accompanying notes are an integral part of these statements.
II-198
STATEMENTS OF RETAINED EARNINGS
For the Years Ended December 31, 1994, 1993, and 1992
Mississippi Power Company 1994 Annual Report
===========================================================================================
1994 1993 1992
------------------------------------------------------------------------------------------
(in thousands)
Balance at Beginning of Period $ 129,343 $ 118,429 $ 111,670
Net income after dividends on preferred stock 49,157 42,436 36,790
Cash dividends on common stock (34,100) (29,000) (28,000)
Preferred stock transactions and other, net (72) (2,522) (2,031)
-------------------------------------------------------------------------------------------
Balance at End of Period (Note 11) $ 144,328 $ 129,343 $ 118,429
===========================================================================================
STATEMENTS OF PAID-IN CAPITAL
For the Years Ended December 31, 1994, 1993, and 1992
===========================================================================================
1994 1993 1992
-------------------------------------------------------------------------------------------
(in thousands)
Balance at Beginning of Period $ 154,362 $ 124,326 $ 124,300
Contributions to capital by parent company 25,000 30,036 26
-------------------------------------------------------------------------------------------
Balance at End of Period $ 179,362 $ 154,362 $ 124,326
===========================================================================================
The accompanying notes are an integral part of these statements.
II-199
NOTES TO FINANCIAL STATEMENTS
Mississippi Power Company 1994 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
General
Mississippi Power Company is a wholly owned subsidiary of The Southern Company,
which is the parent company of five operating companies, Southern Company
Services (SCS), Southern Communications Services (Southern Communications),
Southern Electric International (Southern Electric), Southern Nuclear Operating
Company (Southern Nuclear), and The Southern Development and Investment Group
(SDIG). The operating companies (Alabama Power Company, Georgia Power Company,
Gulf Power Company, Mississippi Power Company, and Savannah Electric and Power
Company) provide electric service in four southeastern states. Contracts among
the companies--dealing with jointly owned generating facilities, interconnecting
transmission lines, and the exchange of electric power--are regulated by the
Federal Energy Regulatory Commission (FERC) or the Securities and Exchange
Commission. SCS provides, at cost, specialized services to The Southern Company
and to the subsidiary companies. Southern Communications, beginning in mid-1995,
will provide digital wireless communications services--over the 800-megahertz
frequency band--to The Southern Company's subsidiaries and also will market
these services to the public within the Southeast. Southern Electric designs,
builds, owns, and operates power production facilities and provides a broad
range of technical services to industrial companies and utilities in the United
States and a number of international markets. Southern Nuclear provides services
to The Southern Company's nuclear power plants. SDIG 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. Mississippi
Power is also subject to regulation by the FERC and the Mississippi Public
Service Commission (MPSC). The Company follows generally accepted accounting
principles and complies with the accounting policies and practices prescribed by
the respective commissions.
Certain prior years' data presented in the financial statements have been
reclassified to conform with current year presentation.
Regulatory Assets and Liabilities
Mississippi Power 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 as of December 31 relate to: (in thousands)
===============================================================
1994 1993
------------------------
Deferred income taxes $25,036 $25,267
Vacation pay 4,588 4,797
Work force reduction costs 11,286 -
Deferred fuel charges 10,068 17,960
Premium on reacquired debt 9,571 10,563
Property damage reserve (10,905) (10,538)
Deferred income tax credits (45,832) (48,228)
Other, net (3,383) (3,653)
---------------------------------------------------------------
Total $ 429 $(3,832)
===============================================================
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 the 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 to their fair value.
Revenues
Mississippi Power accrues revenues for service rendered but unbilled at the end
of each fiscal period. The Company's retail and wholesale rates include
provisions to adjust billings for fluctuations in fuel and the energy component
of purchased power. Retail rates also include provisions to adjust billings for
fluctuations in costs for ad valorem taxes and certain qualifying environmental
II-200
NOTES (continued)
Mississippi Power Company 1994 Annual Report
costs. Revenues are adjusted for differences between actual allowable amounts
and the amounts included in rates.
The Company has a diversified base of customers. No single customer or
industry comprised 10 percent or more of revenues. In 1994, uncollectible
accounts continued to average less than 1 percent of revenues.
Depreciation
Depreciation of the original cost of depreciable utility plant in service is
provided by using composite straight-line rates which approximated 3.2 percent
in 1994, 3.1 percent in 1993, and 3.3 percent in 1992. When property subject to
depreciation is retired or otherwise disposed of in the normal course of
business, its cost -- together with the cost of removal, less salvage -- is
charged to the accumulated provision for depreciation. Minor items of property
included in the original cost of the plant are retired when the related property
unit is retired.
Income Taxes
Mississippi Power provides deferred income taxes for all significant income tax
temporary differences. Investment tax credits utilized are deferred and
amortized to income over the average lives of the related property.
Effective January 1, 1993, Mississippi Power adopted FASB Statement No.
109, Accounting for Income Taxes. Statement No. 109 required, among other
things, conversion to the liability method of accounting for accumulated
deferred income taxes. See Note 8 to the financial statements for additional
information about Statement No. 109.
Allowance for Funds Used During Construction (AFUDC)
AFUDC represents the estimated debt and equity costs of capital funds that are
necessary to finance the construction of new facilities. While cash is not
realized currently from such allowance, it increases the revenue requirement
over the service life of the plant through a higher rate base and higher
depreciation expense. The composite rates used to capitalize the cost of funds
devoted to construction were 6.9 percent in 1994, 6.8 percent in 1993, and 8.2
percent in 1992. AFUDC (net of income taxes), as a percent of net income after
dividends on preferred stock, was 3.5 percent in 1994 and 1993 and 2.7 percent
in 1992.
Utility Plant
Utility plant is stated at original cost. This cost includes: materials; labor;
minor items of property; appropriate administrative and general costs;
payroll-related costs such as taxes, pensions, and other benefits; and the
estimated cost of funds used during construction. The cost of maintenance,
repairs, and replacement of minor items of property is charged to maintenance
expense except for the maintenance of coal cars and a portion of the railway
track maintenance, which are charged to fuel stock. The cost of replacements of
property (exclusive of minor items of property) is charged to utility plant.
Cash and Cash Equivalents
For purposes of the Statements of Cash Flows, temporary cash investments are
considered cash equivalents. Temporary cash investments are securities with
original maturities of 90 days or less.
Financial Instruments
In accordance with FASB Statement No. 107, Disclosure About Fair Value of
Financial Instruments, all financial instruments of the Company for which the
carrying amount does not approximate fair value, must be disclosed. At December
31, 1994, the fair value of long-term debt was $331 million and the carrying
amount was $348 million. At December 31, 1993, the fair value of long-term debt
was $278 million and the carrying amount was $270 million. 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 used
or installed.
II-201
NOTES (continued)
Mississippi Power Company 1994 Annual Report
Vacation Pay
Mississippi Power's employees earn their vacation in one year and take it in the
subsequent year. However, for ratemaking purposes, vacation pay is recognized as
an allowable expense only when paid. Consistent with this ratemaking treatment,
the Company accrues a current liability for earned vacation pay and records a
current asset representing the future recoverability of this cost. Such amounts
were $4.6 million and $4.8 million at December 31, 1994 and 1993, respectively.
In 1995, an estimated 78 percent of the 1994 deferred vacation cost will be
expensed, and the balance will be charged to construction and other accounts.
Provision for Property Damage
Mississippi Power is self-insured for the cost of storm, fire and other
uninsured casualty damage to its property, including transmission and
distribution facilities. As permitted by regulatory authorities, the Company
provided for such costs by charges to income of $1.1 million in 1994 and $1.5
million in 1993 and 1992. The cost of repairing damage resulting from such
events that individually exceed $50 thousand is charged to the accumulated
provision to the extent it is available. As of December 31, 1994, the
accumulated provision amounted to $10.9 million, the maximum allowed for 1994.
Effective January 1995, regulatory treatment by the MPSC allows a maximum
accumulated provision of $18 million.
2. RETIREMENT BENEFITS:
Pension Plan
Mississippi Power has a defined benefit, trusteed, non-contributory pension plan
that covers substantially all regular employees. Benefits are based on the
greater of amounts resulting from two different formulas: years of service and
final average pay or years of service and a flat-dollar benefit. The Company
uses the "entry age normal method with a frozen initial liability" actuarial
method for funding purposes, subject to limitations under federal income tax
regulations. Amounts funded to the pension trust are primarily invested in
equity and fixed-income securities. FASB Statement No. 87, Employers' Accounting
for Pensions, requires use of the "projected unit credit" actuarial method for
financial reporting purposes.
Postretirement Benefits
Mississippi Power also provides certain medical care and life insurance benefits
for retired employees. Substantially all employees may become eligible for these
benefits when they retire. Qualified trusts are funded to the extent required by
the Company's regulatory commissions. Amounts funded are primarily invested in
debt and equity securities.
Effective January 1, 1993, Mississippi Power adopted FASB Statement No.
106, Employers' Accounting for Postretirement Benefits Other Than Pensions, on a
prospective basis. Statement No. 106 requires that medical care and life
insurance benefits for retired employees be accounted for on an accrual basis
using a specified actuarial method, "benefit/years-of-service." The cost of
postretirement benefits is reflected in rates on a current basis.
Prior to 1993, Mississippi Power recognized these benefit costs on an
accrual basis using the "aggregate cost" actuarial method, which spreads the
expected cost of such benefits over the remaining periods of employees' service
as a level percentage of payroll costs. The total cost of such benefits
recognized by the Company was $3.6 million in 1992.
Funded Status and Cost of Benefits
Shown in the following tables are actuarial results and assumptions for
pension and postretirement medical and life insurance benefits as computed under
the requirements of FASB Statement Nos. 87 and 106, respectively. The funded
status of the plans at December 31 was as follows:
II-202
NOTES (continued)
Mississippi Power Company 1994 Annual Report
===============================================================
Pension
-------------------
1994 1993
-------------------
(in thousands)
Actuarial present value of
benefit obligation:
Vested benefits $80,603 $73,735
Non-vested benefits 2,966 3,245
--------------------------------------------------------------
Accumulated benefit obligation 83,569 76,980
Additional amounts related to
projected salary increases 27,292 24,434
---------------------------------------------------------------
Projected benefit obligation 110,861 101,414
Less:
Fair value of plan assets 145,598 154,224
Unrecognized net gain (37,485) (49,239)
Unrecognized prior service cost 3,109 3,590
Unrecognized transition asset (6,635) (7,188)
---------------------------------------------------------------
Prepaid asset (accrued liability)
recognized in the
Balance Sheets $(6,274) $ (27)
===============================================================
Postretirement Medical
------------------------
1994 1993
------------------------
(in thousands)
Actuarial present value of
benefit obligation:
Retirees and dependents $18,106 $10,408
Employees eligible to retire 774 3,752
Other employees 19,124 19,389
---------------------------------------------------------------
Accumulated benefit obligation 38,004 33,549
Less:
Fair value of plan assets 6,460 6,271
Unrecognized net loss (gain) 2,301 3,500
Unrecognized transition
obligation 15,319 16,540
---------------------------------------------------------------
Accrued liability recognized in
the Balance Sheets $13,924 $ 7,238
===============================================================
Postretirement Life
----------------------
1994 1993
----------------------
(in thousands)
Actuarial present value of
benefit obligation:
Retirees $4,727 $3,315
Other employees 3,727 4,596
-----------------------------------------------------------
Accumulated benefit obligation 8,454 7,911
Less:
Fair value of plan assets 148 84
Unrecognized net loss (gain) (550) (632)
Unrecognized transition
obligation 3,349 3,606
-----------------------------------------------------------
Accrued liability recognized in
the Balance Sheets $5,507 $4,853
===========================================================
The weighted average rates assumed in the above actuarial calculations were:
==========================================================
1994 1993 1992
----------------------------
Discount 8.0% 7.5% 8.0%
Annual salary increase 5.5 5.0 6.0
Long-term return on
plan assets 8.5 8.5 8.5
----------------------------------------------------------
An additional assumption used in measuring the accumulated postretirement
medical benefit obligation was a weighted average medical care cost trend rate
of 10.5 percent for 1994 decreasing gradually to 6.0 percent through the year
2000 and remaining at that level thereafter. An annual increase in the assumed
medical care cost trend rate of 1 percent would increase the accumulated medical
benefit obligation as of December 31, 1994, by $6.7 million and the aggregate of
the service and interest cost components of the net retiree medical cost by $1.1
million.
II-203
NOTES (continued)
Mississippi Power Company 1994 Annual Report
Components of the plans' net cost are shown below:
================================================================
Pension
------------------------------
1994 1993 1992
------------------------------
(in thousands)
Benefits earned during
the year $ 3,780 $ 3,792 $ 3,595
Interest cost on
projected benefit
obligation 7,503 7,296 6,886
Actual (return) loss on
plan assets 3,244 (20,017) (5,812)
Net amortization and
deferral (16,048) 8,741 (4,265)
----------------------------------------------------------------
Net pension cost (income) $(1,521) $ (188) $ 404
================================================================
Of the above net pension amounts recorded, $(1.1) million in 1994, $(170)
thousand in 1993, and $269 thousand in 1992, and were recorded in operating
expenses, and the remainder was recorded in construction and other accounts.
Postretirement Medical
---------------------------
1994 1993
---------------------------
(in thousands)
Benefits earned during the year $1,486 $1,149
Interest cost on accumulated
benefit obligation 2,666 2,187
Amortization of transition
obligation over 20 years 864 871
Actual (return) loss on
plan assets 127 (808)
Net amortization and deferral (562) 343
----------------------------------------------------------------
Net postretirement cost $4,581 $3,742
================================================================
Postretirement Life
---------------------
1994 1993
---------------------
(in thousands)
Benefits earned during the year $ 274 $ 299
Interest cost on accumulated
benefit obligation 585 624
Amortization of transition
obligation over 20 years 179 180
Actual (return) loss on
plan assets 5 (6)
Net amortization and deferral (13) -
---------------------------------------------------------------
Net postretirement cost $1,030 $1,097
===============================================================
Of the above net postretirement medical and life insurance costs recorded,
$4.4 million in 1994 and $3.9 million in 1993 was charged to operating expense
and the remainder was charged to construction and other accounts.
Work Force Reduction Programs
During 1994, Mississippi Power and SCS instituted work force reduction
programs. The costs of the SCS work force reduction program were apportioned
among the various entities that form the Southern electric system, with the
Company's portion amounting to $1.4 million. The Company instituted an early
retirement incentive program in April 1994 and deferred the related costs of
approximately $12.9 million. The Company received authority from the MPSC to
defer these costs, as well as its portion of the costs of the SCS program, and
to amortize over a period not to exceed 60 months, beginning no later than
January 1995. During 1994, the Company expensed $3.0 million of the cost of
these programs.
3. LITIGATION AND REGULATORY MATTERS:
Retail Rate Adjustment Plans
Mississippi Power's retail base rates are set under a Performance Evaluation
Plan (PEP). The current version, PEP-2 was approved by the MPSC in January 1994.
PEP-2 was designed with the MPSC objectives that the plan would reduce the
impact of rate changes on the customer and provide incentives for Mississippi
Power to keep customer prices low. PEP-2 includes a mechanism for sharing rate
adjustments based on the Company's ability to maintain low rates for customers
and on the Company's performance as measured by three indicators that emphasize
price and service to the customer. PEP-2 provides for semiannual evaluations of
Mississippi's performance-based return on investment. Any change in rates is
limited to 2 percent of retail revenues per evaluation period. PEP-2 will remain
in effect until the MPSC modifies or terminates the plan. During 1994, there was
no increase under PEP-2.
Environmental Compliance Overview Plan
The MPSC approved Mississippi Power's ECO Plan in 1992. The plan establishes
procedures to facilitate the MPSC's overview of the Company's environmental
strategy and provides for recovery of costs associated with environmental
projects approved by the MPSC. Under the ECO Plan any increase in the annual
revenue requirement is limited to 2 percent of retail revenues. However, the
plan also provides for carryover of any amount over the 2 percent limit into the
next year's revenue requirement. The ECO Plan has resulted in annual retail rate
increases, the latest being a $7.6 million increase effective April 1994. On
II-204
NOTES (continued)
Mississippi Power Company 1994 Annual Report
January 31, 1995, the Company filed the ECO Plan with the MPSC requesting an
annual retail rate increase of $3.7 million, which included $1.6 million of 1994
carryover.
Mississippi Power conducts studies, when possible, to determine the extent
of any required clean-up costs. Should remediation be determined to be probable,
reasonable estimates of costs to clean up such sites are developed and
recognized in the financial statements. See "Environmental Matters" in the
Management's Discussion and Analysis for information on a manufactured gas plant
site.
FERC Reviews Equity Returns
In May 1991, the FERC ordered that hearings be conducted concerning the
reasonableness of the Southern electric system's wholesale rate schedules and
contracts that have a return on equity of 13.75 percent or greater. The
contracts that could be affected by the hearings include substantially all of
the transmission, unit power, long-term power and other similar contracts,
including the Company's Transmission Facilities Agreement (TFA) discussed in
Note 5 under "Lease Agreements." Any changes 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 began in October 1994 and is scheduled to continue
until January 1996.
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 $0.6
million at December 31, 1994. Although the final outcome of this matter cannot
now be determined, in management's opinion, the final outcome will not result in
changes that would have a material adverse effect on the Company's financial
statements.
4. CONSTRUCTION PROGRAM:
Mississippi Power is engaged in continuous construction programs, the costs of
which are currently estimated to total some $78 million in 1995, $73 million in
1996, and $72 million in 1997. These estimates include AFUDC of $1.7 million in
1995, $2.2 million in 1996, and $1.5 million in 1997.
The construction program is subject to periodic review and revision, and
actual construction costs may vary from the above estimates because of numerous
factors. These factors include changes in business conditions; revised load
growth estimates; changes in environmental regulations; increasing costs of
labor, equipment and materials; and cost of capital. The Company does not have
any new 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 "Environmental Matters" in Management's Discussion and Analysis for
information on the impact of the Clean Air Act Amendments of 1990 and other
environmental matters.
5. FINANCING AND COMMITMENTS:
Financing
Mississippi Power's construction program is expected to be financed from
internal and other sources, such as the issuance of additional long-term debt
and preferred stock and the receipt of capital contributions from The Southern
Company.
The amounts of first mortgage bonds and preferred stock which can be issued
in the future will be contingent upon market conditions, adequate earnings
levels, regulatory authorizations and other factors. See "Sources of Capital" in
Management's Discussion and Analysis for information regarding the Company's
coverage requirements.
At December 31, 1994, Mississippi Power had unused committed credit
agreements with banks for $27 million. Additionally, Mississippi Power had $70
million of unused committed credit agreements in the form of revolving credit
II-205
NOTES (continued)
Mississippi Power Company 1994 Annual Report
agreements expiring at various dates during 1995 and in 1997. The agreements
expiring December 31, 1997, for $40 million allow short-term borrowings to be
converted into term loans, payable in 12 equal quarterly installments, with the
first installment due at the end of the first calendar quarter after the
applicable termination date or at an earlier date at the Company's option. In
connection with these credit arrangements, the Company agrees to pay commitment
fees based on the unused portions of the commitments or to maintain compensating
balances with the banks. The Company had no short-term borrowings outstanding at
year-end 1994.
Assets Subject to Lien
Mississippi Power's mortgage indenture dated as of September 1, 1941, as amended
and supplemented, which secures the first mortgage bonds issued by the Company,
constitutes a direct first lien on substantially all the Company's fixed
property and franchises.
Lease Agreements
In 1984, Mississippi Power and Gulf States Utilities Company (Gulf States)
entered into a forty-year transmission facilities agreement whereby Gulf States
began paying a use fee to the Company covering all expenses relative to
ownership and operation and maintenance of a 500 kV line, including amortization
of its original $57 million cost. For the three years ended 1994 use fees
collected under this agreement, net of related expenses, amounted to $3.9
million each year, and are included with other income, net, in the Statements of
Income. For other information see Note 3 under "FERC Reviews Equity Returns."
In 1989, Mississippi Power entered into a twenty-two
year lease agreement for the use of 495 aluminum railcars. In 1994, a second
lease agreement for the use of 250 additional aluminum railcars was also entered
into for twenty-two years. Both of these leases, totaling 745 railcars, were for
the transport of coal at Plant Daniel. Gulf Power, as joint owner of Plant
Daniel, is responsible for one half of the lease cost. The Company's share (50%)
of the leases is charged to fuel inventory and allocated to fuel expense as the
fuel is consumed. The lease cost charged to inventory was $1.2 million in each
of the past three years. For the year 1995, the Company's annual lease payment
will be $2.6 million, of which $1.2 million was charged to inventory in 1994.
Lease payments will be approximately $1.7 million per year for the years 1996
through 1999. Lease payments after 1999 total approximately $26.1 million. The
Company has the option to purchase the 745 railcars at the greater of the
termination value or the fair market value, or to renew the leases at the end of
the lease term.
Fuel Commitments
To supply a portion of the fuel requirements of its generating plants,
Mississippi Power has entered into various long-term commitments for the
procurement of fuel. In most cases, these contracts contain provisions for price
escalations, minimum production levels, and other financial commitments. Total
estimated obligations were approximately $393 million at December 31, 1994.
Additional commitments for fuel will be required in the future to supply the
Company's fuel needs.
In order to take advantage of lower cost coal supplies, agreements were
reached in 1986 to terminate two contracts for the supply of coal to Plant
Daniel, which is jointly owned by Mississippi Power and Gulf Power, an operating
affiliate. The Company's portion of this payment was about $60 million. In
accordance with the ratemaking treatment, the cost to terminate the contracts is
being amortized through 1995 to match costs with savings achieved. The remaining
unamortized amount of Mississippi Power's share of principal payments to the
suppliers totaled $10.1 million at December 31, 1994.
6. JOINT OWNERSHIP AGREEMENTS:
Mississippi Power and Alabama Power own as tenants in common Greene County
Electric Generating Plant (coal) located in Alabama; and Mississippi Power and
Gulf Power own as tenants in common Daniel Electric Generating Plant (coal)
located in Mississippi. At December 31, 1994, Mississippi Power's percentage
ownership and investment in these jointly owned facilities were as follows:
==========================================================================
Company's
Generating Total Percent Gross Accumulated
Plant Capacity Ownership Investment Depreciation
---------- --------- --------- ----------- -------------
(Megawatts) (in thousands)
Greene
County 500 40% $ 57,567 $29,742
Daniel 1,000 50% 219,870 90,908
--------------------------------------------------------------------------
II-206
NOTES (continued)
Mississippi Power Company 1994 Annual Report
Mississippi Power's share of plant operating expenses is included in the
corresponding operating expenses in the Statements of Income.
7. LONG-TERM POWER SALES AGREEMENTS:
General
Mississippi Power and the other operating affiliates of The Southern Company
have entered into long-term contractual agreements for the sale of capacity and
energy to certain non-affiliated utilities located outside of the system's
service area. The agreements for non-firm capacity expired in 1994. Some of
these agreements (unit power sales) are firm commitments and pertain to capacity
related to specific generating units. Mississippi Power's participation in firm
production capacity unit power sales ended in 1989. However, the Company
continues to participate in transmission and energy sales under the unit power
sales agreements. Because the energy is generally sold at variable costs under
these agreements, only revenues from capacity sales affect profitability.
Off-system capacity revenues for the Company have been as follows:
============================================================
Other
Year Unit Power Long-Term Total
------------------------------------------------------------
(in thousands)
1994 $ 660 $1,305 $1,965
1993 1,571 2,620 4,191
1992 2,168 1,405 3,573
------------------------------------------------------------
In 1994, long-term non-firm power of 200 megawatts was sold by the Southern
electric system to Florida Power Corporation until the contract expired at
year-end.
8. INCOME TAXES:
Effective January 1, 1993, Mississippi Power 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, 1994, the tax-related regulatory assets to be recovered from
customers were $25 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, 1994, the tax-related regulatory liabilities to be
refunded to customers were $46 million. These liabilities are attributable to
deferred taxes previously recognized at rates higher than current enacted tax
law and unamortized investment tax credits.
Details of the federal and state income tax provisions are shown below:
==================================================================
1994 1993 1992
------------------------------
(in thousands)
Total provision for
income taxes
Federal --
Currently payable $26,072 $15,842 $20,286
Deferred --current year 6,313 5,158 (1,578)
--reversal of
prior years (5,161) (820) (3,931)
------------------------------------------------------------------
27,224 20,180 14,777
------------------------------------------------------------------
State --
Currently payable 3,978 2,945 2,992
Deferred --current 1,669 1,339 218
--reversal of
prior years (1,258) (638) (182)
------------------------------------------------------------------
4,389 3,646 3,028
------------------------------------------------------------------
Total 31,613 23,826 17,805
Less income taxes charged
to other income 227 1,158 1,427
------------------------------------------------------------------
Federal and state
income taxes charged
to operations $31,386 $22,668 $16,378
==================================================================
The tax effects of temporary differences between the carrying amounts of
assets and liabilities in the financial statements and their respective tax
II-207
NOTES (continued)
Mississippi Power Company 1994 Annual Report
bases, which give rise to deferred tax assets and liabilities are as follows:
===============================================================
1994 1993
-------------------------
(in thousands)
Deferred tax liabilities:
Accelerated depreciation $138,281 $130,299
Basis differences 11,645 11,332
Coal contract buyouts 3,851 6,870
Other 17,908 18,719
---------------------------------------------------------------
Total 171,685 167,220
---------------------------------------------------------------
Deferred tax assets:
Other property
basis differences 27,375 28,779
Pension and
other benefits 5,386 4,625
Property insurance 4,171 4,031
Unbilled fuel 3,649 4,205
Other 7,009 5,562
--------------------------------------------------------------
Total 47,590 47,202
--------------------------------------------------------------
Net deferred tax
liabilities 124,095 120,018
Portion included in
current assets, net 5,410 4,316
--------------------------------------------------------------
Accumulated deferred
income taxes in the
Balance Sheets $129,505 $124,334
==============================================================
In 1989, under order of the MPSC, Mississippi Power began amortizing
deferred income taxes not covered by the Internal Revenue Service normalization
requirements, that had been recorded at rates higher than those specified by the
current statutory income tax rules. This amortization occurred over a 60-month
period, the effect of which was a reduction of income tax expense of
approximately $2.7 million per year. This tax rate differential has been fully
amortized.
Deferred investment tax credits are amortized over the life of the related
property with such amortization normally applied as a credit to reduce
depreciation in the Statements of Income. Credits amortized in this manner
amounted to $1.5 million in both 1994 and 1993 and $1.4 million in 1992. At
December 31, 1994, 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:
=============================================================
1994 1993 1992
----------------------------
Total effective tax rate 37% 33% 30%
State income tax, net of
federal income tax benefit (3)% (3) (3)
Tax rate differential 1 4 6
Other - 1 1
-------------------------------------------------------------
Statutory federal tax rate 35% 35% 34%
=============================================================
Mississippi Power and its affiliates file a consolidated federal income tax
return. Under a joint consolidated income tax agreement, each company's current
and deferred tax expense is computed on a stand-alone basis, and consolidated
tax savings are allocated to each company based on its ratio of taxable income
to total consolidated taxable income.
9. OTHER LONG-TERM DEBT:
Details of other long-term debt are as follows:
==============================================================
December 31,
1994 1993
-------------------
(in thousands)
Obligations incurred in
connection with the sale by
public authorities of
tax-exempt pollution control
revenue bonds:
5.80% due 2007 $ 980 $ 990
Variable rate due 2020 6,550 6,550
Variable rate due 2022 16,750 16,750
6.20% due 2023 13,000 13,000
5.65% due 2023 25,875 25,875
--------------------------------------------------------------
63,155 63,165
--------------------------------------------------------------
Notes payable:
8.25% due 1994-1995 - 17,520
7.50% due 1994-1995 1,689 2,158
5.39% to 5.72% due 1995 9,000 -
4.15% to 5.89% due 1995-1996 50,000 -
6.0375% due 1996 35,000 -
--------------------------------------------------------------
95,689 19,678
--------------------------------------------------------------
Total $158,844 $82,843
==============================================================
Pollution control obligations represent installment or lease purchases of
pollution control facilities financed by application of funds derived from sales
by public authorities of tax-exempt revenue bonds. Mississippi Power has
authenticated and delivered to the Trustee a like principal amount of first
II-208
NOTES (continued)
Mississippi Power Company 1994 Annual Report
mortgage bonds as security for obligations under collateralized installment
agreements. The principal and interest on the first mortgage bonds will be
payable only in the event of default under these agreements. The 5.8% Series of
pollution control obligations has a cash sinking fund requirement of $10
thousand annually through 1997 and $20 thousand annually in 1998 and 1999.
10. LONG-TERM DEBT DUE WITHIN ONE YEAR:
A summary of the improvement fund requirements and scheduled maturities and
redemptions of long-term debt due within one year is as follows:
===============================================================
1994 1993
-------------------
(in thousands)
Bond improvement
fund requirements $ 1,931 $ 1,902
Less:
Portion to be satisfied by
certifying property additions 1,431 1,402
---------------------------------------------------------------
Cash improvement fund
requirements 500 500
First mortgage bond maturities
and redemptions - 10,000
Pollution control bond cash
sinking fund requirements (Note 9) 10 10
Current portion of notes
payable (Note 9) 40,689 8,835
---------------------------------------------------------------
Total $41,199 $19,345
===============================================================
The first mortgage bond improvement fund requirement is one percent of each
outstanding series authenticated under the indenture of Mississippi Power prior
to January 1 of each year, other than first mortgage bonds issued as collateral
security for certain pollution control obligations. The requirement must be
satisfied by June 1 of each year by depositing cash or reacquiring bonds, or by
pledging additional property equal to 166-2/3 percent of such requirement.
11. COMMON STOCK DIVIDEND RESTRICTIONS:
Mississippi Power's first mortgage bond indenture and the corporate charter
contain various common stock dividend restrictions. At December 31, 1994, $94
million of retained earnings was restricted against the payment of cash
dividends on common stock under the most restrictive terms of the mortgage
indenture or corporate charter.
12. QUARTERLY FINANCIAL DATA (UNAUDITED):
Summarized quarterly financial data for 1994 and 1993 are as follows:
===================================================================
Net Income
After Dividends
Quarter Operating Operating On
Ended Revenues Income Preferred Stock
------- ------------------------------------------------
March 1994 $114,134 $12,910 $ 8,266
June 1994 131,792 19,891 13,744
September 1994 142,340 26,212 21,357
December 1994 110,896 14,062 5,790
March 1993 $101,552 $ 9,529 $ 4,424
June 1993 117,764 18,147 11,852
September 1993 148,102 22,377 16,560
December 1993 107,465 13,333 9,600
Mississippi Power's business is influenced by seasonal weather conditions
and the timing of rate changes.
II-209
SELECTED FINANCIAL AND OPERATING DATA
Mississippi Power Company 1994 Annual Report
================================================================================================
1994 1993 1992
------------------------------------------------------------------------------------------------
Operating Revenues (in thousands) $499,162 $474,883 $434,447
Net Income after Dividends
on Preferred Stock (in thousands) $49,157 $42,436 $36,790
Cash Dividends on Common Stock (in thousands) $34,100 $29,000 $28,000
Return on Average Common Equity (percent) 14.38 14.09 13.27
Total Assets (in thousands) $1,123,711 $1,050,334 $791,283
Gross Property Additions (in thousands) $104,014 $139,976 $68,189
------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $361,753 $321,768 $280,640
Preferred stock 74,414 74,414 74,414
Preferred stock subject to mandatory redemption - - -
Long-term debt 306,522 250,391 238,650
------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $742,689 $646,573 $593,704
================================================================================================
Capitalization Ratios (percent):
Common stock equity 48.7 49.8 47.3
Preferred stock 10.0 11.5 12.5
Long-term debt 41.3 38.7 40.2
------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0 100.0
================================================================================================
First Mortgage Bonds (in thousands):
Issued 35,000 70,000 40,000
Retired 32,628 51,300 104,703
Preferred Stock (in thousands):
Issued - 23,404 35,000
Retired - 23,404 -
------------------------------------------------------------------------------------------------
Security Ratings:
First Mortgage Bonds -
Moody's Aa3 A1 A1
Standard and Poor's A+ A+ A+
Duff & Phelps A+ A+ A+
Preferred Stock -
Moody's a1 a1 a1
Standard and Poor's A A A
Duff & Phelps A A A
------------------------------------------------------------------------------------------------
Customers (year-end):
Residential 152,891 151,692 150,248
Commercial 29,276 28,648 28,056
Industrial 650 570 573
Other 189 190 189
------------------------------------------------------------------------------------------------
Total 183,006 181,100 179,066
================================================================================================
Employees (year-end) 1,535 1,586 1,619
------------------------------------------------------------------------------------------------
II-210
SELECTED FINANCIAL AND OPERATING DATA (continued)
Mississippi Power Company 1994 Annual Report
================================================================================================
1991 1990 1989
------------------------------------------------------------------------------------------------
Operating Revenues (in thousands) $432,386 $446,871 $442,650
Net Income after Dividends
on Preferred Stock (in thousands) $22,627 $34,176 $38,576
Cash Dividends on Common Stock (in thousands) $28,500 $27,500 $27,000
Return on Average Common Equity (percent) 8.17 12.36 14.43
Total Assets (in thousands) $790,641 $800,026 $786,570
Gross Property Additions (in thousands) $53,675 $49,009 $43,916
------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $273,855 $279,833 $273,157
Preferred stock 39,414 39,414 39,414
Preferred stock subject to mandatory redemption - 3,750 4,500
Long-term debt 304,150 270,724 277,693
------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $617,419 $593,721 $594,764
================================================================================================
Capitalization Ratios (percent):
Common stock equity 44.4 47.1 45.9
Preferred stock 6.4 7.3 7.4
Long-term debt 49.2 45.6 46.7
------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0 100.0
================================================================================================
First Mortgage Bonds (in thousands):
Issued 50,000 - -
Retired - 4,000 3,823
Preferred Stock (in thousands):
Issued - - -
Retired 4,118 750 750
------------------------------------------------------------------------------------------------
Security Ratings:
First Mortgage Bonds -
Moody's A1 A1 A1
Standard and Poor's A+ A+ A+
Duff & Phelps A+ A+ A+
Preferred Stock -
Moody's a1 a1 a1
Standard and Poor's A A A
Duff & Phelps A A A
------------------------------------------------------------------------------------------------
Customers (year-end):
Residential 148,978 147,738 147,308
Commercial 27,441 27,134 26,867
Industrial 562 574 525
Other 400 411 404
------------------------------------------------------------------------------------------------
Total 177,381 175,857 175,104
================================================================================================
Employees (year-end) 1,630 1,842 1,750
------------------------------------------------------------------------------------------------
II-211A
SELECTED FINANCIAL AND OPERATING DATA (continued)
Mississippi Power Company 1994 Annual Report
================================================================================================
1988 1987 1986
------------------------------------------------------------------------------------------------
Operating Revenues (in thousands) $437,939 $455,843 $476,265
Net Income after Dividends
on Preferred Stock (in thousands) $36,081 $35,200 $33,814
Cash Dividends on Common Stock (in thousands) $27,600 $24,700 $23,700
Return on Average Common Equity (percent) 14.03 14.68 15.28
Total Assets (in thousands) $779,319 $764,068 $767,110
Gross Property Additions (in thousands) $54,550 $53,288 $62,488
------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $261,473 $252,992 $226,601
Preferred stock 39,414 39,414 39,414
Preferred stock subject to mandatory redemption 5,250 6,750 8,250
Long-term debt 287,525 294,811 299,684
------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $593,662 $593,967 $573,949
================================================================================================
Capitalization Ratios (percent):
Common stock equity 44.1 42.6 39.5
Preferred stock 7.5 7.8 8.3
Long-term debt 48.4 49.6 52.2
------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0 100.0
================================================================================================
First Mortgage Bonds (in thousands):
Issued - - 35,000
Retired - 29,701 29,250
Preferred Stock (in thousands):
Issued - - -
Retired 1,500 1,500 1,500
------------------------------------------------------------------------------------------------
Security Ratings:
First Mortgage Bonds -
Moody's A1 A1 A1
Standard and Poor's A+ A+ A+
Duff & Phelps 5 5 5
------------------------------------------------------------------------------------------------
Preferred Stock -
Moody's a1 a1 a1
Standard and Poor's A A A
Duff & Phelps 6 6 6
------------------------------------------------------------------------------------------------
Customers (year-end):
Residential 146,750 146,273 145,809
Commercial 26,751 26,342 26,217
Industrial 478 438 393
Other 399 389 363
------------------------------------------------------------------------------------------------
Total 174,378 173,442 172,782
================================================================================================
Employees (year-end) 1,831 1,898 1,882
------------------------------------------------------------------------------------------------
II-211B
SELECTED FINANCIAL AND OPERATING DATA (continued)
Mississippi Power Company 1994 Annual Report
====================================================================================
1985 1984
------------------------------------------------------------------------------------
Operating Revenues (in thousands) $475,610 $442,507
Net Income after Dividends
on Preferred Stock (in thousands) $33,330 $31,380
Cash Dividends on Common Stock (in thousands) $22,600 $21,000
Return on Average Common Equity (percent) 15.83 15.74
Total Assets (in thousands) $679,577 $660,530
Gross Property Additions (in thousands) $57,791 $37,290
------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $216,087 $205,018
Preferred stock 39,414 39,414
Preferred stock subject to mandatory redemption 9,750 10,500
Long-term debt 261,594 267,051
------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $526,845 $521,983
====================================================================================
Capitalization Ratios (percent):
Common stock equity 41.0 39.3
Preferred stock 9.3 9.5
Long-term debt 49.7 51.2
------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0
====================================================================================
First Mortgage Bonds (in thousands):
Issued - -
Retired 250 250
Preferred Stock (in thousands):
Issued - -
Retired 1,111 639
------------------------------------------------------------------------------------
Security Ratings:
First Mortgage Bonds -
Moody's A1 A1
Standard and Poor's A A
Duff & Phelps 5 5
Preferred Stock -
Moody's a1 a1
Standard and Poor's A A
Duff & Phelps 6 6
------------------------------------------------------------------------------------
Customers (year-end):
Residential 145,071 142,846
Commercial 25,629 25,404
Industrial 371 348
Other 356 356
------------------------------------------------------------------------------------
Total 171,427 168,954
====================================================================================
Employees (year-end) 1,801 1,669
------------------------------------------------------------------------------------
II-211C
SELECTED FINANCIAL AND OPERATING DATA (continued)
Mississippi Power Company 1994 Annual Report
================================================================================================
1994 1993 1992
------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $124,257 $118,793 $109,781
Commercial 124,716 115,152 107,131
Industrial 142,268 130,198 117,010
Other 3,882 3,760 3,533
------------------------------------------------------------------------------------------------
Total retail 395,123 367,903 337,455
Sales for resale - non-affiliates 88,122 83,511 80,213
Sales for resale - affiliates 9,538 15,519 10,055
------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 492,783 466,933 427,723
Other revenues 6,379 7,950 6,724
------------------------------------------------------------------------------------------------
Total $499,162 $474,883 $434,447
================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 1,922,217 1,929,835 1,804,858
Commercial 2,100,625 1,933,685 1,811,042
Industrial 3,847,011 3,623,543 3,536,634
Other 38,147 38,357 38,261
------------------------------------------------------------------------------------------------
Total retail 7,908,000 7,525,420 7,190,795
Sales for resale - non-affiliates 2,555,914 2,544,982 2,687,917
Sales for resale - affiliates 174,342 426,919 280,443
------------------------------------------------------------------------------------------------
Total 10,638,256 10,497,321 10,159,155
================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 6.46 6.16 6.08
Commercial 5.94 5.96 5.92
Industrial 3.70 3.59 3.31
Total retail 5.00 4.89 4.69
Total sales 4.63 4.45 4.21
Residential Average Annual Kilowatt-Hour Use Per Customer 12,611 12,780 12,066
Residential Average Annual Revenue Per Customer $815.21 $786.71 $733.90
Plant Nameplate Capacity Ratings (year-end) (megawatts) 2,086 2,011 2,011
Maximum Peak-Hour Demand (megawatts):
Winter 1,636 1,401 1,386
Summer 1,874 1,872 1,755
Annual Load Factor (percent) 63.4 60.0 60.8
Plant Availability - Fossil-Steam (percent) 85.4 88.0 92.0
------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 56.0 63.5 60.4
Oil and gas 10.2 7.6 5.8
Purchased power -
From non-affiliates 1.2 1.3 1.2
From affiliates 32.6 27.6 32.6
------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0
================================================================================================
Total Fuel Economy Data:
BTU per net kilowatt-hour generated 10,295 10,075 9,888
Cost of fuel per million BTU (cents) 165.96 170.13 162.27
Average cost of fuel per net kilowatt-hour generated (cents) 1.71 1.71 1.60
------------------------------------------------------------------------------------------------
II-212
SELECTED FINANCIAL AND OPERATING DATA (continued)
Mississippi Power Company 1994 Annual Report
================================================================================================
1991 1990 1989
------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $103,820 $102,243 $100,068
Commercial 103,666 103,352 103,403
Industrial 116,972 123,754 128,983
Other 5,869 6,078 5,992
------------------------------------------------------------------------------------------------
Total retail 330,327 335,427 338,446
Sales for resale - non-affiliates 78,826 86,194 82,111
Sales for resale - affiliates 18,044 20,157 16,938
------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 427,197 441,778 437,495
Other revenues 5,189 5,093 5,155
------------------------------------------------------------------------------------------------
Total $432,386 $446,871 $442,650
================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 1,832,266 1,804,838 1,741,855
Commercial 1,768,441 1,718,074 1,686,302
Industrial 3,297,247 3,311,460 3,204,208
Other 89,375 85,938 87,611
------------------------------------------------------------------------------------------------
Total retail 6,987,329 6,920,310 6,719,976
Sales for resale - non-affiliates 2,706,320 2,883,581 2,798,086
Sales for resale - affiliates 617,696 714,365 527,970
------------------------------------------------------------------------------------------------
Total 10,311,345 10,518,256 10,046,032
================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 5.67 5.66 5.74
Commercial 5.86 6.02 6.13
Industrial 3.55 3.74 4.03
Total retail 4.73 4.85 5.04
Total sales 4.14 4.20 4.35
Residential Average Annual Kilowatt-Hour Use Per Customer 12,338 12,228 11,842
Residential Average Annual Revenue Per Customer $699.11 $692.70 $680.32
Plant Nameplate Capacity Ratings (year-end) (megawatts) 2,011 1,998 1,998
Maximum Peak-Hour Demand (megawatts):
Winter 1,267 1,201 1,556
Summer 1,682 1,724 1,682
Annual Load Factor (percent) 61.5 59.0 58.8
Plant Availability - Fossil-Steam (percent) 89.8 93.3 94.0
------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 64.1 62.6 63.4
Oil and gas 8.1 14.0 13.5
Purchased power -
From non-affiliates 0.7 0.8 0.5
From affiliates 27.1 22.6 22.6
------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0
================================================================================================
Total Fuel Economy Data:
BTU per net kilowatt-hour generated 10,142 10,319 10,159
Cost of fuel per million BTU (cents) 177.52 183.27 178.38
Average cost of fuel per net kilowatt-hour generated (cents) 1.80 1.89 1.81
------------------------------------------------------------------------------------------------
II-213A
SELECTED FINANCIAL AND OPERATING DATA (continued)
Mississippi Power Company 1994 Annual Report
================================================================================================
1988 1987 1986
------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $96,711 $98,338 $101,984
Commercial 98,772 98,669 100,521
Industrial 123,038 129,004 134,501
Other 5,874 5,723 5,882
------------------------------------------------------------------------------------------------
Total retail 324,395 331,734 342,888
Sales for resale - non-affiliates 75,525 88,060 107,270
Sales for resale - affiliates 33,747 31,278 21,669
------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 433,667 451,072 471,827
Other revenues 4,272 4,771 4,438
------------------------------------------------------------------------------------------------
Total $437,939 $455,843 $476,265
================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 1,686,722 1,658,327 1,674,407
Commercial 1,607,988 1,555,044 1,544,899
Industrial 2,879,457 2,862,632 2,877,026
Other 86,049 81,153 81,352
------------------------------------------------------------------------------------------------
Total retail 6,260,216 6,157,156 6,177,684
Sales for resale - non-affiliates 2,280,341 2,615,058 2,382,443
Sales for resale - affiliates 1,100,808 955,303 704,461
------------------------------------------------------------------------------------------------
Total 9,641,365 9,727,517 9,264,588
================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 5.73 5.93 6.09
Commercial 6.14 6.35 6.51
Industrial 4.27 4.51 4.68
Total retail 5.18 5.39 5.55
Total sales 4.50 4.64 5.09
Residential Average Annual Kilowatt-Hour Use Per Customer 11,499 11,356 11,498
Residential Average Annual Revenue Per Customer $659.30 $673.41 $700.32
Plant Nameplate Capacity Ratings (year-end) (megawatts) 1,966 1,966 1,966
Maximum Peak-Hour Demand (megawatts):
Winter 1,284 1,224 1,208
Summer 1,621 1,548 1,612
Annual Load Factor (percent) 57.6 59.0 56.8
Plant Availability - Fossil-Steam (percent) 93.0 93.5 93.2
------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 86.3 79.4 74.1
Oil and gas 4.8 5.3 5.1
Purchased power -
From non-affiliates 0.4 0.3 2.0
From affiliates 8.5 15.0 18.8
------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0
================================================================================================
Total Fuel Economy Data:
BTU per net kilowatt-hour generated 10,220 10,525 10,569
Cost of fuel per million BTU (cents) 185.13 194.46 224.63
Average cost of fuel per net kilowatt-hour generated (cents) 1.89 2.05 2.37
------------------------------------------------------------------------------------------------
II-213B
SELECTED FINANCIAL AND OPERATING DATA (continued)
Mississippi Power Company 1994 Annual Report
====================================================================================
1985 1984
------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $96,878 $92,955
Commercial 96,883 91,500
Industrial 129,495 128,951
Other 5,884 5,704
------------------------------------------------------------------------------------
Total retail 329,140 319,110
Sales for resale - non-affiliates 115,757 106,691
Sales for resale - affiliates 27,277 13,226
------------------------------------------------------------------------------------
Total revenues from sales of electricity 472,174 439,027
Other revenues 3,436 3,480
------------------------------------------------------------------------------------
Total $475,610 $442,507
====================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 1,603,539 1,535,329
Commercial 1,500,972 1,415,153
Industrial 2,786,883 2,768,877
Other 83,142 78,198
------------------------------------------------------------------------------------
Total retail 5,974,536 5,797,557
Sales for resale - non-affiliates 2,819,439 2,656,738
Sales for resale - affiliates 733,142 285,562
------------------------------------------------------------------------------------
Total 9,527,117 8,739,857
====================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 6.04 6.05
Commercial 6.45 6.47
Industrial 4.65 4.66
Total retail 5.51 5.50
Total sales 4.96 5.02
Residential Average Annual Kilowatt-Hour Use Per Customer 11,135 10,814
Residential Average Annual Revenue Per Customer $672.71 $654.74
Plant Nameplate Capacity Ratings (year-end) (megawatts) 1,966 1,966
Maximum Peak-Hour Demand (megawatts):
Winter 1,310 1,210
Summer 1,444 1,421
Annual Load Factor (percent) 61.0 59.8
Plant Availability - Fossil-Steam (percent) 92.4 93.1
------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 74.1 67.5
Oil and gas 2.8 2.5
Purchased power -
From non-affiliates 0.4 0.2
From affiliates 22.7 29.8
------------------------------------------------------------------------------------
Total 100.0 100.0
====================================================================================
Total Fuel Economy Data:
BTU per net kilowatt-hour generated 10,396 10,385
Cost of fuel per million BTU (cents) 235.24 236.45
Average cost of fuel per net kilowatt-hour generated (cents) 2.45 2.46
------------------------------------------------------------------------------------
II-213C
STATEMENTS OF INCOME
Mississippi Power Company
========================================================================================================
For the Years Ended December 31, 1994 1993 1992
--------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Operating Revenues:
Revenues $ 489,624 $459,364 $424,392
Revenues from affiliates 9,538 15,519 10,055
--------------------------------------------------------------------------------------------------------
Total operating revenues 499,162 474,883 434,447
--------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
Fuel 102,216 113,986 96,743
Purchased power from non-affiliates 2,711 2,198 1,337
Purchased power from affiliates 68,543 58,019 60,689
Proceeds from settlement of disputed contracts - - (189)
Other 97,988 100,381 90,581
Maintenance 45,785 44,001 43,165
Depreciation and amortization 35,716 33,099 32,789
Taxes other than income taxes 41,742 37,145 34,664
Federal and state income taxes 31,386 22,668 16,378
--------------------------------------------------------------------------------------------------------
Total operating expenses 426,087 411,497 376,157
--------------------------------------------------------------------------------------------------------
Operating Income 73,075 63,386 58,290
Other Income (Expense):
Allowance for equity funds used during construction 1,099 1,010 642
Interest income 87 517 766
Other, net 2,033 3,971 5,501
Income taxes applicable to other income (227) (1,158) (1,427)
--------------------------------------------------------------------------------------------------------
Income Before Interest Charges 76,067 67,726 63,772
--------------------------------------------------------------------------------------------------------
Interest Charges:
Interest on long-term debt 19,725 17,688 22,357
Allowance for debt funds used during construction (1,039) (788) (563)
Interest on notes payable 1,442 1,000 362
Amortization of debt discount, premium, and expense, net 1,479 1,262 630
Other interest charges 404 728 339
--------------------------------------------------------------------------------------------------------
Net interest charges 22,011 19,890 23,125
--------------------------------------------------------------------------------------------------------
Net Income From Continuing Operations 54,056 47,836 40,647
--------------------------------------------------------------------------------------------------------
Discontinued Operations:
Loss from operations of discontinued subsidiary, net of taxes - - -
Loss on disposal of discontinued subsidiary, net of taxes - - -
Net Loss From Discontinued Operations - - -
--------------------------------------------------------------------------------------------------------
Net Income 54,056 47,836 40,647
Dividends on Preferred Stock 4,899 5,400 3,857
--------------------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred Stock $ 49,157 $ 42,436 $ 36,790
========================================================================================================
II-214
STATEMENTS OF INCOME
Mississippi Power Company
=====================================================================================================================
For the Years Ended December 31, 1991 1990 1989 1988
---------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Operating Revenues:
Revenues $ 414,342 $426,714 $425,712 $404,192
Revenues from affiliates 18,044 20,157 16,938 33,747
---------------------------------------------------------------------------------------------------------------------
Total operating revenues 432,386 446,871 442,650 437,939
---------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
Fuel 120,485 138,303 133,671 165,912
Purchased power from non-affiliates 851 1,406 1,266 1,257
Purchased power from affiliates 45,506 49,547 47,066 19,270
Proceeds from settlement of disputed contracts (4,205) - - -
Other 86,932 83,730 84,820 83,542
Maintenance 44,166 33,368 35,658 33,412
Depreciation and amortization 32,147 30,770 28,001 26,610
Taxes other than income taxes 35,414 32,709 32,435 29,638
Federal and state income taxes 13,976 17,144 18,387 20,313
---------------------------------------------------------------------------------------------------------------------
Total operating expenses 375,272 386,977 381,304 379,954
---------------------------------------------------------------------------------------------------------------------
Operating Income 57,114 59,894 61,346 57,985
Other Income (Expense):
Allowance for equity funds used during construction 728 307 903 850
Interest income 1,093 829 1,096 1,030
Other, net 3,845 6,297 6,013 6,399
Income taxes applicable to other income (863) (1,666) (1,392) (1,148)
---------------------------------------------------------------------------------------------------------------------
Income Before Interest Charges 61,917 65,661 67,966 65,116
---------------------------------------------------------------------------------------------------------------------
Interest Charges:
Interest on long-term debt 23,656 22,221 21,685 22,271
Allowance for debt funds used during construction (584) (600) (821) (595)
Interest on notes payable 603 1,142 689 341
Amortization of debt discount, premium, and expense, net 377 359 362 363
Other interest charges 285 333 566 522
---------------------------------------------------------------------------------------------------------------------
Net interest charges 24,337 23,455 22,481 22,902
---------------------------------------------------------------------------------------------------------------------
Net Income From Continuing Operations 37,580 42,206 45,485 42,214
---------------------------------------------------------------------------------------------------------------------
Discontinued Operations:
Loss from operations of discontinued subsidiary, net of taxes (6,404) (4,669) (3,459) (2,549)
Loss on disposal of discontinued subsidiary, net of taxes (5,455) - - -
Net Loss From Discontinued Operations (11,859) (4,669) (3,459) (2,549)
---------------------------------------------------------------------------------------------------------------------
Net Income 25,721 37,537 42,026 39,665
Dividends on Preferred Stock 3,094 3,361 3,450 3,584
---------------------------------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred Stock $ 22,627 $ 34,176 $ 38,576 $ 36,081
=====================================================================================================================
II-215A
STATEMENTS OF INCOME
Mississippi Power Company
======================================================================================================================
For the Years Ended December 31, 1987 1986 1985 1984
----------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Operating Revenues:
Revenues $ 424,565 $454,596 $448,333 $429,281
Revenues from affiliates 31,278 21,669 27,277 13,226
----------------------------------------------------------------------------------------------------------------------
Total operating revenues 455,843 476,265 475,610 442,507
----------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
Fuel 167,165 183,515 188,477 158,793
Purchased power from non-affiliates 1,108 4,671 1,807 836
Purchased power from affiliates 36,114 46,322 56,522 70,202
Proceeds from settlement of disputed contracts - - - -
Other 81,331 70,009 58,528 53,447
Maintenance 33,974 31,368 39,509 31,826
Depreciation and amortization 26,210 30,293 25,412 24,170
Taxes other than income taxes 27,882 26,145 23,930 24,495
Federal and state income taxes 23,888 30,881 29,142 26,525
----------------------------------------------------------------------------------------------------------------------
Total operating expenses 397,672 423,204 423,327 390,294
----------------------------------------------------------------------------------------------------------------------
Operating Income 58,171 53,061 52,283 52,213
Other Income (Expense):
Allowance for equity funds used during construction 608 1,030 693 820
Interest income 1,121 864 1,326 1,325
Other, net 7,065 8,983 9,867 6,482
Income taxes applicable to other income (2,507) (3,517) (3,880) (2,555)
----------------------------------------------------------------------------------------------------------------------
Income Before Interest Charges 64,458 60,421 60,289 58,285
----------------------------------------------------------------------------------------------------------------------
Interest Charges:
Interest on long-term debt 24,139 22,707 22,684 22,678
Allowance for debt funds used during construction (652) (770) (434) (1,800)
Interest on notes payable 558 252 - 1,082
Amortization of debt discount, premium, and expense, net 388 245 146 148
Other interest charges 601 283 562 754
----------------------------------------------------------------------------------------------------------------------
Net interest charges 25,034 22,717 22,958 22,862
----------------------------------------------------------------------------------------------------------------------
Net Income From Continuing Operations 39,424 37,704 37,331 35,423
----------------------------------------------------------------------------------------------------------------------
Discontinued Operations:
Loss from operations of discontinued subsidiary, net of taxes (487) - - -
Loss on disposal of discontinued subsidiary, net of taxes - - - -
Net Loss From Discontinued Operations (487) - - -
----------------------------------------------------------------------------------------------------------------------
Net Income 38,937 37,704 37,331 35,423
Dividends on Preferred Stock 3,737 3,890 4,001 4,043
----------------------------------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred Stock $ 35,200 $ 33,814 $ 33,330 $ 31,380
======================================================================================================================
II-215B
STATEMENTS OF CASH FLOWS
Mississippi Power Company
=======================================================================================================
For the Years Ended December 31, 1994 1993 1992
-------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Operating Activities:
Net income $ 54,056 $ 47,836 $ 40,647
Adjustments to reconcile net income to net
cash provided by operating activities --
Depreciation and amortization 47,827 45,660 41,472
Deferred income taxes, net 1,563 5,039 (5,473)
Deferred investment tax credits, net - - -
Allowance for equity funds used during construction (1,099) (1,010) (642)
Non-cash proceeds from settlement of disputed contracts - - (189)
Other, net 5,230 3,005 8,093
Changes in certain current assets and liabilities --
Receivables, net 3,066 (4,347) 1,002
Inventories (9,856) 11,119 975
Payables (8,754) 4,133 460
Other 3,334 (8,033) 6,095
-------------------------------------------------------------------------------------------------------
Net cash provided from operating activities 95,367 103,402 92,440
-------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (104,014) (139,976) (68,189)
Other (14,087) 7,562 4,235
-------------------------------------------------------------------------------------------------------
Net cash used for investing activities (118,101) (132,414) (63,954)
-------------------------------------------------------------------------------------------------------
Financing Activities and Capital Contributions:
Proceeds:
Preferred stock - 23,404 35,000
First mortgage bonds 35,000 70,000 40,000
Pollution control bonds - 38,875 23,300
Other long-term debt 85,310 - -
Capital contributions 25,000 30,036 26
Redemptions:
Preferred stock - (23,404) -
First mortgage bonds (32,628) (51,300) (104,703)
Pollution control bonds (10) (25,885) (23,650)
Other long-term debt (9,299) (8,170) (6,212)
Notes payable, net (40,000) 9,000 26,500
Payment of preferred stock dividends (4,899) (5,400) (3,857)
Payment of common stock dividends (34,100) (29,000) (28,000)
Miscellaneous (1,201) (5,683) (7,821)
-------------------------------------------------------------------------------------------------------
Net cash provided from (used for) financing activities 23,173 22,473 (49,417)
-------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents 439 (6,539) (20,931)
Cash and Cash Equivalents at Beginning of Year 878 7,417 28,348
-------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 1,317 $ 878 $ 7,417
=======================================================================================================
( ) Denotes use of cash.
II-216
STATEMENTS OF CASH FLOWS
Mississippi Power Company
==================================================================================================================
For the Years Ended December 31, 1991 1990 1989 1988
------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Operating Activities:
Net income $ 25,721 $ 37,537 $ 42,026 $ 39,665
Adjustments to reconcile net income to net
cash provided by operating activities --
Depreciation and amortization 41,773 41,079 35,878 34,440
Deferred income taxes, net (11,869) 2,756 (294) (3,053)
Deferred investment tax credits, net (2) (26) (38) 571
Allowance for equity funds used during construction (728) (307) (903) (850)
Non-cash proceeds from settlement of disputed contracts (4,071) - - -
Other, net (4,982) 7,257 4,306 3,503
Changes in certain current assets and liabilities --
Receivables, net 35,343 (6,252) (18,506) 816
Inventories 10,518 (8,922) 3,687 283
Payables (4,949) (5,552) 1,307 (5,241)
Other 11,433 (1,461) 2,172 (2,294)
------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities 98,187 66,109 69,635 67,840
------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (53,675) (49,009) (43,916) (54,550)
Other 2,148 4,481 1,860 8,368
------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities (51,527) (44,528) (42,056) (46,182)
------------------------------------------------------------------------------------------------------------------
Financing Activities and Capital Contributions:
Proceeds:
Preferred stock - - - -
First mortgage bonds 50,000 - - -
Pollution control bonds - - - -
Other long-term debt 844 - 844 -
Capital contributions - - - -
Redemptions:
Preferred stock (4,118) (750) (750) (1,500)
First mortgage bonds - (4,000) (3,823) -
Pollution control bonds (300) (288) (62) (50)
Other long-term debt (8,958) (6,416) (5,919) (5,401)
Notes payable, net (25,603) 17,146 6,457 6,500
Payment of preferred stock dividends (3,094) (3,361) (3,450) (3,584)
Payment of common stock dividends (28,500) (27,500) (27,000) (27,600)
Miscellaneous (839) 2 - -
------------------------------------------------------------------------------------------------------------------
Net cash provided from (used for) financing activities (20,568) (25,167) (33,703) (31,635)
------------------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents 26,092 (3,586) (6,124) (9,977)
Cash and Cash Equivalents at Beginning of Year 2,256 5,842 11,966 21,943
------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 28,348 $ 2,256 $ 5,842 $ 11,966
==================================================================================================================
( ) Denotes use of cash.
II-217A
STATEMENTS OF CASH FLOWS
Mississippi Power Company
==================================================================================================================
For the Years Ended December 31, 1987 1986 1985 1984
------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Operating Activities:
Net income $ 38,937 $ 37,704 $ 37,331 $ 35,423
Adjustments to reconcile net income to net
cash provided by operating activities --
Depreciation and amortization 33,971 33,432 28,229 26,487
Deferred income taxes, net 10,035 41,059 11,246 10,156
Deferred investment tax credits, net 896 2,442 1,749 6,336
Allowance for equity funds used during construction (608) (1,030) (693) (820)
Non-cash proceeds from settlement of disputed contracts - - - -
Other, net 1,965 (14,162) (2,709) 3,802
Changes in certain current assets and liabilities --
Receivables, net 12,000 (1,708) (5,050) 8,734
Inventories 13,708 (8,499) 12,281 (23,307)
Payables 7,487 (14,502) 4,656 (5,506)
Other (9,342) 11,546 (3,725) (3,651)
------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities 109,049 86,282 83,315 57,654
------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (53,288) (62,488) (57,791) (37,290)
Other (1,461) (61,162) 3,825 388
------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities (54,749) (123,650) (53,966) (36,902)
------------------------------------------------------------------------------------------------------------------
Financing Activities and Capital Contributions:
Proceeds:
Preferred stock - - - -
First mortgage bonds - 35,000 - -
Pollution control bonds - - - -
Other long-term debt 130 60,663 1,000 -
Capital contributions 16,000 400 400 1,000
Redemptions:
Preferred stock (1,500) (1,500) (1,111) (639)
First mortgage bonds (29,701) (29,250) (250) (250)
Pollution control bonds (50) (50) (50) (50)
Other long-term debt (4,974) (200) - -
Notes payable, net - - - -
Payment of preferred stock dividends (3,737) (3,890) (4,001) (4,043)
Payment of common stock dividends (24,700) (23,700) (22,600) (21,000)
Miscellaneous (2,696) (2,929) (18) -
------------------------------------------------------------------------------------------------------------------
Net cash provided from (used for) financing activities (51,228) 34,544 (26,630) (24,982)
------------------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents 3,072 (2,824) 2,719 (4,230)
Cash and Cash Equivalents at Beginning of Year 18,871 21,695 18,976 23,206
------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 21,943 $ 18,871 $ 21,695 $ 18,976
==================================================================================================================
( ) Denotes use of cash.
II-217B
BALANCE SHEETS
Mississippi Power Company
=========================================================================================================
At December 31, 1994 1993 1992
---------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
ASSETS
Utility Plant:
Production-fossil $ 705,043 $ 597,425 $ 576,848
Transmission 202,503 188,375 173,278
Distribution 313,345 295,799 279,335
General 164,141 157,248 151,044
Construction work in progress 44,838 108,063 41,692
---------------------------------------------------------------------------------------------------------
Total utility plant 1,429,870 1,346,910 1,222,197
Accumulated provision for depreciation 477,098 462,725 440,777
---------------------------------------------------------------------------------------------------------
Total 952,772 884,185 781,420
---------------------------------------------------------------------------------------------------------
Less property-related accumulated deferred income taxes - - 142,338
---------------------------------------------------------------------------------------------------------
Total 952,772 884,185 639,082
---------------------------------------------------------------------------------------------------------
Other Property and Investments:
Securities received from settlement of disputed contracts - - -
Miscellaneous 3,353 11,289 4,539
---------------------------------------------------------------------------------------------------------
Total 3,353 11,289 4,539
---------------------------------------------------------------------------------------------------------
Current Assets:
Cash and cash equivalents 1,317 878 7,417
Investment securities - - 3,622
Receivables, net 25,424 28,021 20,219
Accrued utility revenues 14,428 14,897 14,898
Fossil fuel stock, at average cost 16,885 11,185 21,341
Materials and supplies, at average cost 25,301 21,145 22,108
Current portion of deferred fuel commitments 1,068 440 1,861
Prepayments 11,189 8,971 5,869
Vacation pay deferred 4,588 4,797 4,651
---------------------------------------------------------------------------------------------------------
Total 100,200 90,334 101,986
---------------------------------------------------------------------------------------------------------
Deferred Charges:
Debt expense, being amortized 1,358 1,103 804
Premium on reacquired debt, being amortized 9,571 10,563 10,102
Deferred fuel commitments 9,000 17,520 25,255
Deferred charges related to income taxes 25,036 25,267 -
Miscellaneous 22,421 10,073 9,515
---------------------------------------------------------------------------------------------------------
Total 67,386 64,526 45,676
---------------------------------------------------------------------------------------------------------
Total Assets $1,123,711 $1,050,334 $ 791,283
=========================================================================================================
II-218
BALANCE SHEETS
Mississippi Power Company
======================================================================================================================
At December 31, 1991 1990 1989 1988
----------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
ASSETS
Utility Plant:
Production-fossil $ 567,588 $ 560,537 $ 547,946 $ 529,742
Transmission 162,379 151,949 147,288 134,674
Distribution 259,929 247,705 229,238 221,327
General 141,564 136,815 133,361 137,333
Construction work in progress 33,078 26,816 27,057 35,204
----------------------------------------------------------------------------------------------------------------------
Total utility plant 1,164,538 1,123,822 1,084,890 1,058,280
Accumulated provision for depreciation 415,135 392,440 366,193 348,085
----------------------------------------------------------------------------------------------------------------------
Total 749,403 731,382 718,697 710,195
----------------------------------------------------------------------------------------------------------------------
Less property-related accumulated deferred income taxes 138,616 139,970 138,071 134,220
----------------------------------------------------------------------------------------------------------------------
Total 610,787 591,412 580,626 575,975
----------------------------------------------------------------------------------------------------------------------
Other Property and Investments:
Securities received from settlement of disputed contracts 4,113 - - -
Miscellaneous 3,954 8,631 7,792 8,153
----------------------------------------------------------------------------------------------------------------------
Total 8,067 8,631 7,792 8,153
----------------------------------------------------------------------------------------------------------------------
Current Assets:
Cash and cash equivalents 28,348 2,256 5,842 11,966
Investment securities - - - -
Receivables, net 27,152 67,734 58,425 43,246
Accrued utility revenues 12,420 10,797 13,854 10,527
Fossil fuel stock, at average cost 22,373 29,812 24,788 26,587
Materials and supplies, at average cost 22,051 25,130 21,232 23,120
Current portion of deferred fuel commitments 933 1,430 3,017 -
Prepayments 6,137 11,392 12,512 12,341
Vacation pay deferred 4,406 3,955 3,910 3,815
----------------------------------------------------------------------------------------------------------------------
Total 123,820 152,506 143,580 131,602
----------------------------------------------------------------------------------------------------------------------
Deferred Charges:
Debt expense, being amortized 981 824 886 949
Premium on reacquired debt, being amortized 4,676 4,919 5,161 5,404
Deferred fuel commitments 31,039 39,020 45,103 50,714
Deferred charges related to income taxes - - - -
Miscellaneous 11,271 2,714 3,422 6,522
----------------------------------------------------------------------------------------------------------------------
Total 47,967 47,477 54,572 63,589
----------------------------------------------------------------------------------------------------------------------
Total Assets $ 790,641 $ 800,026 $ 786,570 $ 779,319
======================================================================================================================
II-219A
BALANCE SHEETS
Mississippi Power Company
======================================================================================================================
At December 31, 1987 1986 1985 1984
----------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
ASSETS
Utility Plant:
Production-fossil $ 524,198 $ 509,128 $ 485,665 $ 477,618
Transmission 130,963 125,304 121,405 118,552
Distribution 207,810 195,042 183,003 169,545
General 127,690 114,042 99,788 90,626
Construction work in progress 27,755 33,544 34,862 17,054
----------------------------------------------------------------------------------------------------------------------
Total utility plant 1,018,416 977,060 924,723 873,395
Accumulated provision for depreciation 328,761 312,571 293,167 266,844
----------------------------------------------------------------------------------------------------------------------
Total 689,655 664,489 631,556 606,551
----------------------------------------------------------------------------------------------------------------------
Less property-related accumulated deferred income taxes 127,912 120,990 107,633 98,494
----------------------------------------------------------------------------------------------------------------------
Total 561,743 543,499 523,923 508,057
----------------------------------------------------------------------------------------------------------------------
Other Property and Investments:
Securities received from settlement of disputed contracts - - - -
Miscellaneous 4,122 1,738 641 630
----------------------------------------------------------------------------------------------------------------------
Total 4,122 1,738 641 630
----------------------------------------------------------------------------------------------------------------------
Current Assets:
Cash and cash equivalents 21,943 18,871 21,695 18,976
Investment securities - - - -
Receivables, net 42,218 48,158 42,407 39,137
Accrued utility revenues 12,371 18,431 22,474 20,694
Fossil fuel stock, at average cost 29,989 46,067 40,638 57,225
Materials and supplies, at average cost 20,001 17,631 14,561 10,255
Current portion of deferred fuel commitments - - - -
Prepayments 830 973 805 497
Vacation pay deferred 3,956 3,559 3,337 2,910
----------------------------------------------------------------------------------------------------------------------
Total 131,308 153,690 145,917 149,694
----------------------------------------------------------------------------------------------------------------------
Deferred Charges:
Debt expense, being amortized 1,012 1,212 1,208 1,260
Premium on reacquired debt, being amortized 5,647 2,800 - -
Deferred fuel commitments 55,889 60,663 - -
Deferred charges related to income taxes - - - -
Miscellaneous 4,347 3,508 7,888 889
----------------------------------------------------------------------------------------------------------------------
Total 66,895 68,183 9,096 2,149
----------------------------------------------------------------------------------------------------------------------
Total Assets $ 764,068 $ 767,110 $ 679,577 $ 660,530
======================================================================================================================
II-219B
BALANCE SHEETS
Mississippi Power Company
=========================================================================================================
At December 31, 1994 1993 1992
---------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock $ 37,691 $ 37,691 $ 37,691
Paid-in capital 179,362 154,362 124,326
Premium on preferred stock 372 372 194
Earnings retained in the business 144,328 129,343 118,429
---------------------------------------------------------------------------------------------------------
Total common equity 361,753 321,768 280,640
Preferred stock 74,414 74,414 74,414
Preferred stock subject to mandatory redemption - - -
Long-term debt 306,522 250,391 238,650
---------------------------------------------------------------------------------------------------------
Total (excluding amount due within one year) 742,689 646,573 593,704
---------------------------------------------------------------------------------------------------------
Current Liabilities:
Notes payable to banks - 40,000 31,000
Preferred stock due within one year - - -
Long-term debt due within one year 41,199 19,345 8,878
Accounts payable 34,481 60,928 43,550
Customer deposits 2,712 2,786 2,976
Taxes accrued 31,657 27,138 32,035
Interest accrued 4,427 4,237 3,961
Vacation pay accrued 4,588 4,797 4,651
Miscellaneous 10,025 9,323 10,963
---------------------------------------------------------------------------------------------------------
Total 129,089 168,554 138,014
---------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 129,505 124,334 169
Accumulated deferred investment tax credits 31,228 32,710 34,242
Deferred credits related to income taxes 45,832 48,228 -
Miscellaneous 45,368 29,935 25,154
---------------------------------------------------------------------------------------------------------
Total 251,933 235,207 59,565
---------------------------------------------------------------------------------------------------------
Total Capitalization and Liabilities $1,123,711 $1,050,334 $ 791,283
=========================================================================================================
II-220
BALANCE SHEETS
Mississippi Power Company
======================================================================================================================
At December 31, 1991 1990 1989 1988
----------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock $ 37,691 $ 37,691 $ 37,691 $ 37,691
Paid-in capital 124,300 124,300 124,300 124,300
Premium on preferred stock 194 299 299 299
Earnings retained in the business 111,670 117,543 110,867 99,183
----------------------------------------------------------------------------------------------------------------------
Total common equity 273,855 279,833 273,157 261,473
Preferred stock 39,414 39,414 39,414 39,414
Preferred stock subject to mandatory redemption - 3,750 4,500 5,250
Long-term debt 304,150 270,724 277,693 287,525
----------------------------------------------------------------------------------------------------------------------
Total (excluding amount due within one year) 617,419 593,721 594,764 593,662
----------------------------------------------------------------------------------------------------------------------
Current Liabilities:
Notes payable to banks 4,500 30,103 12,957 6,500
Preferred stock due within one year - 368 368 368
Long-term debt due within one year 14,650 7,039 10,717 9,789
Accounts payable 38,213 45,763 47,019 46,937
Customer deposits 3,109 3,430 3,906 3,904
Taxes accrued 29,609 24,935 23,843 21,130
Interest accrued 4,602 4,315 4,280 4,016
Vacation pay accrued 4,406 3,955 3,910 3,815
Miscellaneous 10,236 6,833 7,746 9,347
----------------------------------------------------------------------------------------------------------------------
Total 109,325 126,741 114,746 105,806
----------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 4,117 18,992 22,085 24,556
Accumulated deferred investment tax credits 35,657 37,187 38,752 40,435
Deferred credits related to income taxes - - - -
Miscellaneous 24,123 23,385 16,223 14,860
----------------------------------------------------------------------------------------------------------------------
Total 63,897 79,564 77,060 79,851
----------------------------------------------------------------------------------------------------------------------
Total Capitalization and Liabilities $ 790,641 $ 800,026 $ 786,570 $ 779,319
======================================================================================================================
II-221A
BALANCE SHEETS
Mississippi Power Company
======================================================================================================================
At December 31, 1987 1986 1985 1984
----------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock $ 37,691 $ 37,691 $ 37,691 $ 37,691
Paid-in capital 124,300 108,300 107,900 107,500
Premium on preferred stock 299 299 299 360
Earnings retained in the business 90,702 80,311 70,197 59,467
----------------------------------------------------------------------------------------------------------------------
Total common equity 252,992 226,601 216,087 205,018
Preferred stock 39,414 39,414 39,414 39,414
Preferred stock subject to mandatory redemption 6,750 8,250 9,750 10,500
Long-term debt 294,811 299,684 261,594 267,051
----------------------------------------------------------------------------------------------------------------------
Total (excluding amount due within one year) 593,967 573,949 526,845 521,983
----------------------------------------------------------------------------------------------------------------------
Current Liabilities:
Notes payable to banks - - - -
Preferred stock due within one year 368 368 368 729
Long-term debt due within one year 5,451 34,724 6,532 300
Accounts payable 45,659 36,490 50,992 46,336
Customer deposits 3,857 3,720 3,521 4,240
Taxes accrued 21,351 29,029 32,015 24,850
Interest accrued 4,474 5,064 5,502 5,577
Vacation pay accrued 3,956 3,559 3,337 2,910
Miscellaneous 6,005 5,746 5,464 6,453
----------------------------------------------------------------------------------------------------------------------
Total 91,121 118,700 107,731 91,395
----------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 27,411 25,922 - -
Accumulated deferred investment tax credits 41,427 42,183 41,311 41,063
Deferred credits related to income taxes - - - -
Miscellaneous 10,142 6,356 3,690 6,089
----------------------------------------------------------------------------------------------------------------------
Total 78,980 74,461 45,001 47,152
----------------------------------------------------------------------------------------------------------------------
Total Capitalization and Liabilities $ 764,068 $ 767,110 $ 679,577 $ 660,530
======================================================================================================================
II-221B
MISSISSIPPI POWER COMPANY
OUTSTANDING SECURITIES AT DECEMBER 31, 1994
First Mortgage Bonds
Amount Interest Amount
Series Issued Rate Outstanding Maturity
----------------------------------------------------------------
(Thousands) (Thousands)
1993 $ 35,000 5-3/8% $ 35,000 3/1/98
1992 40,000 6-5/8% 40,000 8/1/00
1994 35,000 6.60% 35,000 3/1/04
1991 50,000 9-1/4% 47,072 5/1/21
1993 35,000 7.45% 35,000 6/1/23
-------- --------
$195,000 $192,072
======== ========
Pollution Control Bonds
Amount Interest Amount
Series Issued Rate Outstanding Maturity
----------------------------------------------------------------
(Thousands) (Thousands)
1977 $ 1,000 5.80% $ 980 10/1/07
1992 6,550 Variable 6,550 12/1/20
1992 16,750 Variable 16,750 12/1/22
1993 13,000 6.20% 13,000 4/1/23
1993 25,875 5.65% 25,875 11/1/23
-------- --------
$ 63,175 $ 63,155
======== ========
Preferred Stock
Shares Dividend Amount
Series Outstanding Rate Outstanding
----------------------------------------------------------------
(Thousands)
1947 20,099 4.60% $ 2,010
1956 40,000 4.40% 4,000
1965 50,000 4.72% 5,000
1968 50,000 7.00% 5,000
1992 350,000 7.25% 35,000
1993 150,000 6.32% 15,000
1993 84,040 6.65% 8,404
------- --------
744,139 $ 74,414
======= ========
II-222
MISSISSIPPI POWER COMPANY
SECURITIES RETIRED DURING 1994
First Mortgage Bonds
Principal Interest
Series Amount Rate
-----------------------------------------------------------------------------
(Thousands)
1964 $10,000 4-5/8%
1965 11,000 4-3/4%
1966 10,000 6%
1991 1,628 9-1/4%
-------
$32,628
=======
Pollution Control Bonds
Principal Interest
Series Amount Rate
-----------------------------------------------------------------------------
(Thousands)
1977 $ 10 5.80%
II-223
SAVANNAH ELECTRIC AND POWER COMPANY
FINANCIAL SECTION
II-224
MANAGEMENT'S REPORT
Savannah Electric and Power Company 1994 Annual Report
The management of Savannah Electric and Power Company has prepared -- and is
responsible for -- the financial statements and related information included in
this report. These statements were prepared in accordance with generally
accepted accounting principles appropriate in the circumstances and necessarily
include amounts that are based on the best estimates and judgments of
management. Financial information throughout this annual report is consistent
with the financial statements.
The Company maintains a system of internal accounting controls to provide
reasonable assurance that assets are safeguarded and that books and records
reflect only authorized transactions of the Company. Limitations exist in any
system of internal controls, however, based on a recognition that the cost of
the system should not exceed its benefits. The Company believes its system of
internal accounting controls maintains an appropriate cost/benefit relationship.
The Company's system of internal accounting controls is evaluated on an
ongoing basis by the Company's internal audit staff. The Company's independent
public accountants also consider certain elements of the internal control system
in order to determine their auditing procedures for the purpose of expressing an
opinion on the financial statements.
The audit committee of the board of directors, composed of four directors
who are not employees, provides a broad overview of management's financial
reporting and control functions. Periodically, this committee meets with
management, the internal auditors and the independent public accountants to
ensure that these groups are fulfilling their obligations and to discuss
auditing, internal controls and financial reporting matters. The internal
auditors and the independent public accountants have access to the members of
the audit committee at any time.
Management believes that its policies and procedures provide reasonable
assurance that the Company's operations are conducted according to a high
standard of business ethics. In management's opinion, the financial statements
present fairly, in all material respects, the financial position, results of
operations, and cash flows of Savannah Electric and Power Company in conformity
with generally accepted accounting principles.
/s/ Arthur M. Gignilliat, Jr.
Arthur M. Gignilliat, Jr.
President and Chief Executive Officer
/s/ K. R. Willis
K. R. Willis
Vice-President Treasurer and Chief Financial Officer
II-225
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
Savannah Electric and Power Company 1994 Annual Report
To the Board of Directors
of Savannah Electric and Power Company:
We have audited the accompanying balance sheets and statements of capitalization
of Savannah Electric and Power Company (a Georgia corporation and a wholly owned
subsidiary of The Southern Company) as of December 31, 1994 and 1993, 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, 1994. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements (pages II-233 through II-246)
referred to above present fairly, in all material respects, the financial
position of Savannah Electric and Power Company as of December 31, 1994 and
1993, and the results of its operations and its cash flows for the periods
stated, in conformity with generally accepted accounting principles.
As explained in Notes 2 and 7 to the financial statements, effective
January 1, 1993, the Company changed its methods of accounting for
postretirement benefits other than pensions and for income taxes.
/s/ Arthur Andersen LLP
Atlanta, Georgia
February 15, 1995
II-226
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Savannah Electric and Power Company 1994 Annual Report
RESULTS OF OPERATIONS
Earnings
Savannah Electric and Power Company's net income after dividends on preferred
stock for 1994 totaled $22.1 million, representing a $0.6 million (3.0 percent)
increase over the prior year. This increase was primarily due to a decrease in
operating expenses, offset somewhat by an increase in interest expense.
In 1993, earnings were $21.5 million, representing a $1.0 million (4.6
percent) increase from the prior year. The revenue impact of an increase in
retail energy sales due to exceptionally hot summer weather was partially offset
by the implementation of a work force reduction program which resulted in a
one-time charge to operating expenses of approximately $4.5 million.
Revenues
Total revenues for 1994 were $211.8 million, reflecting a 3.0 percent decrease
compared to 1993. The revenue impact of an expanding customer base was offset by
moderate weather, reduced industrial energy sales, and an associated decrease in
fuel cost recovery revenues.
The following table summarizes revenue increases and decreases compared to
prior years:
==============================================================
Increase (Decrease)
From Prior Years
--------------------------------
1994 1993 1992
--------------------------------
Retail -- (in thousands)
Change in base rates $ - $(1,450) $(1,350)
Sales growth 7,884 5,980 5,467
Weather (6,589) 4,567 (3,116)
Fuel cost recovery
and other (9,214) 12,404 7,270
--------------------------------------------------------------
Total retail (7,919) 21,501 8,271
--------------------------------------------------------------
Sales for resale--
Non-affiliates (1,235) (1,800) 8
Affiliates 4,013 928 75
--------------------------------------------------------------
Total sales for resale 2,778 (872) 83
--------------------------------------------------------------
Other operating revenues (1,516) 52 (239)
--------------------------------------------------------------
Total operating revenues $(6,657) $20,681 $ 8,115
==============================================================
Percent change (3.0)% 10.5% 4.3%
--------------------------------------------------------------
Retail revenues decreased 3.8 percent in 1994, compared to an increase of
11.5 percent in 1993. The decrease in 1994 retail revenues is attributable to
milder summer weather, reduced industrial energy sales, and substantially lower
fuel cost recovery revenues, offset somewhat by customer growth. Industrial
energ y sales turned down in the fourth quarter of 1994 when operations of a
large industrial customer were temporarily curtailed due to a mechanical failure
of a machine which was a major part of the customer's manufacturing operation.
Under the Company's fuel cost recovery provisions, fuel revenues --including
purchased energy-- generally equal fuel expense and have no effect on earnings.
The $1.5 million decrease in other operating revenues reflects deferral of over
recovery of demand-side management rider revenues during 1994. Revenues from
demand-side management riders (included in retail revenues) recover demand-side
management program costs and have little impact on earnings.
The increase in 1993 retail revenues resulted from customer growth and an
increase in the average annual kilowatt-hour use per customer which was
substantially increased due to hot summer weather.
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. Capacity and energy revenues
decreased in 1994 due to reductions in sales to Florida Power Corporation. The
capacity and energy components were as follows:
========================================================
1994 1993 1992
--------------------------------------------------------
(in thousands)
Capacity $ 448 $ 978 $ 537
Energy 3,052 4,262 7,040
--------------------------------------------------------
Total $3,500 $5,240 $7,577
========================================================
Sales to affiliated companies within the Southern electric system vary from
year to year depending on demand and the availability and cost of generating
resources at each company. These sales have little impact on earnings.
II-227
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 1994 Annual Report
Kilowatt-hour sales for 1994 and the percent change by year were as
follows:
===============================================================
Percent Change
-------------------------
1994
KWH 1994 1993 1992
---------- ------------------------
(in millions)
Residential 1,298 (2.3)% 9.2% 1.8%
Commercial 1,046 2.9 6.5 3.0
Industrial 800 (6.4) (0.8) 4.3
Other 119 3.1 5.2 3.4
------
Total retail 3,263 (1.6) 5.5 2.9
Sales for resale -
Non-affiliates 202 (18.4) (32.7) (1.3)
Affiliates 93 23.4 100.3 15.5
------
Total 3,558 (2.2)% 2.6% 2.6%
======
===============================================================
Expenses
Total operating expenses for 1994 were $175.6 million, reflecting an $8.6
million decrease from 1993. This decrease includes a $5.8 million reduction in
fuel and purchased power expenses, reflecting a decrease in total energy
requirements. The $4.9 million reduction in 1994 in other operation and
maintenance expenses reflects the $4.5 million work force reduction charge in
1993 and a $1.1 million reduction in power generation expenses in 1994. This was
offset by an increase in depreciation expense because of additions to utility
plant, principally two combustion turbine units. Interest expense increased $1.9
million primarily due to the sale in June 1993 of $45 million of first mortgage
bonds.
Total operating expenses for 1993 increased $20.3 million (12.4 percent)
over the prior year. This increase includes a $10.8 million increase in fuel
expense, and an $8.7 million increase in other operation expenses. Fuel expenses
increased primarily because of higher generation due to extremely hot summer
weather and the higher cost of fuel. The increase in other operation expenses
reflects $4.5 million associated with the work force reduction program. The
Company also recognized higher employee benefit costs under new accounting rules
adopted in 1993. See Note 2 to the financial statements for additional
information on these new rules.
Fuel and purchased power costs constitute the single largest expense for
the Company. The mix of energy supply is determined primarily by system load,
the unit cost of fuel consumed and the availability of units.
The amount and sources of energy supply, the average cost of fuel per net
kilowatt-hour generated, and the total average cost of energy supply (including
purchased power) were as follows:
===============================================================
1994 1993 1992
-----------------------
Total energy supply
(millions of kilowatt-hours) 3,768 3,863 3,764
Sources of energy supply
(percent)
Coal 18 21 12
Oil 1 2 1
Gas 1 3 2
Purchased Power 80 74 85
Average cost of fuel per net
kilowatt-hour generated
(cents)
Coal 2.19 2.02 2.28
Oil 3.89 4.11 2.40
Gas 5.19 4.87 4.28
Total average cost of
energy supply 2.02 2.12 1.78
===============================================================
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.
II-228
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 1994 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 growth in energy sales to a less regulated, more
competitive environment.
Future earnings in the near term will depend upon growth in energy sales,
which is subject to a number of factors. Traditionally, these factors included
changes in contracts with neighboring utilities, energy conservation practiced
by customers, the elasticity of demand, weather, competition, and the rate of
economic growth in the Company's service area. However, the Energy Policy Act of
1992 (Energy Act) 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 to
sell electricity to other utilities. This may enhance the incentives for IPPs to
build cogeneration plants for the Company's large industrial and commercial
customers. Although the Energy Act does not require transmission access to
retail customers, retail wheeling initiatives are rapidly evolving and becoming
very prominent issues in several states. 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.
Demand-side options -- programs that enable customers to lower or alter
their peak energy requirements -- have been initiated by the Company and are a
significant part of integrated resource planning. Customers can receive cash
incentives for participating in these programs in addition to reducing their
energy requirements. 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. The ability to defer
major construction projects in conjunction with regulatory precertification
approval processes for both new plant additions and purchase power contracts
should minimize the possibility of not being able to fully recover additional
costs.
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. See Note 1 to the financial statements under
"Regulatory Assets and Liabilities" for additional information.
Compliance costs related to the Clean Air Act Amendments of 1990 (Clean Air
Act) could reduce earnings if such costs are not fully recovered. The Clean Air
Act is discussed later under "Environmental Matters."
Rates to retail customers served by the Company are regulated by the
Georgia Public Service Commission (GPSC). In May 1992, the Company requested,
and subsequently received, approval by the GPSC to reduce annual base revenues
by $2.8 million, effective June 1992. The reduction included a base rate
reduction of approximately $2.5 million spread among all classes of retail
customers. An additional $0.3 million reduction resulted from the implementation
of an experimental, time-of-use rate for certain commercial customers. As part
of this rate settlement, it was informally agreed that the Company's earned rate
of return on common equity should be 12.95 percent.
FINANCIAL CONDITION
Overview
The principal change in the Company's financial condition in 1994 was the
addition of $30 million to utility plant. The majority of funds needed for gross
property additions since 1992 have been provided from operating activities,
II-229
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 1994 Annual Report
principally from earnings and non-cash charges to income such as depreciation
and deferred income taxes. See Statements of Cash Flows for additional
information.
Capital Structure
As of December 31, 1994, the Company's capital structure consisted of 45.8
percent common equity, 9.9 percent preferred stock and 44.3 percent long-term
debt, excluding amounts due within one year. The Company's long-term financial
objective for capitalization ratios is to maintain a capital structure of common
equity at 45 percent, preferred stock at 10 percent and debt at 45 percent.
Maturities and retirements of long-term debt were $5 million in 1994, $4
million in 1993 and $53 million in 1992.
The composite interest rates and dividend rates for the years 1992 through
1994 as of year-end were as follows:
===================================================================
1994 1993 1992
-----------------------------
Composite interest rates
on long-term debt 8.0% 8.0% 8.5%
Composite preferred stock
dividend rate 6.6% 6.6% 9.5%
===================================================================
The Company's current securities ratings are as follows:
===================================================================
Standard
Moody's & Poor's
------------------------
First Mortgage Bonds A1 A
Preferred Stock "a2" A-
-- --
===================================================================
Capital Requirements for Construction
The Company's projected construction expenditures for the next three years total
$87 million ($34 million in 1995, $27 million in 1996, and $26 million in 1997).
Actual construction costs may vary from this estimate because of such factors as
changes in environmental regulations; revised load projections; the cost and
efficiency of construction labor, equipment and materials; and the cost of
capital. In addition, there can be no assurance that costs related to capital
expenditures will be fully recovered.
Other Capital Requirements
In addition to the funds needed for the construction program, approximately $2.9
million will be needed by the end of 1997 for present sinking fund requirements
and a capital lease buyout.
Environmental Matters
In November 1990, the Clean Air Act was signed into law. Title IV of the Clean
Air Act -- the acid rain compliance provision of the new law --may have a
significant impact on the Company and other subsidiaries of the Southern
electric system. Specific reductions in sulfur dioxide and nitrogen oxide
emissions from fossil-fired generating plants will be required in two phases.
Phase I compliance began in 1995, and affects eight generating plants -- some
10,000 megawatts of capacity or 35 percent of total capacity -- in the Southern
electric system. Phase II compliance is required in 2000, and all fossil-fired
generating plants in the Southern electric system will be affected.
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 expects to achieve Phase I sulfur dioxide compliance
at the eight affected plants by switching to low-sulfur coal, and this would
require some equipment upgrades. This compliance strategy is expected to result
in unused emission allowances being banked for later use. Additional
II-230
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 1994 Annual Report
construction expenditures are required to install equipment for the control of
nitrogen oxide emissions at these eight plants. Also, continuous emissions
monitoring equipment has been installed on all fossil-fired units. Construction
expenditures for Phase I compliance are estimated to total approximately $300
million through 1995 for The Southern Company, of which the Company's portion is
approximately $2 million.
For Phase II sulfur dioxide compliance, The Southern Company could use
emission allowances banked during Phase I and increase fuel switching, install
flue gas desulfurization equipment at selected plants, and/or purchase more
allowances, depending on the price and availability of allowances. Also, in
Phase II, equipment to control nitrogen oxide emissions will be installed on
additional system fossil-fired plants as required to meet anticipated Phase II
limits. Therefore, during the period 1996 through 2000, current compliance
strategy could require total estimated construction expenditures of
approximately $150 million. No construction expenditures are expected to be
required of the Company to comply with Phase II requirements. 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 2 percent in annual revenue requirements from
customers could be necessary to fully recover the Company's costs of compliance
for both Phase I and II of the Clean Air Act. Compliance costs include
construction expenditures, increased costs for switching to low-sulfur coal, and
costs related to emission allowances.
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 by November 1995. 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.
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.
The EPA continues to evaluate the need for a new short-term ambient air
quality standard for sulfur dioxide. Preliminary results from an EPA study on
the impact of a new standard indicate that a number of plants could be required
to install sulfur dioxide controls. These controls would be in addition to the
controls already required to meet the acid rain provision of the Clean Air Act.
The EPA issued proposed rules in November 1994 and is required to take final
action on this issue in 1996. The impact of any new standard will depend on the
level chosen for the standard and cannot be determined at this time.
In addition, the EPA is evaluating the need to revise the ambient air
quality standards for particulate matter, nitrogen oxides, and ozone. The impact
of any new standard will depend on the level chosen for the standard and cannot
be determined at this time.
In 1995, 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
II-231
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 1994 Annual Report
regulations, the Company could incur substantial costs to clean up properties
currently or previously owned. The Company conducts studies to determine the
extent of any required cleanup costs and will recognize in the financial
statements any 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 Water Act;
the Comprehensive Environmental Response, Compensation, and Liability Act; the
Resource Conservation and Recovery 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 new legislation related to global climate change,
electromagnetic fields, and other environmental and health concerns could
significantly affect The Southern Company. The impact of new legislation -- if
any -- will depend on the subsequent development and implementation of
applicable regulations. In addition, the potential exists for liability as the
result of lawsuits alleging damages caused by electromagnetic fields.
Sources of Capital
At December 31, 1994, the Company had $1.6 million of cash and $18 million of
unused credit arrangements with banks to meet its short-term cash needs. The
Company had $2.5 million of short-term bank borrowings at December 31, 1994. In
December 1994, the Company renegotiated a two-year revolving credit arrangement
with three of its existing banks for a total credit line of $20 million. The
primary purpose of this additional credit is to provide interim funding for the
Company's construction program.
It is anticipated that the funds required for construction and other
purposes, including compliance with environmental regulations, will also be
derived from operations and the sale of additional first mortgage bonds and
preferred stock and capital contributions from The Southern Company. The Company
is required to meet certain coverage requirements specified in its mortgage
indenture and corporate charter to issue new first mortgage bonds and preferred
stock. The Company's coverage ratios are sufficiently high enough to permit, at
present interest levels, any foreseeable security sales. The amount of
securities which the Company will be permitted to issue in the future will
depend upon market conditions and other factors prevailing at that time.
II-232
STATEMENTS OF INCOME
For the Years Ended December 31, 1994, 1993, and 1992
Savannah Electric and Power Company 1994 Annual Report
=============================================================================================
1994 1993 1992
---------------------------------------------------------------------------------------------
(in thousands)
Operating Revenues (Notes 1, 3, and 6):
Revenues $ 205,339 $ 216,009 $ 196,256
Revenues from affiliates 6,446 2,433 1,505
---------------------------------------------------------------------------------------------
Total operating revenues 211,785 218,442 197,761
---------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
Fuel 18,555 24,976 14,162
Purchased power from non-affiliates 1,839 793 494
Purchased power from affiliates 55,822 56,274 56,492
Other (Note 2) 41,623 45,610 36,884
Maintenance 12,560 13,516 14,232
Depreciation and amortization (Notes 1 and 7) 17,854 16,467 16,829
Taxes other than income taxes 11,074 11,136 10,231
Federal and state income taxes (Notes 1 and 7) 16,289 15,436 14,566
---------------------------------------------------------------------------------------------
Total operating expenses 175,616 184,208 163,890
---------------------------------------------------------------------------------------------
Operating Income 36,169 34,234 33,871
Other Income (Expense):
Allowance for equity funds used during construction (Note 1) 831 958 446
Interest income 54 209 276
Other, net (Note 2) (1,032) (1,841) (1,450)
Income taxes applicable to other income (Notes 1 and 7) 864 1,117 758
---------------------------------------------------------------------------------------------
Income Before Interest Charges 36,886 34,677 33,901
---------------------------------------------------------------------------------------------
Interest Charges:
Interest on long-term debt 12,585 10,696 10,870
Allowance for debt funds used during construction (Note 1) (1,225) (699) (289)
Interest on notes payable 205 240 15
Amortization of debt discount, premium, and expense, net 550 535 427
Other interest charges 337 340 466
---------------------------------------------------------------------------------------------
Net interest charges 12,452 11,112 11,489
---------------------------------------------------------------------------------------------
Net Income 24,434 23,565 22,412
Dividends on Preferred Stock 2,324 2,106 1,900
---------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred Stock $ 22,110 $ 21,459 $ 20,512
=============================================================================================
The accompanying notes are an integral part of these statements.
II-233
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1994, 1993, and 1992
Savannah Electric and Power Company 1994 Annual Report
==============================================================================================
1994 1993 1992
----------------------------------------------------------------------------------------------
(in thousands)
Operating Activities:
Net income $ 24,434 $ 23,565 $ 22,412
Adjustments to reconcile net income to net
cash provided by operating activities --
Depreciation and amortization 19,353 17,482 17,757
Deferred income taxes and investment tax credits 1,625 607 5,947
Allowance for equity funds used during construction (831) (958) (446)
Other, net 826 2,853 (1,312)
Changes in certain current assets and liabilities --
Receivables, net 18,481 (16,839) (4,107)
Special deposits - - 350
Inventories 1,144 (3,947) 4,435
Payables (19,957) 18,742 351
Other (117) 3,282 2,083
----------------------------------------------------------------------------------------------
Net cash provided from operating activities 44,958 44,787 47,470
----------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (30,078) (72,858) (30,132)
Other (841) 1,676 (1,073)
-----------------------------------------------------------------------------------------------
Net cash used for investing activities (30,919) (71,182) (31,205)
-----------------------------------------------------------------------------------------------
Financing Activities and Capital Contributions:
Proceeds:
First mortgage bonds - 45,000 30,000
Preferred stock - 35,000 -
Pollution control bonds - 4,085 13,870
Other long-term debt 8,500 10,000 -
Retirements:
Preferred stock - (20,000) -
First mortgage bonds (5,065) - (38,750)
Pollution control bonds - (4,085) (14,550)
Other long-term debt (823) (10,356) (217)
Notes payable, net (500) (4,500) 7,500
Payment of preferred stock dividends (2,129) (2,222) (1,900)
Payment of common stock dividends (16,300) (21,000) (22,000)
Miscellaneous (74) (3,400) (3,985)
-----------------------------------------------------------------------------------------------
Net cash provided from (used for) financing activities (16,391) 28,522 (30,032)
-----------------------------------------------------------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents (2,352) 2,127 (13,767)
Cash and Cash Equivalents at Beginning of Year 3,915 1,788 15,555
-----------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 1,563 $ 3,915 $ 1,788
===============================================================================================
Supplemental Cash Flow Information:
Cash paid during the year for-
Interest (net of amount capitalized) $11,579 $10,712 $9,932
Income taxes 14,441 13,947 6,646
-----------------------------------------------------------------------------------------------
( ) Denotes use of cash.
The accompanying notes are an integral part of these statements.
II-234
BALANCE SHEETS
At December 31, 1994 and 1993
Savannah Electric and Power Company 1994 Annual Report
=================================================================================================
Assets 1994 1993
-------------------------------------------------------------------------------------------------
(in thousands)
Utility Plant:
Plant in service, at original cost (Notes 1, 4, 5, 7, and 9) $ 693,432 $ 622,521
Less accumulated provision for depreciation 267,590 251,565
-------------------------------------------------------------------------------------------------
425,842 370,956
Construction work in progress 5,930 49,797
-------------------------------------------------------------------------------------------------
Total 431,772 420,753
-------------------------------------------------------------------------------------------------
Other Property and Investments 1,790 1,793
-------------------------------------------------------------------------------------------------
Current Assets:
Cash and cash equivalents 1,563 3,915
Receivables-
Customer accounts receivable 17,581 18,551
Other accounts and notes receivable 216 790
Affiliated companies 177 12,924
Accumulated provision for uncollectible accounts (866) (762)
Fuel cost under recovery 3,113 7,112
Fossil fuel stock, at average cost 7,557 8,419
Materials and supplies, at average cost (Note 1) 9,076 9,358
Prepayments 7,446 4,849
-------------------------------------------------------------------------------------------------
Total 45,863 65,156
-------------------------------------------------------------------------------------------------
Deferred Charges:
Deferred charges related to income taxes (Note 7) 23,521 24,890
Premium on reacquired debt, being amortized 3,295 3,792
Cash surrender value of life insurance for deferred compensation plan 7,028 5,907
Miscellaneous 5,036 4,896
-------------------------------------------------------------------------------------------------
Total 38,880 39,485
-------------------------------------------------------------------------------------------------
Total Assets $ 518,305 $ 527,187
=================================================================================================
The accompanying notes are an integral part of these statements.
II-235
BALANCE SHEETS
At December 31, 1994 and 1993
Savannah Electric and Power Company 1994 Annual Report
================================================================================================
Capitalization and Liabilities 1994 1993
------------------------------------------------------------------------------------------------
(in thousands)
Capitalization (See accompanying statements):
Common stock equity $ 161,581 $ 154,269
Preferred stock 35,000 35,000
Long-term debt 155,922 151,338
-------------------------------------------------------------------------------------------------
Total 352,503 340,607
-------------------------------------------------------------------------------------------------
Current Liabilities:
Amount of securities due within one year (Note 10) 2,579 4,499
Notes payable (Note 5) 2,500 3,000
Accounts payable-
Affiliated companies 5,162 6,041
Other 3,829 24,401
Customer deposits 4,698 4,714
Taxes accrued-
Federal and state income 272 342
Other 861 1,187
Interest accrued 6,830 6,730
Vacation pay accrued 1,823 1,638
Pensions accrued (Note 2) 4,783 5,718
Miscellaneous 3,499 2,985
-------------------------------------------------------------------------------------------------
Total 36,836 61,255
-------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes (Note 7) 70,786 66,947
Accumulated deferred investment tax credits (Note 7) 14,637 15,301
Deferred credits related to income taxes (Note 7) 25,487 26,173
Deferred compensation plans 6,807 6,117
Deferred under-funded accrued benefit obligation (Note 2) 3,022 5,855
Postretirement benefits 3,808 2,074
Miscellaneous 4,419 2,858
-------------------------------------------------------------------------------------------------
Total 128,966 125,325
-------------------------------------------------------------------------------------------------
Commitments and Contingent Matters (Notes 1, 2, 4, 5, and 9)
Total Capitalization and Liabilities $ 518,305 $ 527,187
=================================================================================================
The accompanying notes are an integral part of these statements.
II-236
STATEMENTS OF CAPITALIZATION
At December 31, 1994 and 1993
Savannah Electric and Power Company 1994 Annual Report
==================================================================================================
1994 1993 1994 1993
--------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
Common Stock Equity (Notes 2 and 11):
Common stock, par value $5 per share --
Authorized -- 16,000,000 shares
Outstanding -- 10,844,635 shares in
1994 and 1993 $ 54,223 $ 54,223
Paid-in capital 8,688 8,688
Additional minimum liability
for under-funded pension obligations (546) (2,121)
Retained Earnings 99,216 93,479
--------------------------------------------------------------------------------------------------
Total common stock equity 161,581 154,269 45.8 % 45.3 %
--------------------------------------------------------------------------------------------------
Cumulative Preferred Stock (Note 8):
$25 par value --
Authorized -- 2,200,000 shares
6.64% Series -- Outstanding -- 1,400,000 shares 35,000 35,000
-------------------------------------------------------------------------------------------------
Total (annual dividend requirement -- $2,324,000) 35,000 35,000 9.9 10.3
-------------------------------------------------------------------------------------------------
Long-Term Debt (Note 9):
First mortgage bonds --
Maturity Interest Rates
-------- --------------
April 1, 1994 4 5/8% - 3,715
July 1, 2003 6 3/8% 20,000 20,000
October 1, 2019 9 1/4% 28,950 30,000
July 1, 2021 9 3/8% 29,700 30,000
July 1, 2022 8.30% 30,000 30,000
July 1, 2023 7.40% 25,000 25,000
--------------------------------------------------------------------------------------------------
Total first mortgage bonds 133,650 138,715
Pollution control obligations (Note 9) 17,955 17,955
Other long-term debt (Note 9) 9,988 2,311
Unamortized debt premium (discount), net (3,092) (3,144)
--------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
requirement -- $12,859,000) 158,501 155,837
Less amount due within one year (Note 10) 2,579 4,499
--------------------------------------------------------------------------------------------------
Long-term debt excluding amount due within one year 155,922 151,338 44.3 44.4
--------------------------------------------------------------------------------------------------
Total Capitalization $ 352,503 $ 340,607 100.0% 100.0%
==================================================================================================
The accompanying notes are an integral part of these statements.
II-237
STATEMENTS OF RETAINED EARNINGS
For the Years Ended December 31, 1994, 1993, and 1992
Savannah Electric and Power Company 1994 Annual Report
=======================================================================================
1994 1993 1992
---------------------------------------------------------------------------------------
(in thousands)
Balance at Beginning of Period $ 93,479 $ 95,155 $ 96,643
Net income after dividends on preferred stock 22,110 21,459 20,512
Cash dividends on common stock (16,300) (21,000) (22,000)
Preferred stock transactions, net (73) (2,135) -
---------------------------------------------------------------------------------------
Balance at End of Period (Note 11) $ 99,216 $ 93,479 $ 95,155
=======================================================================================
STATEMENTS OF PAID-IN CAPITAL
For the Years Ended December 31, 1994, 1993, and 1992
=========================================================================================
1994 1993 1992
-----------------------------------------------------------------------------------------
(in thousands)
Balance at Beginning of Period $ 8,688 $ 8,688 $ 8,665
Contributions to capital by parent company - - 23
-----------------------------------------------------------------------------------------
Balance at End of Period $ 8,688 $ 8,688 $ 8,688
=========================================================================================
The accompanying notes are an integral part of these statements.
II-238
NOTES TO FINANCIAL STATEMENTS
Savannah Electric and Power Company 1994 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Savannah Electric and Power Company is a wholly owned subsidiary of The Southern
Company, which is the parent company of five operating companies, a system
service company, Southern Communications Services (Southern Communications),
Southern Electric International (Southern Electric), Southern Nuclear Operating
Company (Southern Nuclear), and The Southern Development and Investment Group
(SDIG). 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, beginning in mid-1995, will provide digital wireless
communications services -- over the 800-megahertz frequency band -- to The
Southern Company's subsidiaries and also will market these services to the
public within the Southeast. Southern Electric designs, builds, owns, and
operates power production facilities and provides a broad range of technical
services to industrial companies and utilities in the United States and a number
of international markets. Southern Nuclear provides services to The Southern
Company's nuclear power plants. SDIG 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
also is subject to regulation by the FERC and the Georgia Public Service
Commission (GPSC). The Company follows generally accepted accounting principles
and complies with the accounting policies and practices prescribed by the GPSC.
Certain prior years' data presented in the financial statements have been
reclassified to conform with current year presentation.
Regulatory Assets and Liabilities
The Company is subject to the provisions of 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:
===============================================================
1994 1993
--------------------
(in thousands)
Deferred income taxes $23,521 $24,890
Premium on reacquired debt 3,295 3,792
Deferred income tax credits (25,487) (26,173)
---------------------------------------------------------------
Total $ 1,329 $ 2,509
===============================================================
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 to their fair value.
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 purchased power costs. Revenues are adjusted for differences between
recoverable fuel and demand-side management program 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 1994, uncollectible
accounts continued to average less than 1 percent of revenues.
II-239
NOTES (continued)
Savannah Electric and Power Company 1994 Annual Report
Depreciation and Amortization
Depreciation of the original cost of depreciable utility plant in service is
provided primarily by using composite straight-line rates, which approximated
2.9 percent in 1994, 2.9 percent in 1993, and 3.2 percent in 1992. The decrease
in rates following 1992 reflects the Company's implementation of new
depreciation rates approved by the GPSC. These new rates provide for a timely
recovery of the investments in the Company's depreciable properties.
When property subject to depreciation is retired or otherwise disposed of
in the normal course of business, its cost -- together with the cost of removal,
less salvage -- is charged to the accumulated provision for depreciation. Minor
items of property included in the original cost of the plant are retired when
the related property unit is retired.
Income Taxes
The Company, which is included in the consolidated federal income tax return
filed by The Southern Company, provides deferred income taxes for all
significant income tax temporary differences. Investment tax credits utilized
are deferred and amortized to income over the average lives of the related
property.
Effective January 1, 1993, the Company adopted FASB Statement No. 109,
Accounting for Income Taxes. Statement No. 109 required, among other things,
conversion to the liability method of accounting for accumulated deferred income
taxes. See Note 7 for additional information about Statement No. 109.
Allowance for Funds Used During Construction (AFUDC)
AFUDC represents the estimated debt and equity costs of capital funds that are
necessary to finance the construction of new facilities. While cash is not
realized currently from such allowance, it increases the revenue requirement
over the service life of the plant through a higher rate base and higher
depreciation expense. The composite rates used by the Company to calculate AFUDC
were 8.04 percent in 1994, 8.77 percent in 1993, and 11.27 percent in 1992.
Utility Plant
Utility plant is stated at original cost, which includes: materials; labor;
minor items of property; appropriate administrative and general costs;
payroll-related costs such as taxes, pensions, and other benefits; and the
estimated cost of funds used during construction. The cost of maintenance,
repairs, and replacement of minor items of property is charged to maintenance
expense. The cost of replacements of property (exclusive of minor items of
property) is charged to utility plant.
Cash and Cash Equivalents
For purposes of the Statements of Cash Flows, temporary cash investments are
considered cash equivalents. Temporary cash investments are securities with
original maturities of 90 days or less.
Financial Instruments
In accordance with FASB Statement No. 107, Disclosure About Fair Value of
Financial Instruments, the Company's only financial instrument that the carrying
amount did not approximate fair value at December 31 was as follows:
================================================================
Long-Term Debt
-----------------------
Carrying Fair
Year Amount Value
---- -----------------------
(in millions)
1994 $157 $153
1993 154 164
================================================================
The fair value for long-term debt was based on either closing market prices
or closing prices of comparable instruments.
Materials and Supplies
Generally, materials and supplies include the cost of transmission,
distribution, and generating plant materials. Materials are charged to inventory
when purchased and then expensed or capitalized to plant, as appropriate, when
installed.
II-240
NOTES (continued)
Savannah Electric and Power Company 1994 Annual Report
2. RETIREMENT BENEFITS
Pension Plan
The Company has a defined benefit, trusteed, non-contributory pension plan that
covers substantially all regular employees. Benefits are based on the greater of
amounts resulting from two different formulas: years of service and final
average pay or years of service and a flat-dollar benefit. The Company uses the
"projected unit credit" actuarial method for funding purposes, subject to
limitations under federal income tax regulations. Amounts funded to the pension
trust are primarily invested in equity and fixed-income securities. FASB
Statement No. 87, Employers' Accounting for Pensions, requires use of the
"projected unit credit" actuarial method for financial reporting purposes.
Postretirement Benefits
The Company also provides certain medical care and life insurance benefits for
retired employees. Substantially all employees may become eligible for these
benefits when they retire. A qualified trust for medical benefits is funded to
the extent deductible under federal income tax regulations. Amounts funded are
primarily invested in debt and equity securities.
Effective January 1, 1993, the Company adopted FASB Statement No. 106,
Employers' Accounting for Postretirement Benefits Other Than Pensions, on a
prospective basis. Statement No. 106 requires that medical care and life
insurance benefits for retired employees be accounted for on an accrual basis
using a specified actuarial method, "benefit/years-of-service." The cost of
postretirement benefits is reflected in rates on a current basis.
Prior to 1993, consistent with regulatory treatment, the Company recognized
costs on a cash basis as payments were made. The total cost of such benefits
recognized by the Company in 1992 was $375 thousand.
Funded Status and Cost of Benefits
Shown in the following tables are actuarial results and assumptions for pension
and postretirement medical and life insurance benefits as computed under the
requirements of FASB Statement Nos. 87 and 106, respectively. The funded status
of the plans at December 31 was as follows:
==================================================================
Pension
-------------------
1994 1993
-------------------
(in thousands)
Actuarial present value of
benefit obligation:
Vested benefits $35,227 $35,818
Non-vested benefits 2,069 1,992
------------------------------------------------------------------
Accumulated benefit obligation 37,296 37,810
Additional amounts related to
projected salary increases 7,393 5,974
------------------------------------------------------------------
Projected benefit obligation 44,689 43,784
Less:
Fair value of plan assets 27,165 26,446
Unrecognized net loss 10,950 9,449
Unrecognized prior service cost 1,510 1,685
Unrecognized net transition
obligation 621 710
Adjustment required to
recognize additional
minimum liability 5,688 5,871
------------------------------------------------------------------
Accrued pension cost recognized
in the Balance Sheets $10,131 $11,365
===================================================================
The weighted average rates assumed in the actuarial calculations for the
pension plan were:
==================================================================
1994 1993 1992
------------------------------
Discount 8.00% 7.50% 8.00%
Annual salary increase 5.25 4.75 5.00
Long-term return on plan assets 9.00 9.25 9.25
===================================================================
In accordance with Statement No. 87, an additional liability related to
under-funded accumulated benefit obligations was reflected at December 31, 1994
and December 31, 1993. Corresponding net-of-tax balances of $0.5 million and
$2.1 million were recognized as separate components of Common Stock Equity in
the 1994 and 1993 Statements of Capitalization.
II-241
NOTES (continued)
Savannah Electric and Power Company 1994 Annual Report
================================================================
Postretirement
Medical
---------------------
1994 1993
---------------------
(in thousands)
Actuarial present value of
benefit obligation:
Retirees and dependents $ 8,480 $ 8,632
Employees eligible to retire 825 898
Other employees 6,840 6,489
-----------------------------------------------------------------
Accumulated benefit obligation 16,145 16,019
Less:
Fair value of plan assets 393 -
Unrecognized net loss 3,106 4,124
Unrecognized transition
obligation 9,817 10,362
-----------------------------------------------------------------
Accrued liability recognized in the
Balance Sheets $ 2,829 $ 1,533
=================================================================
Postretirement Life
----------------------
1994 1993
----------------------
(in thousands)
Actuarial present value of
benefit obligation:
Retirees and dependents $2,514 $2,536
Employees eligible to retire 59 -
Other employees 1,645 1,577
-------------------------------------------------------------------
Accumulated benefit obligation 4,218 4,113
Less:
Fair value of plan assets - -
Unrecognized net loss 91 262
Unrecognized transition
obligation 3,204 3,382
-------------------------------------------------------------------
Accrued liability recognized in the
Balance Sheets $ 923 $ 469
===================================================================
The weighted average rates assumed in the actuarial calculations for the
postretirement medical and life plans were:
=======================================================
1994 1993
------------------
Discount 8.00% 7.50%
Annual salary increase 5.50 5.00
Long-term return on plan assets 8.50 8.50
=======================================================
An additional assumption used in measuring the accumulated postretirement
medical benefit obligation was a weighted average medical care cost trend rate
of 10.5 percent for 1994, decreasing gradually to 6.0 percent through the year
2000 and remaining at that level thereafter. An annual increase in the assumed
medical care cost trend rate of 1 percent would increase the accumulated medical
benefit obligation at December 31, 1994, by $2.3 million and the aggregate of
the service and interest cost components of the net retiree medical cost by $0.3
million.
Components of the plans' net costs are shown below:
===================================================================
Pension
---------------------------
1994 1993 1992
---------------------------
(in thousands)
Benefits earned during the year $ 1,192 $1,188 $1,053
Interest cost on projected
benefit obligation 3,279 2,741 2,429
Actual (return) loss on plan assets 27 (2,199) (1,266)
Net amortization and deferral (1,474) 716 (227)
-------------------------------------------------------------------
Net pension cost $ 3,024 $2,446 $1,989
===================================================================
Of the above net pension amounts, $2.6 million in 1994, $2.0 million in
1993 and $1.7 million in 1992 were recorded in operating expenses, and the
remainder was recorded in construction and other accounts.
================================================================
Postretirement
Medical
------------------
1994 1993
------------------
(in thousands)
Benefits earned during the year $ 528 346
Interest cost on accumulated
benefit obligation 1,185 855
Amortization of transition obligation 545 545
Actual (return) loss on plan assets 6 -
Net amortization and deferral 111 -
----------------------------------------------------------------
Net postretirement cost $2,375 $1,746
================================================================
==================================================================
Postretirement Life
----------------------
1994 1993
----------------------
(in thousands)
Benefits earned during the year $104 $ 97
Interest cost on accumulated
benefit obligation 307 279
Amortization of transition obligation 178 178
------------------------------------------------------------------
Net postretirement cost $589 $554
==================================================================
II-242
NOTES (continued)
Savannah Electric and Power Company 1994 Annual Report
Of the above net postretirement medical and life insurance costs, $2.4
million in 1994 and $1.8 million in 1993 were charged to operating expenses, and
the remainder was recorded in construction and other accounts.
The Company has a supplemental retirement plan for certain executive
employees. The plan is unfunded and payable from the general funds of the
Company. The Company has purchased life insurance on participating executives,
and plans to use these policies to satisfy this obligation. Benefit costs
associated with this plan for 1994, 1993 and 1992 were $377 thousand, $980
thousand and $316 thousand, respectively. The 1993 benefit costs reflect a
one-time expense related to employees who were part of the work force reduction
program.
Work Force Reduction Program
In 1993, the Company incurred additional costs for a one-time charge related to
the implementation of a work force reduction program. In 1993, $4.5 million was
charged to operating expenses and $0.6 million was charged to other income
(expense).
3. REGULATORY MATTERS
In May 1992, the Company filed for, and subsequently received, GPSC approval to
implement new base rates designed to decrease base operating revenues by $2.8
million annually. The reduction included a base rate reduction of approximately
$2.5 million spread among all classes of customers, effective June 1992. An
additional $0.3 million reduction resulted from the implementation of an
experimental, time-of-use rate for certain commercial customers in August 1992.
4. CONSTRUCTION PROGRAM
The Company is engaged in a continuous construction program, currently estimated
to total $34 million in 1995, $27 million in 1996 and $26 million in 1997. The
estimates include AFUDC of $0.7 million in 1995 and 1996, and $0.6 million in
1997. The construction program is subject to periodic review and revision, and
actual construction costs may vary from the above estimates because of numerous
factors. These factors include: changes in business conditions; revised load
growth estimates; changes in environmental regulations; increasing cost of
labor, equipment and materials; and changes in cost of capital. The construction
of two combustion turbine peaking units totaling 160 megawatts was completed
during 1994. In addition, construction will continue related to transmission and
distribution facilities and the upgrading and extension of the useful lives of
generating plants.
5. FINANCING AND COMMITMENTS
General
To the extent possible, the Company's construction program is expected to be
financed from internal sources and from the issuance of additional long-term
debt and preferred stock and capital contributions from The Southern Company.
Should the Company be unable to obtain funds from these sources, the Company
would have to use short-term indebtedness or other alternative, and possibly
costlier, means of financing.
The amounts of long-term debt and preferred stock that can be issued in the
future will be contingent on market conditions, the maintenance of adequate
earnings levels, regulatory authorizations and other factors. See Management's
Discussion and Analysis for information regarding the Company's earnings
coverage requirements.
Bank Credit Arrangements
At the beginning of 1995, unused credit arrangements with five banks totaled $18
million and expire at various times during 1995 and 1996.
The Company's revolving credit arrangements of $20 million, of which $11.5
million remained unused as of December 31, 1994, expire in December 1996. These
agreements allow short-term borrowings to be converted into term loans, payable
in 12 equal quarterly installments, with the first installment due at the end of
II-243
NOTES (continued)
Savannah Electric and Power Company 1994 Annual Report
the first calendar quarter after the applicable termination date or at an
earlier date at the Company's option.
In connection with these credit arrangements, the Company agrees to pay
commitment fees based on the unused portions of the commitments.
Assets Subject to Lien
As amended and supplemented, the Company's Indenture of Mortgage, which secures
the first mortgage bonds issued by the Company, constitutes a direct first lien
on substantially all of the Company's fixed property and franchises.
Operating Leases
The Company has rental agreements with various terms and expiration dates.
Rental expenses totaled $1.5 million for 1994, 1993, and 1992. At December 31,
1994, estimated future minimum lease payments for non-cancelable operating
leases were as follows:
========================================================
Amounts
---------
(in millions)
1995 $1.1
1996 0.9
1997 0.7
1998 0.5
========================================================
6. LONG-TERM POWER SALES AGREEMENTS
The operating subsidiaries of The Southern Company, including the Company, have
entered into long-term contractual agreements for the sale of capacity and
energy to certain non-affiliated utilities located outside the system's service
area. 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 energy is generally sold
at cost under these agreements, revenues from capacity sales primarily affect
profitability. The Company's portion of capacity revenues has been as follows:
=================================================================
Unit Other
Year Power Long-Term Total
---- -----------------------------------
(in thousands)
1994 $3 $445 $448
1993 2 976 978
1992 3 534 537
=================================================================
7. 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, 1994, the tax-related regulatory assets and liabilities were $24
million and $25 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:
===============================================================
1994 1993 1992
----------------------------
(in thousands)
Total provision for income taxes
Federal --
Currently payable $11,736 $11,663 $ 6,630
Deferred - current year 2,106 1,906 7,407
- reversal of
prior years (755) (1,383) (2,347)
---------------------------------------------------------------
13,087 12,186 11,690
---------------------------------------------------------------
State --
Currently payable 2,064 2,049 1,231
Deferred - current year 188 119 1,079
- reversal of
prior years 86 (35) (192)
---------------------------------------------------------------
2,338 2,133 2,118
---------------------------------------------------------------
Total 15,425 14,319 13,808
Less income taxes charged
(credited) to other income (864) (1,117) (758)
---------------------------------------------------------------
Federal and state income taxes
charged to operations $16,289 $15,436 $14,566
===============================================================
II-244
NOTES (continued)
Savannah Electric and Power Company 1994 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:
================================================================
1994 1993
-----------------
(in thousands)
Deferred tax liabilities:
Accelerated depreciation $57,830 $53,585
Property basis differences 12,956 13,871
Other 2,449 3,922
----------------------------------------------------------------
Total 73,235 71,378
---------------------------------------------------------------
Deferred tax assets:
Pension and other benefits 4,816 4,237
Other 3,959 4,616
----------------------------------------------------------------
Total 8,775 8,853
----------------------------------------------------------------
Net deferred tax liabilities 64,460 62,525
Portions included in current assets, net 6,326 4,422
----------------------------------------------------------------
Accumulated deferred income taxes
in the Balance Sheets $70,786 $66,947
================================================================
Deferred investment tax credits are amortized over the life of the related
property with such amortization normally applied as a credit to reduce
depreciation in the Statements of Income. Credits amortized in this manner
amounted to $0.7 million in 1994, 1993, and 1992. At December 31, 1994, 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:
===============================================================
1994 1993 1992
-----------------------------
Statutory federal tax rate 35% 35% 34%
State income tax, net of
federal income tax benefit 4 4 4
Other - (1) -
---------------------------------------------------------------
Total effective tax rate 39% 38% 38%
===============================================================
The Southern Company and its subsidiaries file a consolidated federal
income tax return. Under a joint consolidated income tax agreement, each
company's current and deferred tax expense is computed on a stand-alone basis,
and consolidated tax savings are allocated to each company based on its ratio of
taxable income to total consolidated taxable income.
8. CUMULATIVE PREFERRED STOCK
In 1993, the Company issued 1,400,000 shares of 6.64% Series Preferred Stock
which has redemption provisions of $26.66 per share plus accrued dividends if on
or prior to November 1, 1998, and redemption provisions of $25 per share plus
accrued dividends thereafter.
In December 1993, the Company redeemed all 800,000 shares outstanding of
its 9.5% Series Preferred Stock at the prescribed redemption price of $26.57
plus accrued dividends. Cumulative preferred stock dividends are preferential to
the payment of dividends on common stock.
9. LONG-TERM DEBT
The Company's Indenture related to its First Mortgage Bonds is unlimited as to
the authorized amount of bonds which may be issued, provided that required
property additions, earnings and other provisions of such Indenture are met.
In April 1994, the Company retired the remaining outstanding principal
amount of $3.7 million of its 4 5/8 percent series First Mortgage Bonds due
April 1994.
The sinking fund requirements of first mortgage bonds were satisfied by
certification of property additions in 1993 and by cash redemption in 1994. See
Note 10 "Long-Term Debt Due Within One Year" for details.
Details of pollution control obligations and other long-term debt at
December 31 are as follows:
=================================================================
1994 1993
------------------
(in thousands)
Collateralized obligations incurred
in connection with the sale by public
authorities of tax-exempt pollution
control revenue bonds --
Variable rate (5.65% at 1/1/95)
due 2016 $ 4,085 $ 4,085
6 3/4% due 2022 13,870 13,870
-----------------------------------------------------------------
Total pollution control obligations $17,955 $17,955
-----------------------------------------------------------------
Capital lease obligations --
Combustion turbine equipment $ 980 $ 1,403
Transportation fleet 508 908
Notes Payable:
6.04% due 1995 3,500 -
6.035% due 1995 5,000 -
-----------------------------------------------------------------
Total other long-term debt $ 9,988 $ 2,311
=================================================================
II-245
NOTES (continued)
Savannah Electric and Power Company 1994 Annual Report
Sinking fund requirements and/or maturities through 1999 applicable to
long-term debt are as follows: $2.6 million in 1995; $0.2 million in 1996; $0.1
million in 1997; and no requirement is needed in 1998 and 1999.
Assets acquired under capital leases are recorded as utility plant in
service, and the related obligation is classified as other long-term debt.
Leases are capitalized at the net present value of the future lease payments.
However, for ratemaking purposes, these obligations are treated as operating
leases, and as such, lease payments are charged to expense as incurred.
The Company leases combustion turbine generating equipment under a
non-cancelable lease expiring in December 1995, with renewal options extending
until 2010. The Company also leases a portion of its transportation fleet. Under
the terms of these leases, the Company is responsible for taxes, insurance and
other expenses.
10. LONG-TERM DEBT DUE WITHIN ONE YEAR
A summary of the improvement fund/sinking fund requirements and scheduled
maturities and redemptions of long-term debt due within one year at December 31
is as follows:
=================================================================
1994 1993
--------------------
(in thousands)
Bond sinking fund requirements $1,350 $1,350
Less:
Portion to be satisfied by
certifying property additions - 1,350
-----------------------------------------------------------------
Cash sinking fund requirements 1,350 -
Other long-term debt maturities 1,229 4,499
-----------------------------------------------------------------
Total $2,579 $4,499
=================================================================
The first mortgage bond improvement (sinking) fund requirements amount to 1
percent of each outstanding series of bonds authenticated under the indentures
prior to January 1 of each year, other than those issued to collateralize
pollution control and other obligations. The requirements may be satisfied by
depositing cash or reacquiring bonds, or by pledging additional property equal
to 1 2/3 times the requirements.
11. COMMON STOCK DIVIDEND RESTRICTIONS
The Company's Charter and Indentures contain certain limitations on the payment
of cash dividends on preferred and common stocks. At December 31, 1994,
approximately $57 million of retained earnings was restricted against the
payment of cash dividends on common stock under the terms of the Mortgage
Indenture.
12. QUARTERLY FINANCIAL INFORMATION (Unaudited)
Summarized quarterly financial data for 1994 and 1993 are as follows (in
thousands):
==================================================================
Net Income After
Operating Operating Dividends on
Quarter Ended Revenue Income Preferred Stock
------------------------------------------------------------------
March 1994 $46,717 $ 7,130 $ 3,898
June 1994 56,377 9,555 6,051
September 1994 63,674 13,495 9,547
December 1994 45,017 5,989 2,614
March 1993 $42,873 $ 6,123 $ 3,019
June 1993 52,875 9,301 6,211
September 1993 74,420 13,326 10,214
December 1993 48,274 5,484 2,015
==================================================================
The Company's business is influenced by seasonal weather conditions and a
seasonal rate structure, among other factors.
II-246
SELECTED FINANCIAL AND OPERATING DATA
Savannah Electric and Power Company 1994 Annual Report
=============================================================================================
1994 1993 1992
---------------------------------------------------------------------------------------------
Operating Revenues (in thousands) $211,785 $218,442 $197,761
Net Income after Dividends
on Preferred and Preference Stocks (in thousands) $22,110 $21,459 $20,512
Cash Dividends on Common Stock (in thousands) $16,300 $21,000 $22,000
Return on Average Common Equity (percent) 14.00 13.73 12.89
Total Assets (in thousands) $518,305 $527,187 $352,175
Gross Property Additions (in thousands) $30,078 $72,858 $30,132
---------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $161,581 $154,269 $158,376
Preferred stock 35,000 35,000 20,000
Preferred and preference stock subject
to mandatory redemption - - -
Long-term debt 155,922 151,338 110,767
---------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $352,503 $340,607 $289,143
=============================================================================================
Capitalization Ratios (percent):
Common stock equity 45.8 45.3 54.8
Preferred and preference stock 9.9 10.3 6.9
Long-term debt 44.3 44.4 38.3
---------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0 100.0
=============================================================================================
First Mortgage Bonds (in thousands):
Issued - 45,000 30,000
Retired 5,065 - 38,750
Preferred and Preference Stock (in thousands):
Issued - 35,000 -
Retired - 20,000 -
---------------------------------------------------------------------------------------------
Security Ratings:
First Mortgage Bonds -
Moody's A1 A1 A1
Standard and Poor's A A A
Preferred Stock -
Moody's "a2" "a2" "a2"
Standard and Poor's A- A- A-
---------------------------------------------------------------------------------------------
Customers (year-end):
Residential 103,199 101,032 99,164
Commercial 13,015 12,702 12,416
Industrial 65 69 73
Other 1,007 957 940
---------------------------------------------------------------------------------------------
Total 117,286 114,760 112,593
=============================================================================================
Employees (year-end) 616 665 688
Note:
NR = Not Rated
II-247
SELECTED FINANCIAL AND OPERATING DATA
Savannah Electric and Power Company 1994 Annual Report
=============================================================================================
1991 1990 1989
---------------------------------------------------------------------------------------------
Operating Revenues (in thousands) $189,646 $205,635 $201,799
Net Income after Dividends
on Preferred and Preference Stocks (in thousands) $24,030 $26,254 $25,535
Cash Dividends on Common Stock (in thousands) $22,000 $22,000 $20,000
Return on Average Common Equity (percent) 15.13 16.85 16.88
Total Assets (in thousands) $352,505 $340,050 $349,887
Gross Property Additions (in thousands) $19,478 $20,086 $18,831
---------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $159,841 $157,811 $153,737
Preferred stock 20,000 20,000 22,300
Preferred and preference stock subject
to mandatory redemption - - 2,884
Long-term debt 119,280 112,377 117,522
---------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $299,121 $290,188 $296,443
=============================================================================================
Capitalization Ratios (percent):
Common stock equity 53.4 54.4 51.9
Preferred and preference stock 6.7 6.9 8.5
Long-term debt 39.9 38.7 39.6
---------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0 100.0
=============================================================================================
First Mortgage Bonds (in thousands):
Issued 30,000 - 30,000
Retired 22,500 9,135 18,275
Preferred and Preference Stock (in thousands):
Issued - - -
Retired - 5,374 6,591
---------------------------------------------------------------------------------------------
Security Ratings:
First Mortgage Bonds -
Moody's A1 A1 A1
Standard and Poor's A A A
Preferred Stock -
Moody's "a2" "a2" "a2"
Standard and Poor's A- A- A-
---------------------------------------------------------------------------------------------
Customers (year-end):
Residential 97,446 96,452 94,766
Commercial 12,153 12,045 12,298
Industrial 73 76 69
Other 897 867 856
---------------------------------------------------------------------------------------------
Total 110,569 109,440 107,989
=============================================================================================
Employees (year-end) 672 648 643
Note:
NR = Not Rated
II-248A
SELECTED FINANCIAL AND OPERATING DATA
Savannah Electric and Power Company 1994 Annual Report
=============================================================================================
1988 1987 1986
---------------------------------------------------------------------------------------------
Operating Revenues (in thousands) $182,440 $174,707 $174,847
Net Income after Dividends
on Preferred and Preference Stocks (in thousands) $24,272 $22,086 $20,452
Cash Dividends on Common Stock (in thousands) $11,700 $10,741 $9,353
Return on Average Common Equity (percent) 17.03 17.03 17.52
Total Assets (in thousands) $347,051 $340,109 $341,826
Gross Property Additions (in thousands) $23,254 $32,276 $26,800
---------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $148,883 $136,207 $123,133
Preferred stock 22,300 2,300 2,300
Preferred and preference stock subject
to mandatory redemption 3,075 9,665 10,256
Long-term debt 98,285 129,329 137,821
---------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $272,543 $277,501 $273,510
=============================================================================================
Capitalization Ratios (percent):
Common stock equity 54.6 49.1 45.0
Preferred and preference stock 9.3 4.3 4.6
Long-term debt 36.1 46.6 50.4
---------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0 100.0
=============================================================================================
First Mortgage Bonds (in thousands):
Issued - - 25,000
Retired 12,231 10,239 10,160
Preferred and Preference Stock (in thousands):
Issued 20,000 - -
Retired 553 588 610
---------------------------------------------------------------------------------------------
Security Ratings:
First Mortgage Bonds -
Moody's A1 A3 A3
Standard and Poor's A- A- A-
Preferred Stock -
Moody's "a2" NR NR
Standard and Poor's BBB+ BBB+ BBB+
---------------------------------------------------------------------------------------------
Customers (year-end):
Residential 93,486 92,094 89,951
Commercial 12,135 11,812 11,405
Industrial 69 67 67
Other 828 762 731
---------------------------------------------------------------------------------------------
Total 106,518 104,735 102,154
=============================================================================================
Employees (year-end) 655 655 658
Note:
NR = Not Rated
II-248B
SELECTED FINANCIAL AND OPERATING DATA
Savannah Electric and Power Company 1994 Annual Report
==================================================================================
1985 1984
----------------------------------------------------------------------------------
Operating Revenues (in thousands) $158,643 $148,721
Net Income after Dividends
on Preferred and Preference Stocks (in thousands) $15,279 $14,907
Cash Dividends on Common Stock (in thousands) $8,387 $8,010
Return on Average Common Equity (percent) 14.41 15.31
Total Assets (in thousands) $323,686 $323,318
Gross Property Additions (in thousands) $30,700 $29,724
----------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $110,385 $101,664
Preferred stock 2,300 2,300
Preferred and preference stock subject
to mandatory redemption 10,848 11,446
Long-term debt 128,850 136,709
----------------------------------------------------------------------------------
Total (excluding amounts due within one year) $252,383 $252,119
==================================================================================
Capitalization Ratios (percent):
Common stock equity 43.7 40.3
Preferred and preference stock 5.2 5.5
Long-term debt 51.1 54.2
----------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0
==================================================================================
First Mortgage Bonds (in thousands):
Issued 20,000 -
Retired 5,592 10,532
Preferred and Preference Stock (in thousands):
Issued - -
Retired 588 525
----------------------------------------------------------------------------------
Security Ratings:
First Mortgage Bonds -
Moody's A3 A3
Standard and Poor's A- BBB+
Preferred Stock -
Moody's NR NR
Standard and Poor's BBB+ BBB+
----------------------------------------------------------------------------------
Customers (year-end):
Residential 88,101 86,366
Commercial 10,985 10,659
Industrial 66 76
Other 699 637
----------------------------------------------------------------------------------
Total 99,851 97,738
==================================================================================
Employees (year-end) 653 632
Note:
NR = Not Rated
II-248C
SELECTED FINANCIAL AND OPERATING DATA (continued)
Savannah Electric and Power Company 1994 Annual Report
=============================================================================================
1994 1993 1992
---------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $89,195 $93,883 $82,670
Commercial 71,227 71,320 64,756
Industrial 32,906 36,180 33,171
Other 7,946 7,810 7,095
---------------------------------------------------------------------------------------------
Total retail 201,274 209,193 187,692
Sales for resale - non-affiliates 4,786 6,021 7,821
Sales for resale - affiliates 6,446 2,433 1,505
---------------------------------------------------------------------------------------------
Total revenues from sales of electricity 212,506 217,647 197,018
Other revenues (721) 795 743
---------------------------------------------------------------------------------------------
Total $211,785 $218,442 $197,761
=============================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 1,298,122 1,329,362 1,216,993
Commercial 1,045,831 1,015,935 953,840
Industrial 799,543 854,324 861,121
Other 119,593 115,969 110,270
---------------------------------------------------------------------------------------------
Total retail 3,263,089 3,315,590 3,142,224
Sales for resale - non-affiliates 201,716 247,203 367,066
Sales for resale - affiliates 93,001 75,384 37,632
---------------------------------------------------------------------------------------------
Total 3,557,806 3,638,177 3,546,922
=============================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 6.87 7.06 6.79
Commercial 6.81 7.02 6.79
Industrial 4.12 4.23 3.85
Total retail 6.17 6.31 5.97
Sale for resale 3.81 2.62 2.30
Total sales 5.97 5.98 5.55
Residential Average Annual Kilowatt-Hour Use Per Customer 12,686 13,269 12,369
Residential Average Annual Revenue Per Customer $871.68 $937.07 $840.23
Plant Nameplate Capacity Ratings (year-end) (megawatts) 788 628 628
Maximum Peak-Hour Demand (megawatts):
Winter 617 524 533
Summer 729 747 695
Annual Load Factor (percent) 54.3 54.1 55.0
Plant Availability - Fossil-Steam (percent) 81.0 90.2 89.1
---------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 18.6 21.5 12.0
Oil and gas 1.8 4.5 2.9
Purchased power -
From non-affiliates 1.5 0.9 1.0
From affiliates 78.1 73.1 84.1
---------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0
=============================================================================================
Total Fuel Economy Data:
BTU per net kilowatt-hour generated 11,786 11,515 12,547
Cost of fuel per million BTU (cents) 205.03 215.97 201.50
Average cost of fuel per net kilowatt-hour generated (cents) 2.42 2.49 2.53
=============================================================================================
II-249
SELECTED FINANCIAL AND OPERATING DATA (continued)
Savannah Electric and Power Company 1994 Annual Report
=============================================================================================
1991 1990 1989
---------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $80,541 $87,063 $85,113
Commercial 61,827 65,462 65,474
Industrial 30,492 30,237 28,304
Other 6,561 6,782 6,892
---------------------------------------------------------------------------------------------
Total retail 179,421 189,544 185,783
Sales for resale - non-affiliates 7,813 9,482 8,814
Sales for resale - affiliates 1,430 5,566 6,025
Total revenues from sales of electricity 188,664 204,592 200,622
Other revenues 982 1,043 1,177
---------------------------------------------------------------------------------------------
Total $189,646 $205,635 $201,799
=============================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 1,195,005 1,183,486 1,109,976
Commercial 925,757 892,931 839,756
Industrial 825,862 644,704 561,063
Other 106,683 103,539 101,164
---------------------------------------------------------------------------------------------
Total retail 3,053,307 2,824,660 2,611,959
Sales for resale - non-affiliates 372,085 441,090 437,943
Sales for resale - affiliates 32,581 294,042 303,142
---------------------------------------------------------------------------------------------
Total 3,457,973 3,559,792 3,353,044
=============================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 6.74 7.36 7.67
Commercial 6.68 7.33 7.80
Industrial 3.69 4.69 5.04
Total retail 5.88 6.71 7.11
Sale for resale 2.28 2.05 2.00
Total sales 5.46 5.75 5.98
Residential Average Annual Kilowatt-Hour Use Per Customer 12,323 12,339 11,781
Residential Average Annual Revenue Per Customer $830.54 $907.68 $903.37
Plant Nameplate Capacity Ratings (year-end) (megawatts) 605 605 605
Maximum Peak-Hour Demand (megawatts):
Winter 526 428 548
Summer 691 648 613
Annual Load Factor (percent) 54.1 53.2 52.4
Plant Availability - Fossil-Steam (percent) 76.9 89.6 94.7
---------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 16.3 52.8 63.5
Oil and gas 1.7 3.4 1.4
Purchased power -
From non-affiliates 0.4 0.8 1.5
From affiliates 81.6 43.0 33.6
---------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0
=============================================================================================
Total Fuel Economy Data:
BTU per net kilowatt-hour generated 10,917 10,741 10,611
Cost of fuel per million BTU (cents) 199.42 188.18 180.48
Average cost of fuel per net kilowatt-hour generated (cents) 2.18 2.02 1.92
=============================================================================================
II-250A
SELECTED FINANCIAL AND OPERATING DATA (continued)
Savannah Electric and Power Company 1994 Annual Report
=============================================================================================
1988 1987 1986
---------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $81,098 $79,785 $80,348
Commercial 62,640 60,285 59,547
Industrial 26,865 27,422 27,694
Other 6,557 6,315 6,300
---------------------------------------------------------------------------------------------
Total retail 177,160 173,807 173,889
Sales for resale - non-affiliates 808 - -
Sales for resale - affiliates 3,567 - -
---------------------------------------------------------------------------------------------
Total revenues from sales of electricity 181,535 173,807 173,889
Other revenues 905 900 958
---------------------------------------------------------------------------------------------
Total $182,440 $174,707 $174,847
=============================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 1,067,411 1,044,554 1,021,905
Commercial 806,687 775,643 746,133
Industrial 533,604 557,281 515,544
Other 97,072 94,949 92,471
---------------------------------------------------------------------------------------------
Total retail 2,504,774 2,472,427 2,376,053
Sales for resale - non-affiliates 24,168 - -
Sales for resale - affiliates 156,106 - -
---------------------------------------------------------------------------------------------
Total 2,685,048 2,472,427 2,376,053
=============================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 7.60 7.64 7.86
Commercial 7.77 7.77 7.98
Industrial 5.03 4.92 5.37
Total retail 7.07 7.03 7.32
Sale for resale 2.43 - -
Total sales 6.76 7.03 7.32
Residential Average Annual Kilowatt-Hour Use Per Customer 11,489 11,481 11,514
Residential Average Annual Revenue Per Customer $872.87 $876.95 $905.27
Plant Nameplate Capacity Ratings (year-end) (megawatts) 605 605 605
Maximum Peak-Hour Demand (megawatts):
Winter 471 414 464
Summer 574 562 565
Annual Load Factor (percent) 53.4 53.6 51.1
Plant Availability - Fossil-Steam (percent) 77.1 81.2 86.9
---------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 79.8 74.3 81.9
Oil and gas 5.4 4.4 6.8
Purchased power -
From non-affiliates 5.9 19.9 11.3
From affiliates 8.9 1.4 -
---------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0
=============================================================================================
Total Fuel Economy Data:
BTU per net kilowatt-hour generated 10,683 10,551 10,607
Cost of fuel per million BTU (cents) 178.31 176.10 186.30
Average cost of fuel per net kilowatt-hour generated (cents) 1.90 1.86 1.98
=============================================================================================
II-250B
SELECTED FINANCIAL AND OPERATING DATA (continued)
Savannah Electric and Power Company 1994 Annual Report
==================================================================================
1985 1984
----------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $70,377 $65,059
Commercial 53,696 50,538
Industrial 28,335 27,233
Other 5,823 5,505
----------------------------------------------------------------------------------
Total retail 158,231 148,335
Sales for resale - non-affiliates - -
Sales for resale - affiliates - -
----------------------------------------------------------------------------------
Total revenues from sales of electricity 158,231 148,335
Other revenues 412 386
----------------------------------------------------------------------------------
Total $158,643 $148,721
==================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 926,988 883,498
Commercial 694,168 668,309
Industrial 513,270 518,118
Other 87,238 84,798
----------------------------------------------------------------------------------
Total retail 2,221,664 2,154,723
Sales for resale - non-affiliates - -
Sales for resale - affiliates - -
----------------------------------------------------------------------------------
Total 2,221,664 2,154,723
==================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 7.59 7.36
Commercial 7.74 7.56
Industrial 5.52 5.26
Total retail 7.12 6.88
Sale for resale - -
Total sales 7.12 6.88
Residential Average Annual Kilowatt-Hour Use Per Customer 10,536 10,357
Residential Average Annual Revenue Per Customer $799.90 $762.67
Plant Nameplate Capacity Ratings (year-end) (megawatts) 605 605
Maximum Peak-Hour Demand (megawatts):
Winter 440 360
Summer 498 481
Annual Load Factor (percent) 54.7 54.1
Plant Availability - Fossil-Steam (percent) 92.0 86.1
----------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 87.5 91.8
Oil and gas 2.6 2.2
Purchased power -
From non-affiliates 9.9 6.0
From affiliates - -
----------------------------------------------------------------------------------
Total 100.0 100.0
==================================================================================
Total Fuel Economy Data:
BTU per net kilowatt-hour generated 10,581 10,498
Cost of fuel per million BTU (cents) 198.80 196.20
Average cost of fuel per net kilowatt-hour generated (cents) 2.10 2.06
==================================================================================
II-250C
STATEMENTS OF INCOME
Savannah Electric and Power Company
==========================================================================================================
For the Years Ended December 31, 1994 1993 1992
----------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Operating Revenues:
Revenues $ 205,339 $ 216,009 $ 196,256
Revenues from affiliates 6,446 2,433 1,505
----------------------------------------------------------------------------------------------------------
Total operating revenues 211,785 218,442 197,761
----------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
Fuel 18,555 24,976 14,162
Purchased power from non-affiliates 1,839 793 494
Purchased power from affiliates 55,822 56,274 56,492
Other 41,623 45,610 36,884
Maintenance 12,560 13,516 14,232
Depreciation and amortization 17,854 16,467 16,829
Taxes other than income taxes 11,074 11,136 10,231
Federal and state income taxes 16,289 15,436 14,566
----------------------------------------------------------------------------------------------------------
Total operating expenses 175,616 184,208 163,890
----------------------------------------------------------------------------------------------------------
Operating Income 36,169 34,234 33,871
Other Income (Expense):
Allowance for equity funds used during construction 831 958 446
Interest income 54 209 276
Other, net (1,032) (1,841) (1,450)
Income taxes applicable to other income 864 1,117 758
----------------------------------------------------------------------------------------------------------
Income Before Interest Charges 36,886 34,677 33,901
----------------------------------------------------------------------------------------------------------
Interest Charges:
Interest on long-term debt 12,585 10,696 10,870
Allowance for debt funds used during construction (1,225) (699) (289)
Interest on notes payable 205 240 15
Amortization of debt discount, premium, and expense, net 550 535 427
Other interest charges 337 340 466
----------------------------------------------------------------------------------------------------------
Net interest charges 12,452 11,112 11,489
----------------------------------------------------------------------------------------------------------
Income Before Cumulative Effect of a
Change in Method of Recording Revenues 24,434 23,565 22,412
Cumulative effect as of January 1, 1988, of accruing unbilled
revenues--less income taxes of $1,164(000) - - -
----------------------------------------------------------------------------------------------------------
Net Income 24,434 23,565 22,412
Dividends on Preferred and Preference Stock 2,324 2,106 1,900
----------------------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred and Preference Stock $ 22,110 $ 21,459 $ 20,512
==========================================================================================================
Pro Forma Net Income After Dividends on Preferred Stock
Assuming Change in Method of Recording
Revenues Was Applied Retroactively $ 22,110 $ 21,459 $ 20,512
II-251
STATEMENTS OF INCOME
Savannah Electric and Power Company
====================================================================================================================
For the Years Ended December 31, 1991 1990 1989 1988
--------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Operating Revenues:
Revenues $ 188,216 $200,069 $195,774 $178,873
Revenues from affiliates 1,430 5,566 6,025 3,567
--------------------------------------------------------------------------------------------------------------------
Total operating revenues 189,646 205,635 201,799 182,440
--------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
Fuel 14,415 42,630 44,224 46,578
Purchased power from non-affiliates 297 611 616 3,593
Purchased power from affiliates 49,007 34,648 26,361 6,586
Other 32,945 30,630 29,371 28,271
Maintenance 12,475 12,754 12,281 14,261
Depreciation and amortization 16,549 16,118 20,343 19,771
Taxes other than income taxes 10,122 9,798 9,152 9,209
Federal and state income taxes 16,195 17,611 17,571 14,017
--------------------------------------------------------------------------------------------------------------------
Total operating expenses 152,005 164,800 159,919 142,286
--------------------------------------------------------------------------------------------------------------------
Operating Income 37,641 40,835 41,880 40,154
Other Income (Expense):
Allowance for equity funds used during construction 170 193 - 273
Interest income 589 741 719 355
Other, net (879) (803) (672) (1,423)
Income taxes applicable to other income 722 187 192 459
--------------------------------------------------------------------------------------------------------------------
Income Before Interest Charges 38,243 41,153 42,119 39,818
--------------------------------------------------------------------------------------------------------------------
Interest Charges:
Interest on long-term debt 11,486 12,052 12,287 15,603
Allowance for debt funds used during construction (103) (194) (112) (330)
Interest on notes payable 25 116 402 230
Amortization of debt discount, premium, and expense, net 380 241 274 196
Other interest charges 525 665 1,313 336
--------------------------------------------------------------------------------------------------------------------
Net interest charges 12,313 12,880 14,164 16,035
--------------------------------------------------------------------------------------------------------------------
Income Before Cumulative Effect of a
Change in Method of Recording Revenues 25,930 28,273 27,955 23,783
Cumulative effect as of January 1, 1988, of accruing unbilled
revenues--less income taxes of $1,164(000) - - - 1,920
--------------------------------------------------------------------------------------------------------------------
Net Income 25,930 28,273 27,955 25,703
Dividends on Preferred and Preference Stock 1,900 2,019 2,420 1,431
--------------------------------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred and Preference Stock $ 24,030 $ 26,254 $ 25,535 $ 24,272
====================================================================================================================
Pro Forma Net Income After Dividends on Preferred Stock
Assuming Change in Method of Recording
Revenues Was Applied Retroactively $ 24,030 $ 26,254 $ 25,535 $ 22,352
II-252A
STATEMENTS OF INCOME
Savannah Electric and Power Company
====================================================================================================================
For the Years Ended December 31, 1987 1986 1985 1984
--------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Operating Revenues:
Revenues $ 174,707 $ 174,847 $ 158,643 $148,721
Revenues from affiliates - - - -
--------------------------------------------------------------------------------------------------------------------
Total operating revenues 174,707 174,847 158,643 148,721
--------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
Fuel 38,597 44,393 45,232 44,183
Purchased power from non-affiliates 11,453 6,069 7,577 3,810
Purchased power from affiliates 1,186 2,071 1,526 2,255
Other 25,642 24,114 20,292 18,424
Maintenance 13,629 12,591 12,029 11,195
Depreciation and amortization 18,152 16,443 15,798 14,104
Taxes other than income taxes 9,088 7,863 6,724 6,098
Federal and state income taxes 16,969 21,405 15,495 15,026
--------------------------------------------------------------------------------------------------------------------
Total operating expenses 134,716 134,949 124,673 115,095
--------------------------------------------------------------------------------------------------------------------
Operating Income 39,991 39,898 33,970 33,626
Other Income (Expense):
Allowance for equity funds used during construction 512 27 646 624
Interest income 925 924 943 1,200
Other, net (464) (553) (107) (173)
Income taxes applicable to other income (317) (217) (389) (548)
--------------------------------------------------------------------------------------------------------------------
Income Before Interest Charges 40,647 40,079 35,063 34,729
--------------------------------------------------------------------------------------------------------------------
Interest Charges:
Interest on long-term debt 17,127 17,415 18,089 18,237
Allowance for debt funds used during construction (459) (73) (725) (551)
Interest on notes payable 70 315 437 172
Amortization of debt discount, premium, and expense, net 237 234 302 241
Other interest charges 251 335 213 188
--------------------------------------------------------------------------------------------------------------------
Net interest charges 17,226 18,226 18,316 18,287
--------------------------------------------------------------------------------------------------------------------
Income Before Cumulative Effect of a
Change in Method of Recording Revenues 23,421 21,853 16,747 16,442
Cumulative effect as of January 1, 1988, of accruing unbilled
revenues--less income taxes of $1,164(000) - - - -
--------------------------------------------------------------------------------------------------------------------
Net Income 23,421 21,853 16,747 16,442
Dividends on Preferred and Preference Stock 1,335 1,401 1,468 1,535
--------------------------------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred and Preference Stock $ 22,086 $ 20,452 $ 15,279 $ 14,907
====================================================================================================================
Pro Forma Net Income After Dividends on Preferred Stock
Assuming Change in Method of Recording
Revenues Was Applied Retroactively $ 21,865 $ 20,606 $ 15,744 $ 14,665
II-252B
STATEMENTS OF CASH FLOWS
Savannah Electric and Power Company
==================================================================================================
For the Years Ended December 31, 1994 1993 1992
--------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Operating Activities:
Net income $ 24,434 $ 23,565 $ 22,412
Adjustments to reconcile net income to net
cash provided by operating activities --
Depreciation and amortization 19,353 17,482 17,757
Deferred income taxes, net 1,625 607 5,947
Deferred investment tax credits, net - - -
Allowance for equity funds used during construction (831) (958) (446)
Other, net 826 2,853 (1,312)
Changes in certain current assets and liabilities --
Receivables, net 18,481 (16,839) (4,107)
Special deposits - - 350
Inventories 1,144 (3,947) 4,435
Payables (19,957) 18,742 351
Other (117) 3,282 2,083
--------------------------------------------------------------------------------------------------
Net cash provided from operating activities 44,958 44,787 47,470
--------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (30,078) (72,858) (30,132)
Sales of property - - -
Other (841) 1,676 (1,073)
--------------------------------------------------------------------------------------------------
Net cash used for investing activities (30,919) (71,182) (31,205)
--------------------------------------------------------------------------------------------------
Financing Activities:
Proceeds:
Preferred stock - 35,000 -
First mortgage bonds - 45,000 30,000
Pollution control bonds - 4,085 13,870
Other long-term debt 8,500 10,000 -
Common Stock - - -
Retirements:
Preferred and preference stock - (20,000) -
First mortgage bonds (5,065) - (38,750)
Pollution control bonds - (4,085) (14,550)
Other long-term debt (823) (10,356) (217)
Notes payable, net (500) (4,500) 7,500
Payment of preferred and preference stock dividends (2,129) (2,222) (1,900)
Payment of common and class A stock dividends (16,300) (21,000) (22,000)
Miscellaneous (74) (3,400) (3,985)
--------------------------------------------------------------------------------------------------
Net cash provided from (used for) financing activities (16,391) 28,522 (30,032)
--------------------------------------------------------------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents (2,352) 2,127 (13,767)
Cash and Cash Equivalents at Beginning of Year 3,915 1,788 15,555
--------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 1,563 $ 3,915 $ 1,788
==================================================================================================
( ) Denotes use of cash.
II-253
STATEMENTS OF CASH FLOWS
Savannah Electric and Power Company
=============================================================================================================
For the Years Ended December 31, 1991 1990 1989 1988
-------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Operating Activities:
Net income $ 25,930 $ 28,273 $ 27,955 $ 25,703
Adjustments to reconcile net income to net
cash provided by operating activities --
Depreciation and amortization 17,501 16,995 21,310 20,592
Deferred income taxes, net 1,601 2,782 3,476 3,568
Deferred investment tax credits, net - - - -
Allowance for equity funds used during construction (170) (193) - (273)
Other, net (1,876) 511 (775) 718
Changes in certain current assets and liabilities --
Receivables, net 5,291 1,541 (6,949) (7,062)
Special deposits 1,348 185 2,708 (558)
Inventories (1,082) 1,246 (1,503) 3,063
Payables 568 (228) 1,086 (1,151)
Other 3,710 (319) 1,544 (1,684)
-------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities 52,821 50,793 48,852 42,916
-------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (19,478) (20,086) (18,831) (23,254)
Sales of property - - - -
Other 407 (120) 381 (4,042)
-------------------------------------------------------------------------------------------------------------
Net cash used for investing activities (19,071) (20,206) (18,450) (27,296)
-------------------------------------------------------------------------------------------------------------
Financing Activities:
Proceeds:
Preferred stock - - - 20,000
First mortgage bonds 30,000 - 30,000 -
Pollution control bonds - - - -
Other long-term debt - - - -
Common Stock - - - 403
Retirements:
Preferred and preference stock - (5,374) (6,591) (553)
First mortgage bonds (22,500) (9,135) (18,275) (12,231)
Pollution control bonds (515) (485) (455) (430)
Other long-term debt (275) (364) (7,656) (4,401)
Notes payable, net (1,500) 1,500 - -
Payment of preferred and preference stock dividends (1,900) (2,113) (2,318) (1,284)
Payment of common and class A stock dividends (22,000) (22,000) (20,000) (14,407)
Miscellaneous (477) 47 (1,071) (269)
-------------------------------------------------------------------------------------------------------------
Net cash provided from (used for) financing activities (19,167) (37,924) (26,366) (13,172)
-------------------------------------------------------------------------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents 14,583 (7,337) 4,036 2,448
Cash and Cash Equivalents at Beginning of Year 972 8,309 4,273 1,825
-------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 15,555 $ 972 $ 8,309 $ 4,273
=============================================================================================================
( ) Denotes use of cash.
II-254A
STATEMENTS OF CASH FLOWS
Savannah Electric and Power Company
==============================================================================================================
For the Years Ended December 31, 1987 1986 1985 1984
--------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Operating Activities:
Net income $ 23,421 $ 21,853 $ 16,747 $ 16,442
Adjustments to reconcile net income to net
cash provided by operating activities --
Depreciation and amortization 19,126 16,855 16,484 14,216
Deferred income taxes, net 925 4,443 3,034 3,104
Deferred investment tax credits, net (5) 489 3,084 2,043
Allowance for equity funds used during construction (512) (27) (646) (624)
Other, net (1,016) 474 (1,730) 35
Changes in certain current assets and liabilities --
Receivables, net 1,360 1,456 (1,122) 180
Special deposits (587) (53) (916) (27)
Inventories (503) 663 5,563 (7,006)
Payables (78) (1,750) 2,135 1,637
Other (757) 1,916 2 521
--------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities 41,374 46,319 42,635 30,521
--------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (32,276) (26,800) (30,700) (29,724)
Sales of property - - 1,145 193
Other 1,296 (824) 2,682 1,561
--------------------------------------------------------------------------------------------------------------
Net cash used for investing activities (30,980) (27,624) (26,873) (27,970)
--------------------------------------------------------------------------------------------------------------
Financing Activities:
Proceeds:
Preferred stock - - - -
First mortgage bonds - 25,000 20,000 -
Pollution control bonds - - - -
Other long-term debt - - - -
Common Stock 1,693 1,691 1,777 1,639
Retirements:
Preferred and preference stock (588) (610) (588) (525)
First mortgage bonds (10,239) (10,160) (5,592) (10,532)
Pollution control bonds (405) (380) (360) (335)
Other long-term debt (3,954) (3,075) (17,721) (2,965)
Notes payable, net - (4,500) (4,500) 9,000
Payment of preferred and preference stock dividends (1,351) (1,418) (1,485) (1,552)
Payment of common and class A stock dividends (10,383) (9,114) (8,347) (7,763)
Miscellaneous - (436) (383) -
--------------------------------------------------------------------------------------------------------------
Net cash provided from (used for) financing activities (25,227) (3,002) (17,199) (13,033)
--------------------------------------------------------------------------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents (14,833) 15,693 (1,437) (10,482)
Cash and Cash Equivalents at Beginning of Year 16,658 965 2,402 12,884
--------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 1,825 $ 16,658 $ 965 $ 2,402
==============================================================================================================
( ) Denotes use of cash.
II-254B
BALANCE SHEETS
Savannah Electric and Power Company
=================================================================================================
At December 31, 1994 1993 1992
-------------------------------------------------------------------------------------------------
(Thousands of Dollars)
ASSETS
Utility Plant:
Production-fossil $ 312,215 $ 257,708 $ 258,539
Transmission 100,956 99,791 93,182
Distribution 251,323 237,012 222,024
General 28,938 28,010 25,851
Construction work in progress 5,930 49,797 5,966
-------------------------------------------------------------------------------------------------
Total utility plant 699,362 672,318 605,562
Accumulated provision for depreciation 267,590 251,565 240,094
-------------------------------------------------------------------------------------------------
Total 431,772 420,753 365,468
Less property-related accumulated deferred income taxes - - 65,725
-------------------------------------------------------------------------------------------------
Total 431,772 420,753 299,743
-------------------------------------------------------------------------------------------------
Other Property and Investments 1,790 1,793 1,795
-------------------------------------------------------------------------------------------------
Current Assets:
Cash and cash equivalents 1,563 3,915 1,788
Receivables, net 12,328 27,714 14,480
Accrued unbilled revenues 4,780 3,789 3,401
Fuel cost under recovery 3,113 7,112 3,895
Fossil fuel stock, at average cost 7,557 8,419 4,895
Materials and supplies, at average cost 9,076 9,358 8,935
Prepayments 7,446 4,849 1,599
-------------------------------------------------------------------------------------------------
Total 45,863 65,156 38,993
-------------------------------------------------------------------------------------------------
Deferred Charges:
Deferred charges related to income taxes 23,521 24,890 -
Miscellaneous 15,359 14,595 11,644
-------------------------------------------------------------------------------------------------
Total 38,880 39,485 11,644
-------------------------------------------------------------------------------------------------
Total Assets $ 518,305 $ 527,187 $ 352,175
=================================================================================================
II-255
BALANCE SHEETS
Savannah Electric and Power Company
==========================================================================================================
At December 31, 1991 1990 1989 1988
----------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
ASSETS
Utility Plant:
Production-fossil $ 247,017 $246,278 $ 242,988 $241,833
Transmission 90,198 73,358 72,299 71,601
Distribution 212,576 217,913 204,611 192,335
General 24,283 22,990 22,482 21,686
Construction work in progress 4,211 1,354 2,880 1,684
----------------------------------------------------------------------------------------------------------
Total utility plant 578,285 561,893 545,260 529,139
Accumulated provision for depreciation 225,605 211,725 198,228 178,888
----------------------------------------------------------------------------------------------------------
Total 352,680 350,168 347,032 350,251
Less property-related accumulated deferred income taxes 62,737 58,106 54,418 51,487
----------------------------------------------------------------------------------------------------------
Total 289,943 292,062 292,614 298,764
----------------------------------------------------------------------------------------------------------
Other Property and Investments 39 39 49 49
----------------------------------------------------------------------------------------------------------
Current Assets:
Cash and cash equivalents 15,555 972 8,309 4,273
Receivables, net 14,549 14,450 14,300 15,714
Accrued unbilled revenues 3,252 3,831 4,501 3,889
Fuel cost under recovery - 5,662 6,881 1,838
Fossil fuel stock, at average cost 9,196 8,071 9,706 8,455
Materials and supplies, at average cost 9,069 9,112 8,723 8,471
Prepayments 4,544 1,492 585 1,240
----------------------------------------------------------------------------------------------------------
Total 56,165 43,590 53,005 43,880
----------------------------------------------------------------------------------------------------------
Deferred Charges:
Deferred charges related to income taxes - - - -
Miscellaneous 6,358 4,359 4,219 4,358
----------------------------------------------------------------------------------------------------------
Total 6,358 4,359 4,219 4,358
----------------------------------------------------------------------------------------------------------
Total Assets $ 352,505 $340,050 $ 349,887 $347,051
==========================================================================================================
II-256A
BALANCE SHEETS
Savannah Electric and Power Company
==========================================================================================================
At December 31, 1987 1986 1985 1984
----------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
ASSETS
Utility Plant:
Production-fossil $ 236,587 $232,316 $ 229,765 $215,908
Transmission 69,822 65,215 61,843 55,047
Distribution 177,163 160,346 147,563 136,807
General 17,513 14,838 13,153 10,585
Construction work in progress 7,214 5,270 1,915 10,609
----------------------------------------------------------------------------------------------------------
Total utility plant 508,299 477,985 454,239 428,956
Accumulated provision for depreciation 161,531 144,232 130,279 116,576
----------------------------------------------------------------------------------------------------------
Total 346,768 333,753 323,960 312,380
Less property-related accumulated deferred income taxes 49,255 46,496 41,026 32,859
----------------------------------------------------------------------------------------------------------
Total 297,513 287,257 282,934 279,521
----------------------------------------------------------------------------------------------------------
Other Property and Investments 49 39 39 52
----------------------------------------------------------------------------------------------------------
Current Assets:
Cash and cash equivalents 1,825 16,658 965 2,402
Receivables, net 14,419 13,806 14,472 12,350
Accrued unbilled revenues - - - -
Fuel cost under recovery - 787 1,524 1,609
Fossil fuel stock, at average cost 12,359 12,642 13,615 19,554
Materials and supplies, at average cost 7,630 6,844 6,534 6,157
Prepayments 2,786 978 383 117
----------------------------------------------------------------------------------------------------------
Total 39,019 51,715 37,493 42,189
----------------------------------------------------------------------------------------------------------
Deferred Charges:
Deferred charges related to income taxes - - - -
Miscellaneous 4,127 2,815 3,220 1,556
----------------------------------------------------------------------------------------------------------
Total 4,127 2,815 3,220 1,556
----------------------------------------------------------------------------------------------------------
Total Assets $ 340,708 $341,826 $ 323,686 $323,318
==========================================================================================================
II-256B
BALANCE SHEETS
Savannah Electric and Power Company
================================================================================================
At December 31, 1994 1993 1992
------------------------------------------------------------------------------------------------
(Thousands of Dollars)
>
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock $ 54,223 $ 54,223 $ 54,223
Paid-in capital 8,688 8,688 8,688
Additional minimum liability
for under-funded pension obligations (546) (2,121) -
Retained Earnings 99,216 93,479 95,465
------------------------------------------------------------------------------------------------
Total common equity 161,581 154,269 158,376
Preferred stock 35,000 35,000 20,000
Preferred and preference stock subject to mandatory redemption - - -
Long-term debt 155,922 151,338 110,767
------------------------------------------------------------------------------------------------
Total (excluding amount due within one year) 352,503 340,607 289,143
------------------------------------------------------------------------------------------------
Current Liabilities:
Notes payable to banks 2,500 3,000 7,500
Preferred and preference stock due within one year - - -
Long-term debt due within one year 2,579 4,499 1,319
Accounts payable 8,991 30,442 11,179
Customer deposits 4,698 4,714 4,541
Fuel cost over recovery - - -
Taxes accrued 1,133 1,529 3,016
Interest accrued 6,830 6,730 5,733
Vacation pay accrued 1,823 1,638 1,790
Miscellaneous 8,282 8,703 5,025
------------------------------------------------------------------------------------------------
Total 36,836 61,255 40,103
------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 70,786 66,947 -
Accumulated deferred investment tax credits 14,637 15,301 15,964
Deferred credits related to income taxes 25,487 26,173 -
Deferred under-funded accrued benefit obligation 3,022 5,855 -
Miscellaneous 15,034 11,049 6,965
------------------------------------------------------------------------------------------------
Total 128,966 125,325 22,929
------------------------------------------------------------------------------------------------
Total Capitalization and Liabilities $ 518,305 $527,187 $ 352,175
================================================================================================
II-257
BALANCE SHEETS
Savannah Electric and Power Company
==========================================================================================================
At December 31, 1991 1990 1989 1988
----------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock $ 54,223 $ 54,223 $ 54,223 $ 54,223
Paid-in capital 8,665 8,665 8,665 8,665
Additional minimum liability
for under-funded pension obligations - - - -
Retained Earnings 96,953 94,923 90,849 85,995
----------------------------------------------------------------------------------------------------------
Total common equity 159,841 157,811 153,737 148,883
Preferred stock 20,000 20,000 22,300 22,300
Preferred and preference stock subject to mandatory redemption - - 2,884 3,075
Long-term debt 119,280 112,377 117,522 98,285
----------------------------------------------------------------------------------------------------------
Total (excluding amount due within one year) 299,121 290,188 296,443 272,543
----------------------------------------------------------------------------------------------------------
Current Liabilities:
Notes payable to banks - 1,500 - -
Preferred and preference stock due within one year - - 190 6,590
Long-term debt due within one year 2,442 2,358 7,091 23,217
Accounts payable 10,176 8,786 9,078 7,950
Customer deposits 4,528 4,472 4,296 3,983
Fuel cost over recovery 1,603 - - -
Taxes accrued 724 1,387 1,749 1,899
Interest accrued 4,657 3,415 4,287 4,154
Vacation pay accrued 1,672 1,604 1,477 1,412
Miscellaneous 4,823 3,398 2,880 1,705
----------------------------------------------------------------------------------------------------------
Total 30,625 26,920 31,048 50,910
----------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes - - - -
Accumulated deferred investment tax credits 16,628 17,292 17,971 19,106
Deferred credits related to income taxes - - - -
Deferred under-funded accrued benefit obligation - - - -
Miscellaneous 6,131 5,650 4,425 4,492
---------------------------------------------------------------------------------------------------------
Total 22,759 22,942 22,396 23,598
----------------------------------------------------------------------------------------------------------
Total Capitalization and Liabilities $ 352,505 $340,050 $ 349,887 $347,051
==========================================================================================================
II-258A
BALANCE SHEETS
Savannah Electric and Power Company
==========================================================================================================
At December 31, 1987 1986 1985 1984
----------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock $ 54,131 $ 53,174 $ 52,332 $ 51,271
Paid-in capital 8,353 7,623 6,774 6,059
Additional minimum liability
for under-funded pension obligations - - - -
Retained Earnings 73,723 62,336 51,279 44,334
----------------------------------------------------------------------------------------------------------
Total common equity 136,207 123,133 110,385 101,664
Preferred stock 2,300 2,300 2,300 2,300
Preferred and preference stock subject to mandatory redemption 9,665 10,256 10,848 11,446
Long-term debt 129,329 137,821 128,850 136,709
----------------------------------------------------------------------------------------------------------
Total (excluding amount due within one year) 277,501 273,510 252,383 252,119
----------------------------------------------------------------------------------------------------------
Current Liabilities:
Notes payable to banks - - 4,500 9,000
Preferred and preference stock due within one year 553 550 568 558
Long-term debt due within one year 8,956 14,836 12,636 8,510
Accounts payable 9,427 10,329 12,584 9,956
Customer deposits 3,729 3,403 3,256 2,846
Fuel cost over recovery 599 - - -
Taxes accrued 3,713 4,834 3,595 8,663
Interest accrued 4,599 4,906 4,984 5,253
Vacation pay accrued 1,306 1,255 1,150 1,086
Miscellaneous 6,257 3,650 3,356 3,336
----------------------------------------------------------------------------------------------------------
Total 39,139 43,763 46,629 49,208
----------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes - - - -
Accumulated deferred investment tax credits 20,264 21,663 22,265 20,117
Deferred credits related to income taxes - - - -
Deferred under-funded accrued benefit obligation - - - -
Miscellaneous 3,804 2,890 2,409 1,874
----------------------------------------------------------------------------------------------------------
Total 24,068 24,553 24,674 21,991
----------------------------------------------------------------------------------------------------------
Total Capitalization and Liabilities $ 340,708 $341,826 $ 323,686 $323,318
==========================================================================================================
II-258B
SAVANNAH ELECTRIC AND POWER COMPANY
OUTSTANDING SECURITIES AT DECEMBER 31, 1994
First Mortgage Bonds
Amount Interest Amount
Series Issued Rate Outstanding Maturity
-------------------------------------------------------------
(Thousands) (Thousands)
1993 $ 20,000 6-3/8% $ 20,000 7/1/03
1989 30,000 9-1/4% 28,950 10/1/19
1991 30,000 9-3/8% 29,700 7/1/21
1992 30,000 8.30% 30,000 7/1/22
1993 25,000 7.40% 25,000 7/1/23
-------- --------
$135,000 $133,650
======== ========
Pollution Control Bonds
Amount Interest Amount
Series Issued Rate Outstanding Maturity
-------------------------------------------------------------
(Thousands) (Thousands)
1993 $ 4,085 Variable $ 4,085 1/1/16
1992 13,870 6-3/4% 13,870 2/1/22
-------- --------
$ 17,955 $ 17,955
======== ========
Preferred Stock
Shares Dividend Amount
Series Outstanding Rate Outstanding
-------------------------------------------------------------
(Thousands)
1993 1,400,000 6.64% $ 35,000
II-259
SAVANNAH ELECTRIC AND POWER COMPANY
SECURITIES RETIRED DURING 1994
First Mortgage Bonds
Principal Interest
Series Amount Rate
---------------------------------------------------------------------
(Thousands)
1964 $3,715 4-5/8%
1989 1,050 9-1/4%
1991 300 9-3/8%
------
$5,065
======
II-260
PART III
Items 10, 11, 12 and 13 for SOUTHERN are incorporated by reference to ELECTION
OF DIRECTORS in SOUTHERN's definitive Proxy Statement relating to the 1995
annual meeting of stockholders.
Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS
ALABAMA
(a)(1) Identification of directors of ALABAMA.
Elmer B. Harris (1)
President and Chief Executive Officer of ALABAMA
Age 55
Served as Director since 3-1-89
Bill M. Guthrie
Executive Vice President of ALABAMA
Age 61
Served as Director since 12-16-88
Whit Armstrong (2)
Age 47
Served as Director since 9-24-82
Philip E. Austin (2)
Age 53
Served as Director since 1-25-91
Margaret A. Carpenter (2)
Age 70
Served as Director since 2-26-93
A. W. Dahlberg (2)
Age 54
Served as Director since 4-22-94
Peter V. Gregerson, Sr. (2)
Age 66
Served as Director since 10-22-93
Crawford T. Johnson, III (2)
Age 70
Served as Director since 4-18-69
Carl E. Jones, Jr. (2)
Age 54
Served as Director since 4-22-88
Wallace D. Malone, Jr. (2)
Age 58
Served as Director since 6-22-90
William V. Muse (2)
Age 55
Served as Director since 2-26-93
John T. Porter (2)
Age 63
Served as Director since 10-22-93
Gerald H. Powell (2)
Age 68
Served as Director since 2-28-86
Robert D. Powers (2)
Age 45
Served as Director since 1-24-92
John W. Rouse (2)
Age 57
Served as Director since 4-22-88
William J. Rushton, III (2)
Age 65
Served as Director since 9-18-70
James H. Sanford (2)
Age 50
Served as Director since 8-1-83
John C. Webb, IV (2)
Age 52
Served as Director since 4-22-77
John W. Woods (2)
Age 63
Served as Director since 4-20-73
(1) Previously served as Director of ALABAMA from 1980 to 1985.
(2) No position other than Director.
Each of the above is currently a director of ALABAMA, serving a term running
from the last annual meeting of ALABAMA's stockholder (April 22, 1994) for one
year until the next annual meeting or until a successor is elected and
qualified.
III-1
There are no arrangements or understandings between any of the individuals
listed above and any other person pursuant to which he was or is to be selected
as a director or nominee, other than any arrangements or understandings with
directors or officers of ALABAMA acting solely in their capacities as such.
(b)(1) Identification of executive officers of ALABAMA.
Elmer B. Harris (1)
President, Chief Executive Officer and Director
Age 55
Served as Executive Officer since 3-1-89
Banks H. Farris
Executive Vice President
Age 60
Served as Executive Officer since 12-3-91
William B. Hutchins, III
Executive Vice President and Chief Financial Officer
Age 51
Served as Executive Officer since 12-3-91
Charles D. McCrary
Executive Vice President
Age 43
Served as Executive Officer since 1-1-91
T. Harold Jones
Senior Vice President
Age 64
Served as Executive Officer since 12-1-91
(1) Previously served as executive officer of ALABAMA from 1979 to 1985.
Each of the above is currently an executive officer of ALABAMA, serving a
term running from the last annual meeting of the directors (April 22, 1994) for
one year until the next annual meeting or until his successor is elected and
qualified.
There are no arrangements or understandings between any of the individuals
listed above and any other person pursuant to which he was or is to be selected
as an officer, other than any arrangements or understandings with officers of
ALABAMA acting solely in their capacities as such.
(c)(1) Identification of certain significant employees.
None.
(d)(1) Family relationships.
None.
(e)(1) Business experience.
Elmer B. Harris - Elected in 1989; Chief Executive Officer. He previously served
as Senior Executive Vice President of GEORGIA from 1986 to 1989. Director of
SOUTHERN and AmSouth Bancorporation.
Bill M. Guthrie - Elected in 1988; also served since 1991 as Chief Production
Officer of SOUTHERN system and Executive Vice President and Chief Production
Officer of SCS; Vice President of SOUTHERN, GULF, MISSISSIPPI and SAVANNAH and
Executive Vice President of GEORGIA. Responsible primarily for providing overall
management of materials management, fuel services, operating and planning
services, fossil, hydro and bulk power operations of the Southern electric
system.
Whit Armstrong - President, Chairman and Chief Executive Officer of The
Citizens Bank, Enterprise, Alabama. Also, President and Chairman of the Board of
Enterprise Capital Corporation, Inc.
Philip E. Austin - Chancellor, The University of Alabama System. Previously
President and Chancellor of Colorado State University.
Margaret A. Carpenter - President, Compos-it, Inc. (typographics),
Montgomery, Alabama.
A. W. Dahlberg - Chairman, President and Chief Executive Officer of
SOUTHERN effective March 1, 1995. He previously served as President of SOUTHERN
from 1994 to 1995 and President and Chief Executive Officer of GEORGIA from 1988
through 1993. Director of SOUTHERN, GEORGIA, Trust Company Bank, Trust Company
of Georgia, Protective Life Corporation and Equifax, Inc.
Peter V. Gregerson, Sr. - Chairman Emeritus of Gregerson's Foods, Inc. (retail
groceries), Gadsden, Alabama. Director of AmSouth Bank of Gadsden, Alabama.
III-2
Crawford T. Johnson, III - Chairman of Coca-Cola Bottling Company United,
Inc., Birmingham, Alabama. Director of Protective Life Corporation, AmSouth
Bancorporation and Russell Corporation.
Carl E. Jones, Jr. - Chairman and Chief Executive Officer of First Alabama
Bank, Mobile, Alabama.
Wallace D. Malone, Jr. - Chairman and Chief Executive Officer of SouthTrust
Corporation, bank holding company, Birmingham, Alabama.
William V. Muse - President and Chief Executive Officer of Auburn University. He
previously served as President of the University of Akron from 1984 to 1992.
John T. Porter - Pastor of Sixth Avenue Baptist Church, Birmingham,
Alabama. Director of Citizen Federal Bank.
Gerald H. Powell - President, Dixie Clay Company of Alabama, Inc.
(refractory clay producer), Jacksonville, Alabama.
Robert D. Powers - President, The Eufaula Agency, Inc. (real estate and
insurance), Eufaula, Alabama.
John W. Rouse - President and Chief Executive Officer of Southern Research
Institute (non-profit research institute), Birmingham, Alabama. Director of
Protective Life Corporation.
William J. Rushton, III - Chairman Emeritus of the Board, Protective Life
Corporation (insurance holding company), Birmingham, Alabama. Director of
SOUTHERN and AmSouth Bancorporation.
James H. Sanford - President, HOME Place Farms Inc. (diversified farmers
and ginners), Prattville, Alabama.
John C. Webb, IV - President, Webb Lumber Company, Inc. (wholesale lumber),
Demopolis, Alabama.
John W. Woods - Chairman and Chief Executive Officer, AmSouth
Bancorporation (multi-bank holding company), Birmingham, Alabama. Director of
Protective Life Corporation.
Banks H. Farris - Elected in 1991; responsible primarily for providing the
overall management of the Human Resources, Information Resources, Power Delivery
and Marketing Departments and the six geographic divisions. He previously served
as Senior Vice President from 1991 to 1994 and Vice President - Human Resources
from 1989 to 1991.
William B. Hutchins, III - Elected in 1991; Chief Financial Officer, responsible
primarily for providing the overall management of accounting and financial
planning activities. He previously served as Senior Vice President and Chief
Financial Officer from 1991 to 1994 and Vice President and Treasurer from 1983
to 1991.
Charles D. McCrary - Elected in 1991; responsible for the External Relations
Department, Operating Services and Corporate Services. He previously served as
Senior Vice President from 1991 to 1994 and Vice President of Administrative
Services - Nuclear of SCS from 1988 to 1991.
T. Harold Jones - Elected in 1991; responsible primarily for providing the
overall management of the Fossil Generation, Hydro Generation, Power Generation
Services and Fuels Departments. He previously served as Vice President - Fossil
Generation from 1986 to 1991.
(f)(1) Involvement in certain legal proceedings.
None.
III-3
GEORGIA
(a)(2) Identification of directors of GEORGIA.
H. Allen Franklin
President and Chief Executive Officer.
Age 50
Served as Director since 1-1-94.
Warren Y. Jobe
Executive Vice President, Treasurer and Chief Financial Officer.
Age 54
Served as Director since 8-1-82
Bennett A. Brown (1)
Age 65
Served as Director since 5-15-80
A. W. Dahlberg (1)
Age 54
Served as Director since 6-1-88
William A. Fickling, Jr. (1)
Age 62
Served as Director since 4-18-73
L. G. Hardman III (1)
Age 55
Served as Director since 6-25-79
James R. Lientz, Jr. (1)
Age 51
Served as Director since 7-1-93
William A. Parker, Jr. (1)
Age 67
Served as Director since 5-19-65
G. Joseph Prendergast (1)
Age 49
Served as Director since 1-20-93
Herman J. Russell (1)
Age 64
Served as Director since 5-18-88
Gloria M. Shatto (1)
Age 63
Served as Director since 2-20-80
William Jerry Vereen (1)
Age 54
Served as Director since 5-18-88
Carl Ware (1) (2)
Age 51
Served as Director since 2-15-95
Thomas R. Williams (1)
Age 66
Served as Director since 3-17-82
(1) No position other than Director.
(2) Previously served as Director of GEORGIA
from 1980 to 1991.
Each of the above is currently a director of GEORGIA, serving a term running
from the last annual meeting of GEORGIA's stockholder (May 18, 1994) for one
year until the next annual meeting or until a successor is elected and
qualified, except for Mr. Ware whose election was effective on the date
indicated.
There are no arrangements or understandings between any of the individuals
listed above and any other person pursuant to which he/she was or is to be
selected as a director or nominee, other than any arrangements or understandings
with directors or officers of GEORGIA acting solely in their capacities as such.
(b)(2) Identification of executive officers of GEORGIA.
H. Allen Franklin
President, Chief Executive Officer and Director
Age 50
Served as Executive Officer since 1-1-94
Warren Y. Jobe
Executive Vice President, Treasurer, Chief Financial Officer and Director
Age 54
Served as Executive Officer since 5-19-82
Dwight H. Evans
Executive Vice President - External Affairs
Age 46
Served as Executive Officer since 4-19-89
III-4
W. G. Hairston, III
Executive Vice President - Nuclear
Age 50
Served as Executive Officer since 6-1-93
Gene R. Hodges
Executive Vice President - Customer Operations
Age 56
Served as Executive Officer since 11-19-86
Wayne T. Dahlke
Senior Vice President - Power Delivery
Age 54
Served as Executive Officer since 4-19-89
James K. Davis
Senior Vice President - Corporate Relations
Age 54
Served as Executive Officer since 10-1-93
Robert H. Haubein
Senior Vice President - Fossil/Hydro Power
Age 55
Served as Executive Officer since 2-19-92
Gale E. Klappa
Senior Vice President - Marketing
Age 44
Served as Executive Officer since 2-19-92
Fred D. Williams
Senior Vice President - Bulk Power Markets
Age 50
Served as Executive Officer since 11-18-92
Each of the above is currently an executive officer of GEORGIA, serving a
term running from the last annual meeting of the directors (May 18, 1994) for
one year until the next annual meeting or until his successor is elected and
qualified.
There are no arrangements or understandings between any of the individuals
listed above and any other person pursuant to which he was or is to be selected
as an officer, other than any arrangements or understandings with officers of
GEORGIA acting solely in their capacities as such.
(c)(2) Identification of certain significant employees.
None.
(d)(2) Family relationships.
None.
(e)(2) Business experience.
H. Allen Franklin - President and Chief Executive Officer since January
1994. He previously served as President and Chief Executive Officer of SCS from
1988 through 1993. Director of SOUTHERN and SouthTrust Corporation.
Warren Y. Jobe - Executive Vice President and Chief Financial Officer since 1982
and Treasurer since 1992. Responsible for financial and accounting operations
and planning, internal auditing, procurement, corporate services, corporate
secretary and treasury operations.
Bennett A. Brown - Retired from serving as Chairman of the Board of
NationsBank on December 31, 1992. Previously Chairman of the Board and Chief
Executive Officer of C&S/Sovran Corporation. Director of Cousins Properties.
A. W. Dahlberg - Chairman, President and Chief Executive Officer of
SOUTHERN effective March 1, 1995. He previously served as President of SOUTHERN
from 1994 to 1995 and President and Chief Executive Officer of GEORGIA from 1988
through 1993. Director of SOUTHERN, ALABAMA, Trust Company Bank, Trust Company
of Georgia, Protective Life Corporation and Equifax, Inc.
William A. Fickling, Jr. - Co-Chairman of the Board and Chief Executive
Officer of Beech Street Corporation (provider of managed care services).
L. G. Hardman III - Chairman of the Board of First National Bank of
Commerce, Georgia and Chairman of the Board and Chief Executive Officer of First
Commerce Bancorp, Inc. Chairman of the Board, President and Treasurer of Harmony
Grove Mills, Inc. (real estate investments). Director of SOUTHERN.
James R. Lientz, Jr. - President of NationsBank of Georgia since 1993. He
previously served as President and Chief Executive Officer of former Citizens &
Southern Bank of South Carolina (now NationsBank) from 1990 to 1993.
III-5
William A. Parker, Jr. - Chairman of the Board, Seminole Investment Co.,
L.L.C. (private investments), Atlanta, Georgia. Director of SOUTHERN, Genuine
Parts Company, Life Insurance Company of Georgia, Atlantic Realty Company, ING
North America Insurance Company, Post Properties, Inc. and Haverty Furniture
Companies, Inc.
G. Joseph Prendergast - Chairman Wachovia Bank of Georgia, N.A. since April
1994. He previously served as President and Chief Executive Officer, Wachovia
Corporation of Georgia and Wachovia Bank of Georgia, N.A. from 1993 to 1994 and
from 1988 to 1993 as Executive Vice President of Wachovia Corporation and
President of Wachovia Corporate Services, Inc.
Herman J. Russell - Chairman of the Board and Chief Executive Officer, H.
J. Russell & Company (construction), Atlanta, Georgia. Chairman of the Board,
Citizens Trust Bank, and Citizens Bancshares Corporation Atlanta, Georgia.
Director of Wachovia Corporation.
Gloria M. Shatto - President, Berry College, Mount Berry, Georgia. Director
of SOUTHERN, Becton Dickinson & Company, Kmart Corporation and Texas
Instruments, Inc.
William Jerry Vereen - President, Treasurer and Chief Executive Officer of
Riverside Manufacturing Company (manufacture and sale of uniforms), Moultrie,
Georgia. Director of Gerber Scientific, Inc., Textile Clothing Technology Group
and Blue Cross/Blue Shield of Georgia.
Carl Ware - President, Africa Group, Coca-Cola International; Senior Vice
President, The Coca-Cola Co.
Thomas R. Williams - President of The Wales Group, Inc. (investments),
Atlanta, Georgia. Director of ConAgra, Inc., BellSouth Corporation, National
Life Insurance Company of Vermont, AppleSouth, Inc., American Software, Inc. and
The Fidelity Group of Funds.
Dwight H. Evans - Executive Vice President - External Affairs since 1989.
W. G. Hairston, III - Executive Vice President - Nuclear since 1993. Also,
he has served as President and Chief Operating Officer of Southern Nuclear since
May 1993 and Chief Executive Officer since December 1993. Executive Vice
President of Southern Nuclear from 1992 to 1993 and Senior Vice President of
Southern Nuclear from 1990 to 1992.
Gene R. Hodges - Executive Vice President - Customer Operations since 1992.
Senior Vice President - Region/Land Operations from 1990 to 1992.
Wayne T. Dahlke - Senior Vice President - Power Delivery since 1992. Senior
Vice President - Marketing from 1989 to 1992.
James K. Davis - Senior Vice President - Corporate Relations since 1993.
Vice President of Corporate Relations from 1988 to 1993.
Robert H. Haubein - Senior Vice President - Fossil/ Hydro Power since June 1994.
Senior Vice President - Administrative Services from 1992 to 1994 and Vice
President - Northern Region from 1990 to 1992.
Gale E. Klappa - Senior Vice President - Marketing since 1992. Vice
President - Public Relations of SCS from 1981 to 1992.
Fred D. Williams - Senior Vice President - Bulk Markets since 1992. Vice
President - Bulk Power Markets from 1984 to 1992.
(f)(2) Involvement in certain legal proceedings.
None.
III-6
GULF
(a)(3) Identification of directors of GULF.
Travis J. Bowden
President and Chief Executive Officer
Age 56
Served as Director since 2-1-94
Reed Bell, Sr., M.D. (1)
Age 68
Served as Director since 1-17-86
Paul J. DeNicola (1)
Age 46
Served as Director since 4-19-91
Fred C. Donovan (1)
Age 54
Served as Director since 1-18-91
W. D. Hull, Jr. (1)
Age 62
Served as Director since 10-14-83
C. W. Ruckel (1)
Age 67
Served as Director since 4-20-62
J. K. Tannehill (1)
Age 61
Served as Director since 7-19-85
(1) No position other than Director.
Each of the above is currently a director of GULF, serving a term running
from the last annual meeting of GULF's stockholder (June 28, 1994) for one year
until the next annual meeting or until a successor is elected and qualified.
There are no arrangements or understandings between any of the individuals
listed above and any other person pursuant to which he was or is to be selected
as a director or nominee, other than any arrangements or understandings with
directors or officers of GULF acting solely in their capacities as such.
(b)(3) Identification of executive officers of GULF.
Travis J. Bowden
President, Chief Executive Officer and Director
Age 56
Served as Executive Officer since 2-1-94
F. M. Fisher, Jr.
Vice President - Employee and External Relations
Age 46
Served as Executive Officer since 5-19-89
John E. Hodges, Jr.
Vice President - Customer Operations
Age 51
Served as Executive Officer since 5-19-89
G. Edison Holland, Jr. (1)
Vice President - Power Generation/ Transmission and Corporate Counsel
Age 42
Served as Executive Officer since 4-25-92
Earl B. Parsons, Jr. (2)
Vice President - Power Generation and Transmission
Age 56
Served as Executive Officer since 4-14-78
A. E. Scarbrough
Vice President - Finance
Age 58
Served as Executive Officer since 9-21-77
(1) Effective March 13, 1995.
(2) Resigned effective March 11, 1995, to assume the position of Senior
Vice President - Fossil and Hydro Generation at ALABAMA.
Each of the above is currently an executive officer of GULF, serving a term
running from the last annual meeting of the directors (July 22, 1994) for one
year until the next annual meeting or until his successor is elected and
qualified.
III-7
There are no arrangements or understandings between any of the individuals
listed above and any other person pursuant to which he was or is to be selected
as an officer, other than any arrangements or understandings with officers of
GULF acting solely in their capacities as such.
(c)(3) Identification of certain significant employees.
None.
(d)(3) Family relationships.
None.
(e)(3) Business experience.
Travis J. Bowden - Elected President effective February 1994 and, effective May
1994, Chief Executive Officer. He previously served as Executive Vice President
of ALABAMA from 1985 to 1994.
Reed Bell, Sr., M.D. - Medical Doctor and since 1989, employee of the State
of Florida. He serves as Medical Director of Children's Medical Services,
District 1. He previously served as Medical Director of the Escambia County
Public Health Unit until 1992.
Paul J. DeNicola - President and Chief Executive Officer of SCS effective
January 1994. He previously served as Executive Vice President of SCS from 1991
through 1993 and President and Chief Executive Officer of MISSISSIPPI from 1989
to 1991. Director of SOUTHERN, MISSISSIPPI and SAVANNAH.
Fred C. Donovan - President of Baskerville - Donovan, Inc., Pensacola,
Florida, an architectural and engineering firm. Director of Baptist Health Care,
Inc.
W. D. Hull, Jr. - Vice Chairman of the Sun Bank/West Florida, Panama City,
Florida. He previously served as President and Chief Executive Officer and
Director of the Sun Commercial Bank, Panama City, Florida from 1987 to 1992.
C. W. Ruckel - Chairman of the Board of The Vanguard Bank and Trust
Company, Valparaiso, Florida. President and owner of Ruckel Properties, Inc.,
Valparaiso, Florida.
J. K. Tannehill - President and Chief Executive Officer of Tannehill
International Industries, Lynn Haven, Florida. He previously served as President
and Chief Executive Officer of Stock Equipment Company, Chagrin Falls, Ohio,
until 1991. Director of Florida First Federal Savings Bank, Panama City,
Florida.
F. M. Fisher, Jr. - Elected Vice President - Employee and External
Relations in 1989.
John E. Hodges, Jr. - Elected Vice President - Customer Operations in 1989.
Director of Barnett Bank of West Florida, Pensacola, Florida.
G. Edison Holland, Jr. - Elected Vice President and Corporate Counsel in 1992
and Vice President - Power Generation/Transmission and Corporate Counsel in
March 1995; responsible for generation and transmission of electric energy, all
legal matters associated with GULF and serves as compliance officer. Also
serves, since 1982, as a partner in the law firm, Beggs & Lane.
Earl B. Parsons, Jr. - Elected Vice President - Power Generation and
Transmission in 1989; responsible for generation and transmission of electrical
energy.
A. E. Scarbrough - Elected Vice President - Finance in 1980; responsible
for all accounting and financial services of GULF.
(f)(3) Involvement in certain legal proceedings.
None.
III-8
MISSISSIPPI
(a)(4) Identification of directors of MISSISSIPPI.
David M. Ratcliffe
President and Chief Executive Officer
Age 46
Served as Director since 4-24-91
Paul J. DeNicola (1)
Age 46
Served as Director since 5-1-89
Edwin E. Downer (1)
Age 63
Served as Director since 4-24-84
Robert S. Gaddis (1)
Age 63
Served as Director since 1-21-86
Walter H. Hurt, III (1)
Age 59
Served as Director since 4-6-82
Aubrey K. Lucas (1)
Age 60
Served as Director since 4-24-84
Gerald J. St. Pe (1)
Age 55
Served as Director since 1-21-86
Dr. Philip J. Terrell (1)
Age 41
Served as Director since 2-22-95
N. Eugene Warr (1)
Age 59
Served as Director since 1-21-86
(1) No position other than Director.
Each of the above is currently a director of MISSISSIPPI, serving a term
running from the last annual meeting of MISSISSIPPI's stockholder (April 5,
1994) for one year until the next annual meeting or until a successor is elected
and qualified, except for Dr. Terrell whose election was effective on the date
indicated.
There are no arrangements or understandings between any of the individuals
listed above and any other person pursuant to which he or she was or is to be
selected as a director or nominee, other than any arrangements or understandings
with directors or officers of MISSISSIPPI acting solely in their capacities as
such.
(b)(4) Identification of executive officers of MISSISSIPPI.
David M. Ratcliffe (1)
President, Chief Executive Officer and Director
Age 46
Served as Executive Officer since 4-24-91
H. E. Blakeslee
Vice President - Customer Services and Marketing
Age 54
Served as Executive Officer since 1-25-84
F. D. Kuester
Vice President - Power Generation and Delivery
Age 44
Served as Executive Officer since 3-1-94
Don E. Mason
Vice President - External Affairs and Corporate Services
Age 53
Served as Executive Officer since 7-27-83
Michael W. Southern
Vice President, Secretary, Treasurer and
Chief Financial Officer
Age 42
Served as Executive Officer since 1-1-95
(1) Elected Senior Vice President of SOUTHERN in March 1995, however, Mr.
Ratcliffe will maintain his present position until his successor is elected.
Each of the above is currently an executive officer of MISSISSIPPI, serving
a term running from the last annual meeting of the directors (April 27, 1994)
for one year until the next annual meeting or until a successor is elected and
qualified, except for Mr. Southern whose election was effective on the date
indicated.
There are no arrangements or understandings between any of the individuals
listed above and any other person pursuant to which he was or is to be selected
as an officer, other than any arrangements or understandings with officers of
MISSISSIPPI acting solely in their capacities as such.
III-9
(c)(4) Identification of certain significant employees.
None.
(d)(4) Family relationships.
None.
(e)(4) Business experience.
David M. Ratcliffe - President and Chief Executive Officer since 1991. He
previously served as Executive Vice President of SCS from 1989 to 1991 and Vice
President of SCS from 1985 to 1989.
Paul J. DeNicola - President and Chief Executive Officer of SCS effective 1994.
Executive Vice President of SCS from 1991 through 1993. He previously served as
President and Chief Executive Officer of MISSISSIPPI from 1989 to 1991. Director
of SOUTHERN, SAVANNAH and GULF.
Edwin E. Downer - Business consultant specializing in economic analysis,
management controls and procedural studies since 1990. President and Chief
Executive Officer, Unifirst Bank for Savings, F.A., Midland Division, Meridian,
Mississippi from 1985 to 1990.
Robert S. Gaddis - President of the Trustmark National Bank - Laurel,
Mississippi.
Walter H. Hurt, III - President and Director of NPC Inc. (Investments).
Vicar, All Saints Church, Inverness, Mississippi, and St. Thomas Church,
Belzoni, Mississippi. Retired newspaper editor and publisher.
Aubrey K. Lucas - President of the University of Southern Mississippi,
Hattiesburg, Mississippi.
Gerald J. St. Pe - President of Ingalls Shipbuilding and Senior Vice
President of Litton Industries, Inc. since 1985. Director of Merchants and
Marine Bank, Pascagoula, Mississippi.
Dr. Philip J. Terrell - Superintendent of Pass Christian Public School
District and adjunct professor at William Carey College.
N. Eugene Warr - Retailer (Biloxi and Gulfport, Mississippi). Vice chairman
of the Board of SouthTrust Bank of Mississippi, formerly The Jefferson Bank,
Biloxi, Mississippi.
H. E. Blakeslee - Elected Vice President in 1984. Primarily responsible for
rate design, economic analysis and revenue forecasting, economic development,
marketing and district operations.
F. D. Kuester - Elected Vice President in 1994.
Primarily responsible for generating plants, environmental quality, fuel
services, power generation technical services, distribution, transmission,
system planning, bulk power contracts, system operations and control, system
protection and real estate. He previously served as Manager of Business and New
Project Design/Development of SCS from 1993 to 1994 and Vice President of SCS
from 1990 to 1993.
Don E. Mason - Elected Vice President in 1983. Primarily responsible for the
external affairs functions, including governmental and regulatory affairs,
corporate communications, security, materials and general services, as well as
the human resources function.
Michael W. Southern - Elected Vice President, Secretary, Treasurer and Chief
Financial Officer in 1995, responsible primarily for accounting, treasury,
finance, information resources and risk management. He previously served as
Director of Corporate Finance of SCS from 1994 to 1995 and Director of Financial
Planning of SCS from 1990 to 1994.
(f)(4) Involvement in certain legal proceedings.
None.
III-10
SAVANNAH
(a)(5) Identification of directors of SAVANNAH.
Arthur M. Gignilliat, Jr.
President and Chief Executive Officer
Age 62
Served as Director since 9-1-82
Helen Quattlebaum Artley (1)
Age 67
Served as Director since 5-17-77
Paul J. DeNicola (1)
Age 46
Served as Director since 3-14-91
Brian R. Foster (1)
Age 45
Served as Director since 5-16-89
Walter D. Gnann (1)
Age 59
Served as Director since 5-17-83
Robert B. Miller, III (1)
Age 49
Served as Director since 5-17-83
James M. Piette (1)
Age 70
Served as Director since 6-12-73
Arnold M. Tenenbaum (1)
Age 58
Served as Director since 5-17-77
Frederick F. Williams, Jr. (1)
Age 67
Served as Director since 7-2-75
(1) No Position other than Director.
Each of the above is currently a director of SAVANNAH, serving a term
running from the last annual meeting of SAVANNAH's stockholder (May 17, 1994)
for one year until the next annual meeting or until a successor is elected and
qualified.
There are no arrangements or understandings between any of the individuals
listed above and any other person pursuant to which he/she was or is to be
selected as a director or nominee, other than any arrangements or understandings
with directors or officers of SAVANNAH acting solely in their capacities as
such.
(b)(5) Identification of executive officers of SAVANNAH.
Arthur M. Gignilliat, Jr.
President, Chief Executive Officer and Director
Age 62
Served as Executive Officer since 2-15-72
W. Miles Greer
Vice President - Marketing and Customer Services
Age 51
Served as Executive Officer since 11-20-85
Larry M. Porter
Vice President - Operations
Age 50
Served as Executive Officer since 7-1-91
Kirby R. Willis
Vice President, Treasurer and Chief Financial Officer
Age 43
Served as Executive Officer since 1-1-94
Each of the above is currently an executive officer of SAVANNAH, serving a
term running from the last annual meeting of the directors (May 17, 1994) for
one year until the next annual meeting or until his successor is elected and
qualified.
There are no arrangements or understandings between any of the individuals
listed above and any other person pursuant to which he was or is to be selected
as an officer, other than any arrangements or understandings with officers of
SAVANNAH acting solely in their capacities as such.
(c)(5) Identification of certain significant employees.
None.
(d)(5) Family relationships.
None.
(e)(5) Business experience.
Arthur M. Gignilliat, Jr. - Elected President and Chief Executive Officer
in 1984. Director of Savannah Foods and Industries, Inc.
III-11
Helen Quattlebaum Artley - Homemaker and Civic Worker.
Paul J. DeNicola - President and Chief Executive Officer of SCS effective
January 1994. Executive Vice President of SCS from 1991 through 1993. He
previously served as President and Chief Executive Officer of MISSISSIPPI from
1989 to 1991. Director of SOUTHERN, GULF and MISSISSIPPI.
Brian R. Foster - President and Chief Executive Officer of NationsBank of
Georgia, N.A., in Savannah since 1988.
Walter D. Gnann - President of Walt's TV, Appliance and Furniture Co.,
Inc., Springfield, Georgia. Past Chairman of the Development Authority of
Effingham County, Georgia.
Robert B. Miller, III - President of American Builders of Savannah.
James M. Piette - Retired Vice Chairman, Board of Directors, Union Camp
Corporation.
Arnold M. Tenenbaum - President and Director of Chatham Steel Corporation.
Director of First Union National Bank of Georgia and Savannah Foods and
Industries, Inc.
Frederick F. Williams, Jr. - Retired Partner and Consultant, Hilb, Rogal
and Hamilton Employee Benefits, Incorporated (Insurance Brokers), formerly
Jones, Hill & Mercer.
W. Miles Greer - Vice President - Marketing and Customer Services effective
1994. Formerly served as Vice President - Economic Development and Corporate
Services from 1989 through 1993.
Larry M. Porter - Vice President - Operations since 1991. Responsible for
managing the areas of fuel procurement, power production, transmission and
distribution, engineering and system operation. Previously he served as
Assistant Plant Manager of GEORGIA's Plant Scherer from 1984 to 1991.
Kirby R. Willis - Vice President, Treasurer and Chief Financial Officer since
1994. Responsible for all financial activities, Information Resources, Human
Resources, Corporate Services, and Environmental Affairs and Safety. He
previously served as Treasurer, Controller and Assistant Secretary from 1991 to
1993 and Treasurer and Secretary from 1987 to 1991.
(f)(5) Involvement in certain legal proceedings.
None.
GEORGIA's Mr. Thomas R. Williams failed to file on a timely basis a single
report disclosing one transaction on Forms 4 and 5 as required by Section 16 of
the Securities Exchange Act of 1934. Mr. William G. Hairston, III also failed to
file on a timely basis a Form 3 as required by Section 16 of the Securities Act
of 1934.
III-12
ITEM 11. EXECUTIVE COMPENSATION
(a) Summary Compensation Tables. The following tables set forth
information concerning any Chief Executive Officer and the four most highly
compensated executive officers whose total annual salary and bonus exceeded
$100,000 during 1994 for each of the operating affiliates (ALABAMA, GEORGIA,
GULF, MISSISSIPPI and SAVANNAH).
Key terms used in this Item will have the following meanings:-
AME.........................................Above-market earnings on deferred compensation
ESP.........................................Employee Savings Plan
ESOP........................................Employee Stock Ownership Plan
SBP.........................................Supplemental Benefit Plan
ERISA.......................................Employee Retirement Income Security Act
ALABAMA
SUMMARY COMPENSATION TABLE
ANNUAL COMPENSATION LONG-TERM COMPENSATION
------------------- ----------------------
Number of
Securities Long-
Name Underlying Term
and Other Annual Stock Incentive All Other
Principal Compensation Options Payouts Compensation
Position Year Salary($) Bonus($) ($)1 (Shares) ($)2 ($)3
-----------------------------------------------------------------------------------------------------------------------
President,
Chief Executive 1994 436,280 96,711 13,882 31,441 236,642 24,467
Officer, 1993 418,818 117,630 23,469 26,892 198,131 39,388
Director 1992 397,499 96,615 9,161 30,036 147,278 24,435
Banks H. Farris 1994 203,508 38,828 52,567 8,331 41,134 9,864
Executive Vice 1993 176,041 17,642 24,222 6,302 28,394 27,418
President 1992 165,746 27,274 6,211 6,906 19,021 8,916
Charles D. McCrary 1994 189,718 35,459 4,254 7,767 38,195 10,260
Executive Vice 1993 163,832 16,103 16,612 5,874 24,928 26,713
President 1992 152,877 24,893 2,087 5,528 15,438 8,023
III-13
ALABAMA
SUMMARY COMPENSATION TABLE
(Continued)
ANNUAL COMPENSATION LONG-TERM COMPENSATION
------------------- ----------------------
Number of
Securities Long-
Name Underlying Term
and Other Annual Stock Incentive All Other
Principal Compensation Options Payouts Compensation
Position Year Salary($) Bonus($) ($)1 (Shares) ($)2 ($)3
--------------------------------------------------------------------------------------------------------------------------
William B.
Hutchins, III
Executive Vice
President, 1994 184,995 26,993 1,289 7,551 35,138 9,650
Chief Financial 1993 164,972 16,103 14,791 5,896 26,429 26,817
Officer 1992 156,520 24,893 973 5,652 17,347 8,307
T. Harold Jones 1994 177,367 22,994 1,573 7,101 35,052 8,986
Senior Vice 1993 170,266 11,400 4,032 6,074 27,350 14,093
President 1992 163,164 15,000 32,611 6,784 19,181 8,631
1 Tax reimbursement by ALABAMA and certain personal benefits, including membership fee of $44,014 for Mr. Farris in
1994 and membership fee of $28,402 for Mr. Jones in 1992.
2 Payouts made in 1993, 1994 and 1995 for the four-year performance periods ending December 31, 1992, 1993 and 1994,
respectively.
3 ALABAMA contributions to the ESP, ESOP, and non-pension related accruals under the SBP (ERISA excess plan under
which accruals are made to offset Internal Revenue Code imposed limitations under the ESP and ESOP), for the
following:-
Name ESP ESOP SBP
---- --- ---- ---
Elmer B. Harris $6,750 $1,789 $15,928
Banks H. Farris 6,750 1,686 1,428
Charles D. McCrary 6,750 1,549 1,961
William B. Hutchins, III 6,750 1,572 1,328
T. Harold Jones 6,750 1,405 831
III-14
GEORGIA
SUMMARY COMPENSATION TABLE
ANNUAL COMPENSATION LONG-TERM COMPENSATION
------------------- ----------------------
Number of
Securities Long-
Name Underlying Term
and Other Annual Stock Incentive All Other
Principal Compensation Options Payouts Compensation
Position Year Salary($) Bonus($) ($)1 (Shares) ($)2 ($)3
------------------------------------------------------------------------------------------------------------------------
H. Allen Franklin
President, 1994 415,954 87,763 30,078 31,386 203,201 100,201
Chief Executive 1993 365,000 73,584 16,438 23,408 140,650 37,298
Officer, Director 1992 328,198 84,096 2,704 19,366 90,200 17,669
William G.
Hairston, III 1994 287,831 44,521 3,225 15,725 81,662 14,593
Executive 1993 234,454 53,202 15,925 11,782 54,126 30,475
Vice President 1992 198,392 27,990 34,425 8,414 37,320 10,697
Dwight H. Evans 1994 215,887 35,459 2,318 8,610 56,635 11,812
Executive 1993 210,544 34,763 14,642 7,498 48,282 29,519
Vice President 1992 206,980 40,598 3,505 8,414 36,284 10,925
Warren Y. Jobe
Executive
Vice President,
Treasurer, 1994 215,809 27,579 2,744 8,610 56,635 11,736
Chief Financial 1993 210,200 27,038 15,645 7,480 48,282 29,258
Officer, Director 1992 209,249 30,521 2,566 8,434 37,320 11,535
Gene R. Hodges 1994 204,190 27,579 4,601 8,196 52,188 11,093
Executive 1993 206,727 4 28,228 14,903 6,878 35,285 30,629
Vice President 1992 177,966 27,666 2,471 7,212 29,367 9,600
1 Tax reimbursement by GEORGIA on certain personal benefits.
2 Payouts made in 1993, 1994 and 1995 for the four-year performance periods ending December 31, 1992,
1993 and 1994, respectively.
3 GEORGIA contributions to the ESP, ESOP, and non-pension related accruals under the SBP (ERISA excess plan
under which accruals are made to offset Internal Revenue Code imposed limitations under the ESP and ESOP) for
the following:-
Name ESP ESOP SBP
---- --- ---- ---
H. Allen Franklin $6,750 $1,789 $15,043
William G. Hairston, III 6,750 1,789 6,054
Dwight H. Evans 6,750 1,789 3,273
Warren Y. Jobe 6,750 1,789 3,197
Gene R. Hodges 6,750 1,789 2,554
Also included for Mr. Franklin is a relocation allowance of $76,619.
4 Mr. Hodges' 1993 salary included a retroactive pay adjustment of $15,717 to correct underpayment of his 1992 salary.
III-15
GULF
SUMMARY COMPENSATION TABLE
ANNUAL COMPENSATION LONG-TERM COMPENSATION
------------------- ----------------------
Number of
Securities Long-
Name Underlying Term
and Other Annual Stock Incentive All Other
Principal Compensation Options Payouts Compensation
Position Year Salary($) Bonus($) ($)1 (Shares) ($)2 ($)3
------------------------------------------------------------------------------------------------------------------------
Travis J. Bowden
President, 1994 308,682 42,849 39,642 15,134 86,730 58,109
Chief Executive 1993 257,089 23,161 16,118 12,238 61,524 31,271
Officer, Director 1992 244,139 35,804 1,636 13,604 44,345 13,550
Douglas L. McCrary4
President, 1994 152,353 14,300 1,793 - 102,364 8,707
Chief Executive 1993 310,701 40,856 3,639 14,812 104,719 19,854
Officer, Director 1992 299,960 42,307 1,719 16,702 80,942 16,386
G. Edison
Holland, Jr. 1994 172,092 21,352 1,512 6,893 18,888 9,307
Vice President, 1993 162,651 20,934 9,504 5,840 - 21,015
Corporate Counsel 1992 101,725 17,980 724 5,590 n/e5 -
Earl B. Parsons, Jr. 1994 164,787 21,012 1,513 - 25,889 9,113
Vice President 1993 160,089 19,129 9,572 - 22,072 25,430
1992 155,495 22,050 420 - 17,875 8,460
Arlan E. Scarbrough 1994 163,548 19,511 1,185 - 25,889 8,612
Vice President 1993 155,565 19,129 11,582 - 22,072 24,729
1992 147,418 23,173 185 - 17,060 7,891
John E. Hodges, Jr. 1994 156,831 21,352 1,999 5,455 37,776 8,733
Vice President 1993 147,144 20,934 9,726 4,578 32,206 24,327
1992 139,296 25,360 448 5,064 23,218 7,425
1 Tax reimbursement by GULF on certain personal benefits.
2 Payouts made in 1993, 1994 and 1995 for the four-year performance periods ending December 31, 1992,
1993 and 1994, respectively.
3 GULF contributions to the ESP, ESOP, and non-pension related accruals under the SBP (ERISA excess plan under
which accruals are made to offset Internal Revenue Code imposed limitations under the ESP and ESOP) for the following:-
Name ESP ESOP SBP
---- --- ---- ---
Travis J. Bowden $6,750 $1,789 $6,521
Douglas L. McCrary 5,422 1,709 1,576
G. Edison Holland, Jr. 6,750 1,572 985
Earl B. Parsons, Jr. 6,750 1,719 644
Arlan E. Scarbrough 6,750 1,711 151
John E. Hodges, Jr. 6,750 1,688 295
Also included for Mr. Bowden is a relocation allowance of $43,049.
4 Mr. McCrary retired effective May 1, 1994.
5 Employee and executive officer of GULF since April 25, 1992. Not eligible to
participate in the Long-Term Incentive Plan until January 1, 1993.
III-16
MISSISSIPPI
SUMMARY COMPENSATION TABLE
ANNUAL COMPENSATION LONG-TERM COMPENSATION
------------------- ----------------------
Number of
Securities Long-
Name Underlying Term
and Other Annual Stock Incentive All Other
Principal Compensation Options Payouts Compensation
Position Year Salary($) Bonus($) ($)1 (Shares) ($)2 ($)3
------------------------------------------------------------------------------------------------------------------------
David M. Ratcliffe
President, Chief 1994 240,291 61,989 2,581 13,137 100,336 13,349
Executive 1993 226,373 45,917 8,722 8,114 75,378 17,887
Officer, Director 1992 213,095 33,395 6,380 8,652 48,722 10,860
H. E. Blakeslee 1994 156,204 23,808 1,055 5,509 37,776 8,494
Vice President 1993 154,332 15,271 3,528 4,768 32,206 15,650
1992 151,176 15,558 507 5,284 23,728 7,756
Don E. Mason 1994 150,162 22,069 686 - 25,889 8,080
Vice President 1993 148,305 11,016 4,321 - 22,072 15,409
1992 146,153 9,951 1,352 - 17,060 7,505
Thomas A. Fanning4
Vice President,
Chief Financial 1994 130,471 27,189 352 - 20,432 7,075
Officer, Secretary, 1993 122,724 28,244 3,016 - 15,233 14,655
Treasurer 1992 89,089 15,574 16,539 - 10,085 18,364
Frederick D.
Kuester5 1994 127,590 16,481 1,781 - 16,588 19,121
Vice President 1993 - - - - - -
1992 - - - - - -
1 Tax reimbursement by MISSISSIPPI on certain personal benefits.
2 Payouts made in 1993, 1994 and 1995 for the four-year performance periods ending December 31, 1992,
1993 and 1994, respectively.
3 MISSISSIPPI contributions to the ESP, ESOP, and non-pension related accruals under the SBP (ERISA excess plan
under which accruals are made to offset Internal Revenue Code imposed limitations under the ESP and ESOP) for the following:-
Name ESP ESOP SBP
---- --- ---- ---
David M. Ratcliffe $6,750 $1,789 $4,810
H. E. Blakeslee 6,750 1,744 -
Don E. Mason 6,750 1,330 -
Thomas A. Fanning 5,949 1,126 -
Frederick D. Kuester 5,804 1,051 -
Also included for Mr. Kuester is a relocation allowance of $12,266.
4 Effective December 31, 1994, Mr. Fanning resigned to become a vice president of SCS.
5 Mr. Kuester named an executive officer effective March 28, 1994.
III-17
SAVANNAH
SUMMARY COMPENSATION TABLE
ANNUAL COMPENSATION LONG-TERM COMPENSATION
------------------- ----------------------
Number of
Securities Long-
Name Underlying Term
and Other Annual Stock Incentive All Other
Principal Compensation Options Payouts Compensation
Position Year Salary($) Bonus($) ($)1 (Shares) ($)2 ($)3
------------------------------------------------------------------------------------------------------------------------
Arthur M.
Gignilliat, Jr.
President, 1994 206,964 37,384 194 8,253 76,164 18,617
Chief Executive 1993 202,259 26,470 12,231 7,198 64,932 31,512
Officer, Director 1992 201,338 27,409 - 8,116 50,269 14,466
Larry M. Porter 1994 130,619 15,249 198 - 15,070 7,561
Vice President 1993 126,133 10,070 7,251 - 7,810 21,570
1992 122,274 11,621 4,818 - n/e4 6,142
W. Miles Greer 1994 122,153 14,050 198 - 14,527 7,642
Vice President 1993 117,766 10,337 7,458 - 12,202 21,881
1992 115,114 10,776 34 - 9,243 6,599
Kirby R. Willis5
Vice President, 1994 111,653 14,207 46 - 8,257 6,840
Chief Financial 1993 - - - - - -
Officer, Treasurer 1992 - - - - - -
1 Tax reimbursement by SAVANNAH on certain personal benefits.
2 Payouts made in 1993, 1994 and 1995 for the four-year performance periods ending December 31, 1992, 1993
and 1994, respectively.
3 SAVANNAH contributions to the ESP, under Section 401(k) of the Internal Revenue Code, ESOP, and AME for
the following:-
Name ESP ESOP AME
---- --- ---- ---
Arthur M. Gignilliat $6,750 $1,590 $10,277
Larry M. Porter 5,230 946 1,385
W. Miles Greer 5,144 1,003 1,495
Kirby R. Willis 4,590 793 1,457
4 Not eligible to participate in the Long-term Incentive Plan until January 1, 1992.
5 Mr. Willis was named an executive officer effective in 1994.
III-18
STOCK OPTION GRANTS IN 1994
(b) Stock Option Grants. The following table sets forth all stock option
grants to the named executive officers of each operating subsidiary during the
year ending December 31, 1994.
Individual Grants Grant Date Value
# of % of Total
Securities Options Exercise
Underlying Granted to or
Options Employees in Base Price Expiration Grant Date
Name Granted1 Fiscal Year2 ($/Sh)1 Date1 Present Value($)3
------------------------------------------------------------------------------------------------------------
ALABAMA
Elmer B. Harris 31,441 7.0% $18.8750 07/18/2004 80,175
Banks H. Farris 8,331 1.9% $18.8750 06/01/2003 21,244
Charles D. McCrary 7,767 1.7% $18.8750 07/18/2004 19,806
William B. Hutchins, III 7,551 1.7% $18.8750 07/18/2004 19,255
T. Harold Jones 7,101 1.6% $18.8750 04/01/1998 7,456
GEORGIA
H. Allen Franklin 31,386 7.0% $18.8750 07/18/2004 80,034
William G. Hairston, III 15,725 3.5% $18.8750 07/18/2004 40,099
Dwight H. Evans 8,610 1.9% $18.8750 07/18/2004 21,956
Warren Y. Jobe 8,610 1.9% $18.8750 07/18/2004 20,900
Gene R. Hodges 8,196 1.8% $18.8750 07/18/2004 21,956
GULF
Travis J. Bowden 15,134 3.4% $18.8750 07/18/2004 38,592
Douglas L. McCrary - - - - -
G. Edison Holland, Jr. 6,893 1.5% $18.8750 07/18/2004 17,577
Earl B. Parsons, Jr. - - - - -
A. E. Scarbrough - - - - -
John E. Hodges, Jr. 5,455 1.2% $18.8750 07/18/2004 13,910
See next page for footnotes.
III-19
STOCK OPTION GRANTS IN 1994
Individual Grants Grant Date Value
# of % of Total
Securities Options Exercise
Underlying Granted to or
Options Employees in Base Price Expiration Grant Date
Name Granted1 Fiscal Year2 ($/Sh)1 Date1 Present Value($)3
-----------------------------------------------------------------------------------------------------------
MISSISSIPPI
David M. Ratcliffe 13,137 2.9% $18.8750 07/18/2004 33,499
H. E. Blakeslee 5,509 1.2% $18.8750 07/18/2004 14,048
Don E. Mason - - - - -
Thomas A. Fanning - - - - -
Frederick D. Kuester - - - - -
SAVANNAH
Arthur M. Gignilliat, Jr. 8,253 1.8% $18.8750 09/03/2000 17,084
Larry M. Porter - - - - -
W. Miles Greer - - - - -
Kirby R.Willis - - - - -
-------------------------
1 Grants were made on July 18, 1994, and vest 25% per year on the anniversary
date of the grant. Grants fully vest upon termination incident to death,
disability, or retirement. The exercie price is the average of the high and low
fair market value of SOUTHERN's common stock on the date granted. In accordance
with the terms of the Executive Stock Plan, Mr. Farris' unexercised options
expire on June 1, 2003, three years after his normal retirement date; Mr. Jones'
unexercised options expire on April 1, 1998, three years after his normal
retirement date; and Mr. Gignilliat's unexercised options expire on September 3,
2000, three years after his normal retirement date. Mr. McCrary's unexercised
options at December 31, 1994 expire on May 1, 1997 three years after his May 1,
1994 retirement date.
2 A total of 446,443 stock options were granted in 1994 to
key executives participating in SOUTHERN's Executive Stock Plan.
3 Based on the Black-Scholes option valuation model. The actual value, if
any, an executive officer may realize ultimately depends on the market value of
SOUTHERN's common stock at a future date. This valuation is provided pursuant to
SEC disclosure rules and there is no assurance that the value realized will be
at or near the value estimated by the Black-Scholes model. Assumptions used to
calculate this value: price volatility - 16.79%; risk-free rate of return -
7.3%; dividend yield - 6.25%; and time to exercise - 10 years.
III-20
AGGREGATED STOCK OPTION EXERCISES IN 1994 AND YEAR-END OPTION VALUES
(c) Aggregated Stock Option Exercises. The following table sets forth
information concerning options exercised during the year ending December 31,
1994, by the named executive officers and the value of unexercised options held
by them as of December 31, 1994.
Number of
Securities Value of
Underlying Unexercised
Unexercised In-the-Money
Options at Options at
Fiscal Fiscal
Year-End (#) Year-End($)1
Shares Acquired Value Exercisable/ Exercisable/
Name on Exercise (#) Realized($)2 Unexercisable Unexercisable
--------------------------------------------------------------------------------------------------------------
ALABAMA
Elmer B. Harris - - 58,867/75,800 276,376/120,463
Banks H. Farris - - 5,028/16,511 6,582/15,954
Charles D. McCrary - - 4,232/14,937 5,269/14,007
William B. Hutchins, III - - 4,300/14,799 5,387/13,882
T. Harold Jones - - 4,910/15,049 6,466/14,454
GEORGIA
H. Allen Franklin - - 40,383/63,905 186,066/86,272
William G. Hairston, III 2,588 19,087 9,658/31,275 23,447/41,137
Dwight H. Evans - - 8,474/20,896 34,426/32,819
Warren Y. Jobe - - 9,416/21,062 41,270/33,885
Gene R. Hodges - - 7,627/19,143 31,287/29,527
GULF
Travis J. Bowden - - 24,019/34,057 108,558/48,103
Douglas. L. McCrary 48,152 241,274 14,812/0 0/0
G. Edison Holland, Jr. - - 4,255/14,068 5,328/13,082
Earl B. Parsons, Jr. - - - -
Arlan E. Scarbrough - - - -
John E. Hodges, Jr. - - 15,714/12,615 85,878/18,314
See next page for footnotes.
III-21
AGGREGATED STOCK OPTION EXERCISES IN 1994 AND YEAR-END OPTION VALUES
Number of
Securities Value of
Underlying Unexercised
Unexercised In-the-Money
Options at Options at
Fiscal Fiscal
Year-End (#) Year-End($)1
Shares Acquired Value Exercisable/ Exercisable/
Name on Exercise (#) Realized($)2 Unexercisable Unexercisable
-------------------------------------------------------------------------------------------------------------
MISSISSIPPI
David M. Ratcliffe - - 20,046/26,119 95,471/38,847
H. E. Blakeslee - - 6,812/13,371 26,162/21,355
Don E. Mason - - - -
Thomas A. Fanning - - - -
Frederick D. Kuester - - - -
SAVANNAH
Arthur M. Gignilliat, Jr. - - 26,133/20,236 140,184/32,571
Larry M. Porter - - - -
W. Miles Greer - - - -
Kirby R. Willis - - - -
1 This represents the excess of the fair market value of SOUTHERN's common stock
of $20.00 per share, as of December 31, 1994, above the exercise price of the
options. One column reports the "value" of options that are vested and therefore
could be exercised; the other "value" of options that are not vested and
therefore could not be exercised as of December 31, 1994.
2 The "Value Realized" is ordinary income, before taxes, and represents the amount
equal to the excess of the fair market value of the shares at the time of exercise over the exercise
price.
III-22
LONG-TERM INCENTIVE PLANS - AWARDS IN 1994
(d) Long-Term Incentive Plans. The following table sets forth the
long-term incentive plan awards made to the named executive officers for the
performance period January 1, 1994 through December 31, 1997.
Estimated Future Payouts under
Non-Stock Price-Based Plans
------------------------------
Number Performance or
of Other Period
Units Until Maturation Threshold Target Maximum
Name (#)1 or Payout ($)2 ($)2 ($)2
----------------------------------------------------------------------------------------------------------------
ALABAMA
Elmer B. Harris 269,311 4 years 134,656 269,311 538,622
Banks H. Farris 95,170 4 years 47,585 95,170 190,340
Charles D. McCrary 77,251 4 years 38,626 77,251 154,502
William B. Hutchins, III 70,570 4 years 35,285 70,570 141,140
T. Harold Jones 56,360 4 years 28,180 56,360 112,720
GEORGIA
H. Allen Franklin 305,573 4 years 152,787 305,573 611,146
William G. Hairston, III 157,500 4 years 78,750 157,500 315,000
Dwight H. Evans 77,251 4 years 38,626 77,251 154,502
Warren Y. Jobe 77,251 4 years 38,626 77,251 154,502
Gene R. Hodges 77,251 4 years 38,626 77,251 154,502
GULF
Travis J. Bowden 129,576 4 years 64,788 129,576 259,152
Douglas L. McCrary 149,598 4 years 74,799 149,598 299,196
G. Edison Holland, Jr. 56,360 4 years 28,180 56,360 112,720
Earl B. Parsons, Jr. 51,500 4 years 25,750 51,500 103,000
Arlan E. Scarbrough 51,500 4 years 25,750 51,500 103,000
John E. Hodges, Jr. 56,360 4 years 28,180 56,360 112,720
See next page for footnotes.
III-23
LONG-TERM INCENTIVE PLANS - AWARDS IN 1994
Estimated Future Payouts under
Non-Stock Price-Based Plans
------------------------------
Number Performance or
of Other Period
Units Until Maturation Threshold Target Maximum
Name (#)1 or Payout ($)2 ($)2 ($)2
-------------------------------------------------------------------------------------------------------------------
MISSISSIPPI
David M. Ratcliffe 127,038 4 years 63,519 127,038 254,076
H. E. Blakeslee 56,360 4 years 28,180 56,360 112,720
Don E. Mason 51,500 4 years 25,750 51,500 103,000
Thomas A. Fanning 40,298 4 years 20,149 40,298 80,596
Frederick D. Kuester 40,298 4 years 20,149 40,298 80,596
SAVANNAH
Arthur M. Gignilliat, Jr. 92,760 4 years 46,380 92,760 185,520
Larry M. Porter 40,298 4 years 20,149 40,298 80,596
W. Miles Greer 37,156 4 years 18,578 37,156 74,312
Kirby R. Willis 37,156 4 years 18,578 37,156 74,312
1 A performance unit is a method of assigning a dollar value to a performance
award opportunity. The actual number of units granted to a participant will be
based on an award percentage of an individual's base salary range control
mid-point at the beginning of the performance period.
2 The threshold, target and maximum value of a unit is $0.50, $1.00, and $2.00,
respectively, and can vary based on SOUTHERN's return on common equity relative
to a selected group of electric and gas utilities in the Southeastern United States.
If certain minimum performance relative to the selected group is not achieved, there
will be no payout; nor is there a payout if the current earnings of SOUTHERN are not
sufficient to fund the dividend rate paid in the last calendar year. All awards
are payable in cash at the end of the performance period.
III-24
DEFINED BENEFIT OR ACTUARIAL PLAN DISCLOSURE
(e)(1) Pension Plan Table. The following table sets forth the estimated
combined annual pension benefits under the pension and supplemental defined
benefit plans in effect during 1994 for ALABAMA, GEORGIA, GULF and MISSISSIPPI.
Employee compensation covered by the pension and supplemental benefit plans for
pension purposes is limited to the average of the highest three of the final 10
years' base salary and wages (reported under column titled "Salary" in the
Summary Compensation Tables on pages III-13 through III-18).
The amounts shown in the table were calculated according to the final
average pay formula and are based on a single life annuity without reduction for
joint and survivor annuities (although married employees are required to have
their pension benefits paid in one of various joint and survivor annuity forms,
unless the employee elects otherwise with the spouse's consent) or computation
of the Social Security offset which would apply in most cases. This offset
amounts to one-half of the estimated Social Security benefit (primary insurance
amount) in excess of $3,000 per year times the number of years of accredited
service, divided by the total possible years of accredited service to normal
retirement age.
Years of Accredited Service
Remuneration 15 20 25 30 35 40
------------ ------------------------------------------------------------------
$ 50,000 $ 12,750 $ 17,000 $ 21,250 $ 25,500 $ 29,750 $ 34,000
$100,000 25,500 34,000 42,500 51,000 59,500 68,000
$300,000 76,500 102,000 127,500 153,000 178,500 204,000
$500,000 127,500 170,000 212,500 255,000 297,500 340,000
$700,000 178,500 238,000 297,500 357,000 416,500 476,000
$950,000 242,250 323,000 403,750 484,500 565,250 646,000
As of December 31, 1994, the applicable compensation levels and years of
accredited service are presented in the following tables:
ALABAMA
Compensation
Name Level Years of Service
---- ----- ----------------
Elmer B. Harris $421,620 36
Banks H. Farris 184,860 35
Charles D. McCrary 171,852 20
Williams B. Hutchins, III 171,396 24
T. Harold Jones 171,408 42
III-25
GEORGIA
Compensation
Name Level Years of Service
---- ----- ----------------
H. Allen Franklin $385,716 23
William G. Hairston, III 259,932 26
Dwight H. Evans 210,600 25
Warren Y. Jobe 210,588 23
Gene R. Hodges 191,616 30
GULF
Compensation
Name Level Years of Service
---- ----- ----------------
Travis J. Bowden $263,832 181
G. Edison Holland, Jr. 169,356 121
Earl B. Parsons, Jr. 161,100 33
Arlan E. Scarbrough 157,104 31
John E. Hodges, Jr. 149,604 28
MISSISSIPPI
Compensation
Name Level Years of Service
---- ----- ----------------
David M. Ratcliffe $228,432 22
H. E. Blakeslee 154,224 28
Don E. Mason 148,500 28
Thomas A. Fanning 125,820 13
Frederick D. Kuester 127,992 22
SAVANNAH has in effect a qualified, trusteed, noncontributory, defined
benefit pension plan which provides pension benefits to employees upon
retirement at the normal retirement age after designated periods of accredited
service and at a specified compensation level. The plan provides pension
benefits under a formula which includes each participant's years of service with
the Southern system and average annual earnings of the highest three of the
final ten years of service with the Southern system preceding retirement. Plan
benefits are reduced by a portion of the benefits participants are entitled to
receive under Social Security. The plan provides for reduced early retirement
benefits at age 55 and a pension for the surviving spouse equal to one-half of
the deceased retiree's pension.
The following table sets forth the estimated annual pension benefits
under the pension plan in effect during 1994 which are payable by SAVANNAH to
employees upon retirement at the normal retirement age after designated periods
of accredited service and at a specified compensation level.
-----------------------------------
1 The number of accredited years of service includes ten years credited to both
Mr. Bowden and Mr. Holland pursuant to individual supplemental pension
agreements.
III-26
Average Annual Salary Annual Benefits Exclusive of Social Security1
for Last 36 Months of Years of Service
Employment 15 25 35
------------------------ -- -- --
$ 90,000 $22,505 $ 37,508 $ 52,511
$120,000 30,006 50,010 70,014
$150,000 37,508 62,513 87,518
$180,000 45,009 75,015 105,021
$210,000 52,511 87,518 122,525
$250,000 62,513 104,188 145,863
As of December 31, 1994, the applicable compensation levels and years of
accredited service are presented in the following table:-
SAVANNAH
Compensation
Name Level Years of Service
---- ----- ----------------
Arthur M. Gignilliat $182,625 36
Larry M. Porter 115,500 17
W. Miles Greer 110,685 10
Kirby R. Willis 93,300 20
(e)(2) Deferred Compensation Plan; Supplemental Executive Retirement Plan.
------------------------------------------------------------------
SAVANNAH has in effect a voluntary deferred compensation plan for certain
executive employees pursuant to which such employees may defer a portion of
their respective annual salaries. In addition, SAVANNAH has a supplemental
executive retirement plan for certain of its executive employees which became
effective January 1, 1984. The deferred compensation plan is designed to provide
supplemental retirement or survivor benefit payments. The supplemental executive
retirement plan is also designed to provide retiring executives of SAVANNAH with
a supplemental retirement benefit, which, in conjunction with social security
and benefits under SAVANNAH's qualified pension plan, will equal 70 percent of
the highest three of the final ten years average annual compensation (including
deferrals under the deferred compensation plan). Both of these plans are
unfunded and the liability is payable from general funds of SAVANNAH. The
deferred compensation plan became effective December 1, 1983, and all of
SAVANNAH's executive officers are participating in the plan. In addition, all
executives are participating in the supplemental executive retirement plan.
In order to provide for its liabilities under the deferred compensation
plan and the supplemental executive retirement plan, SAVANNAH has purchased life
insurance on participating executive employees in actuarially determined amounts
which, based upon assumptions as to mortality experience, policy dividends, tax
effects, and other factors which, if realized, along with compensation deferred
by employees and the death benefits payable to SAVANNAH, are expected to cover
all such insurance premium payments, and all benefit payments to participants,
plus a factor for the cost of funds of SAVANNAH.
-------------------------------
1 The plan benefits are subject to the maximum benefit limitations set forth in
Section 415 of the Internal Revenue Code.
III-27
(f) Compensation of Directors.
-------------------------
(1) Standard Arrangements. The following table presents compensation paid
to the directors, during 1994 for service as a member of the board of directors
and any board committee(s), except that employee directors received no fees or
compensation for service as a member of the board of directors or any board
committee. All or a portion of these fees may be deferred until membership on
the board is terminated.
ALABAMA GEORGIA GULF MISSISSIPPI SAVANNAH
Retainer Fee $15,000 $18,000 $12,000 $12,000 $12,000
Meeting Fee 800 900 750 750 750
Committees:
Audit 800 900 750 750 750
Compensation 800 900 750 750 750
Executive 800 900 - - 750
Finance - 900 - 750 -
Nominating 800 - - - -
Nuclear Safety 800 - - - -
Nuclear Operations
Overview - 1,800 - - -
ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH also provide
retirement benefits to non-employee directors who are credited with a minimum of
60 months of service on the board of directors of one or more system companies,
under the Outside Directors Pension Plan. Eligible directors are entitled to
benefits under the Plan upon retirement from the board on the retirement date
designated in the respective companies' by-laws. The annual benefit payable
ranges from 75 to 100 percent of the annual retainer fee in effect on the date
of retirement, based upon length of service. Payments continue for the greater
of the lifetime of the participant or 10 years.
(2) Other Arrangements. No director received other compensation for
services as a director during the year ending December 31, 1994 in addition to
or in lieu of that specified by the standard arrangements specified above.
(g) Employment Contracts and Termination of Employment and Change in
Control Arrangements.
None.
III-28
(h) Report on Repricing of Options.
------------------------------
None.
(i) Additional Information with Respect to Compensation Committee
Interlocks and Insider Participation in Compensation Decisions.
ALABAMA
Elmer B. Harris serves on the Compensation Committee of AmSouth
Bancorporation. John W. Woods, a director of ALABAMA, is Chairman and
Chief Executive Officer of AmSouth Bancorporation.
III-29
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
(a) Security ownership of certain beneficial owners.
-----------------------------------------------
SOUTHERN is the beneficial owner of 100% of the outstanding common
stock of registrants: ALABAMA, GEORGIA, GULF, MISSISSIPPI and
SAVANNAH.
Amount and
Name and Address Nature of Percent
of Beneficial Beneficial of
Title of Class Owner Ownership Class
------------------------------------------------------------------------------------------
Common Stock The Southern Company 100%
64 Perimeter Center East
Atlanta, Georgia 30346
Registrants:
-----------
ALABAMA 5,608,955
GEORGIA 7,761,500
GULF 992,717
MISSISSIPPI 1,121,000
SAVANNAH 10,844,635
(b) Security ownership of management. The following table shows the
number of shares of SOUTHERN common stock and operating subsidiary preferred
stock owned by the directors, nominees and executive officers as of December 31,
1994. It is based on information furnished by the directors, nominees and
executive officers. The shares owned by all directors, nominees and executive
officers as a group constitute less than one percent of the total number of
shares of the respective classes outstanding on December 31, 1994.
Name of Directors, Number of Shares
Nominees and Beneficially
Executive Officers Title of Class Owned 1,2
------------------ -------------- ----------------
ALABAMA
Whit Armstrong SOUTHERN Common 13,164
A. W. Dahlberg SOUTHERN Common 92,736
Bill M. Guthrie SOUTHERN Common 93,694
Elmer B. Harris SOUTHERN Common 104,175
III-30
Name of Directors, Number of Shares
Nominees and Beneficially
Executive Officers Title of Class Owned 1,2
------------------ -------------- -----------------
Crawford T. Johnson, III SOUTHERN Common 607
Carl E. Jones, Jr. SOUTHERN Common 8,380
Gerald H. Powell SOUTHERN Common 5,604
Robert Davis Powers SOUTHERN Common 50
John W. Rouse, Jr. SOUTHERN Common 3,585
William J. Rushton, III SOUTHERN Common 6,201
ALABAMA Preferred 20
John C. Webb, IV SOUTHERN Common 7,798
ALABAMA Preferred 989
Banks H. Farris SOUTHERN Common 37,453
William B. Hutchins, III SOUTHERN Common 23,081
T. Harold Jones SOUTHERN Common 24,587
Charles D. McCrary SOUTHERN Common 15,986
The directors, nominees,
and executive officers
as a group SOUTHERN Common 437,101 shares
ALABAMA Preferred 1,009 shares
GEORGIA
Edward L. Addison SOUTHERN Common 313,008
Bennett A. Brown SOUTHERN Common 9,000
A. W. Dahlberg SOUTHERN Common 92,736
W. A. Fickling, Jr. GEORGIA Preferred 50
H. Allen Franklin SOUTHERN Common 61,231
L. G. Hardman III SOUTHERN Common 6,779
III-31
Name of Directors, Number of Shares
Nominees and Beneficially
Executive Officers Title of Class Owned 1,2
------------------ -------------- ------------------
Warren Y. Jobe SOUTHERN Common 36,589
GEORGIA Preferred 403
James R. Lientz, Jr. SOUTHERN Common 42
W. A. Parker, Jr. SOUTHERN Common 26,254
GEORGIA Preferred 2
Gloria M. Shatto SOUTHERN Common 13,351
GEORGIA Preferred 1,200
W. J. Vereen SOUTHERN Common 5,000
GEORGIA Preferred 1,701
Thomas R. Williams GEORGIA Preferred 1,000
Dwight E. Evans SOUTHERN Common 24,844
GEORGIA Preferred 300
William G. Hairston, III SOUTHERN Common 25,550
Gene R. Hodges SOUTHERN Common 33,328
GEORGIA Preferred 800
The directors, nominees
and executive officers
as a group SOUTHERN Common 743,594 shares
GEORGIA Preferred 5,456 shares
GULF
Reed Bell SOUTHERN Common 43
Travis J. Bowden SOUTHERN Common 50,443
Paul J. DeNicola SOUTHERN Common 41,269
W. Deck Hull, Jr. SOUTHERN Common 2,139
C. Walter Ruckel SOUTHERN Common 43
Joseph K. Tannehill SOUTHERN Common 4,043
III-32
Name of Directors, Number of Shares
Nominees and Beneficially
Executive Officers Title of Class Owned 1,2
------------------ -------------- ------------------
John E. Hodges, Jr. SOUTHERN Common 34,870
GULF Preferred 3
G. Edison Holland, Jr. SOUTHERN Common 4,929
Earl B. Parsons, Jr. SOUTHERN Common 14,736
Arlan E. Scarbrough SOUTHERN Common 19,820
The directors, nominees SOUTHERN Common 176,275 shares
and executive officers GULF Preferred 5 shares
as a group
MISSISSIPPI
Paul J. DeNicola SOUTHERN Common 41,269
Edwin E. Downer SOUTHERN Common 1,059
Robert S. Gaddis SOUTHERN Common 3,236
Walter H. Hurt, III SOUTHERN Common 843
MISSISSIPPI Preferred 33
Aubrey K. Lucas SOUTHERN Common 901
Earl D. McLean, Jr. SOUTHERN Common 14,451
David M. Ratcliffe SOUTHERN Common 32,896
Gerald J. St. Pe SOUTHERN Common 16,043
N. Eugene Warr SOUTHERN Common 86
H. E. Blakeslee SOUTHERN Common 15,846
Thomas A. Fanning SOUTHERN Common 4,253
Frederick D. Kuester SOUTHERN Common 9,899
III-33
Name of Directors, Number of Shares
Nominees and Beneficially
Executive Officers Title of Class Owned 1,2
------------------ -------------- -------------------
Don E. Mason SOUTHERN Common 18,160
The directors, nominees
and executive officers SOUTHERN Common 158,942 shares
as a group MISSISSIPPI Preferred 33 shares
SAVANNAH
Helen Quattlebaum Artley SOUTHERN Common 2,461
Paul J. DeNicola SOUTHERN Common 41,269
Brian R. Foster SOUTHERN Common 43
Arthur M. Gignilliat, Jr. SOUTHERN Common 46,914
Walter D. Gnann SOUTHERN Common 1,550
Robert B. Miller, III SOUTHERN Common 2,025
James M. Piette SOUTHERN Common 1,281
Arnold M. Tenenbaum SOUTHERN Common 397
Fred F. Williams SOUTHERN Common 972
W. Miles Greer SOUTHERN Common 1,398
III-34
Name of Directors, Number of Shares
Nominees and Beneficially
Executive Officers Title of Class Owned 1,2
------------------ -------------- -------------------
Larry M. Porter SOUTHERN Common 11,739
Kirby R. Willis SOUTHERN Common 3,547
The directors, nominees
and executive officers
as a group SOUTHERN Common 113,596 shares
(c) Changes in control. SOUTHERN and the operating affiliates know of
no arrangements which may at a subsequent date result in any change in control.
--------
1 As used in this table, "beneficial ownership" means the sole or shared power to vote, or to direct the voting
of, a security and/or investment power with respect to a security (i.e., the power to dispose of, or to direct
the disposition of, a security).
2 The shares shown include shares of SOUTHERN common stock of which certain directors and executive officers have
the right to acquire beneficial ownership within 60 days pursuant to the Executive Stock Plan, as follows: Mr.
Addison, 230,025 shares; Mr. Blakeslee, 6,812 shares; Mr. Bowden, 24,019 shares; Mr. Dahlberg, 45,847 shares; Mr.
DeNicola, 12,139 shares; Mr. Evans, 8,474 shares; Mr. Farris, 5,028 shares; Mr. Franklin, 40,383 shares; Mr.
Gignilliat, 26,133 shares; Mr. Guthrie, 44,968 shares; Mr. Hairston, 9,658 shares; Mr. Harris, 58,867 shares;
Mr. G. R. Hodges, 7,627 shares; Mr. J. E. Hodges, 15,714 shares; Mr. Holland, 4,255 shares; Mr. Hutchins, 4,300
shares; Mr. Jobe, 9,416 shares; Mr. Jones, 4,910 shares; Mr. C. D. McCrary, 4,232 shares; Mr. Ratcliffe, 20,046
shares; and Mr. Williams, 1,416 shares. Also included are shares of SOUTHERN common stock held by the spouses of
the following directors: Mr. Addison, 1,424 shares; Mr. Hardman, 100 shares; Mr. Harris, 310 shares; Mr. Parker,
48 shares; Mr. Powers, 50 shares; and Dr. Shatto, 11,157 shares. Also included are 1,200 shares of GEORGIA
preferred stock held by Dr. Shatto's spouse.
III-35
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
ALABAMA
(a) Transactions with management and others.
During 1994, ALABAMA, in the ordinary course of business, paid premiums
amounting to approximately $584,358 for various types of insurance policies
purchased from Protective Life Insurance Company, a subsidiary of Protective
Life Corporation, a company in which Mr. William J. Rushton, III, a director of
ALABAMA, owns an interest and of which he served as Chairman.
ALABAMA believes that these transactions have been on terms representing
competitive market prices that are no less favorable than those available from
others.
(b) Certain business relationships.
None.
(c) Indebtedness of management.
None.
(d) Transactions with promoters.
None.
GEORGIA
(a) Transactions with management and others.
Mr. G. Joseph Prendergast is Chairman of Wachovia Bank of Georgia, N.A.,
and Mr. James R. Lientz, Jr. is President of NationsBank of Georgia. During
1994, these banks furnished a number of regular banking services in the ordinary
course of business to GEORGIA. GEORGIA intends to maintain normal banking
relations with all the aforesaid banks in the future.
In 1994, GEORGIA leased a building from Riverside Manufacturing Co. for
approximately $73,000. Mr. William J. Vereen is Chief Executive Officer,
President, Treasurer and Director of Riverside Manufacturing Co.
(b) Certain business relationships.
None.
(c) Indebtedness of management.
None.
(d) Transactions with promoters.
None.
GULF
(a) Transactions with management and others.
The firm of Beggs & Lane, P.A. serves as local counsel for GULF and
received from GULF approximately $1,095,340 for services rendered. Mr. G. Edison
Holland, Jr. is a partner in the firm and also serves as Vice President and
Corporate Counsel of GULF.
(b) Certain business relationships.
None.
(c) Indebtedness of management.
None.
(d) Transactions with promoters.
None.
MISSISSIPPI
(a) Transactions with management and others.
During 1994, MISSISSIPPI was indebted in a maximum amount of $9 million to
Hancock Bank, of which Mr. Leo W. Seal, Jr. serves as Chairman of the Board and
Chief Executive Officer. Mr. Seal retired from MISSISSIPPI's board of directors
effective September 6, 1994.
(b) Certain business relationships.
None.
(c) Indebtedness of management.
None.
(d) Transactions with promoters.
None.
III-36
SAVANNAH
(a) Transactions with management and others.
Mr. Tenenbaum is a Director of First Union National Bank of Georgia, and Mr.
Foster is President of NationsBank of Georgia, N.A., in Savannah. During 1994,
these banks furnished a number of regular banking services in the ordinary
course of business to SAVANNAH. SAVANNAH intends to maintain normal banking
relations with all of the aforesaid banks in the future.
(b) Certain business relationships.
None.
(c) Indebtedness of management.
None.
(d) Transactions with promoters.
None.
III-37
PART IV
Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) The following documents are filed as a part of this report on this Form
10-K:
(1) Financial Statements:
Reports of Independent Public Accountants on the financial
statements for SOUTHERN and Subsidiary Companies, ALABAMA,
GEORGIA, GULF, MISSISSIPPI and SAVANNAH are listed under Item
8 herein.
The financial statements filed as a part of this report for
SOUTHERN and Subsidiary Companies, ALABAMA, GEORGIA, GULF,
MISSISSIPPI and SAVANNAH are listed under Item 8 herein.
(2) Financial Statement Schedules:
Reports of Independent Public Accountants as to Schedules for
SOUTHERN and Subsidiary Companies, ALABAMA, GEORGIA, GULF,
MISSISSIPPI and SAVANNAH are included herein on pages IV-12
through IV-17.
Financial Statement Schedules for SOUTHERN and Subsidiary
Companies, ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH
are listed in the Index to the Financial Statement Schedules
at page S-1.
(3) Exhibits:
Exhibits for SOUTHERN, ALABAMA, GEORGIA, GULF, MISSISSIPPI and
SAVANNAH are listed in the Exhibit Index at page E-1.
(b) Reports on Form 8-K: During the fourth quarter of 1994 only the
following registrant filed a Current Report on Form 8-K:
ALABAMA filed a Form 8-K dated November 30, 1994 to facilitate a
security sale.
IV-1
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized. The signature of the
undersigned company shall be deemed to relate only to matters having reference
to such company and any subsidiaries thereof.
THE SOUTHERN COMPANY
By: A. W. Dahlberg, Chairman, President and
Chief Executive Officer
By: /s/ Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 23, 1995
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities and on the dates indicated. The signature of each of the
undersigned shall be deemed to relate only to matters having reference to the
above-named company and any subsidiaries thereof.
A. W. Dahlberg
Chairman of the Board, President and
Chief Executive Officer
(Principal Executive Officer)
W. L. Westbrook
Financial Vice President and Chief Financial Officer
(Principal Financial and Accounting Officer)
Directors:
W. P. Copenhaver Elmer B. Harris.
A. D. Correll Earl D. McLean, Jr.
Paul J. DeNicola William A. Parker, Jr.
Jack Edwards William J. Rushton, III
H. Allen Franklin Gloria M. Shatto
Bruce S. Gordon Herbert Stockham
L. G. Hardman III
By: /s/ Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 23, 1995
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized. The signature of the
undersigned company shall be deemed to relate only to matters having reference
to such company and any subsidiaries thereof.
ALABAMA POWER COMPANY
By: Elmer B. Harris, President and
Chief Executive Officer
By: /s/ Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 23, 1995
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities and on the dates indicated. The signature of each of the
undersigned shall be deemed to relate only to matters having reference to the
above-named company and any subsidiaries thereof.
Elmer B. Harris
President, Chief Executive Officer and Director
(Principal Executive Officer)
William B. Hutchins, III
Executive Vice President
(Principal Financial Officer)
David L. Whitson
Vice President and Comptroller
(Principal Accounting Officer)
Directors:
Whit Armstrong Wallace D. Malone, Jr.
Philip E. Austin William V. Muse
Margaret A. Carpenter Gerald H. Powell
A. W. Dahlberg Robert D. Powers
Peter V. Gregerson, Sr. John W. Rouse
Bill M. Guthrie James H. Sanford
Crawford T. Johnson, III John Cox Webb, IV
Carl E. Jones, Jr. John W. Woods
By: /s/Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 23, 1995
IV-2
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized. The signature of the
undersigned company shall be deemed to relate only to matters having reference
to such company and any subsidiaries thereof.
GEORGIA POWER COMPANY
By: H. Allen Franklin, President and
Chief Executive Officer
By: /s/ Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 23, 1995
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities and on the dates indicated. The signature of each of the
undersigned shall be deemed to relate only to matters having reference to the
above-named company and any subsidiaries thereof.
H. Allen Franklin
President, Chief Executive Officer and Director
(Principal Executive Officer)
Warren Y. Jobe
Executive Vice President, Treasurer,
Chief Financial Officer and Director
(Principal Financial Officer)
C. B. Harreld
Vice President and Comptroller
(Principal Accounting Officer)
Directors:
Bennett A. Brown Herman J. Russell
A. W. Dahlberg William Jerry Vereen
L. G. Hardman III Carl Ware
James R. Lientz, Jr. Thomas R. Williams
G. Joseph Prendergast
By: /s/Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 23, 1995
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized. The signature of the
undersigned company shall be deemed to relate only to matters having reference
to such company and any subsidiaries thereof.
GULF POWER COMPANY
By: Travis J. Bowden, President and
Chief Executive Officer
By: /s/Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 23, 1995
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities and on the dates indicated. The signature of each of the
undersigned shall be deemed to relate only to matters having reference to the
above-named company and any subsidiaries thereof.
Travis J. Bowden
President, Chief Executive Officer and Director
(Principal Executive Officer)
A. E. Scarbrough
Vice President - Finance
(Principal Financial and Accounting Officer)
Directors:
Reed Bell W. D. Hull, Jr.
Paul J. DeNicola C. W. Ruckel
Fred C. Donovan J. K. Tannehill
By: /s/ Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 23, 1995
IV-3
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized. The signature of the
undersigned company shall be deemed to relate only to matters having reference
to such company and any subsidiaries thereof.
MISSISSIPPI POWER COMPANY
By: David M. Ratcliffe, President and
Chief Executive Officer
By: /s/ Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 23, 1995
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities and on the dates indicated. The signature of each of the
undersigned shall be deemed to relate only to matters having reference to the
above-named company and any subsidiaries thereof.
David M. Ratcliffe
President, Chief Executive Officer and Director
(Principal Executive Officer)
Michael W. Southern
Vice President, Secretary, Treasurer and
Chief Financial Officer
(Principal Financial and Accounting Officer)
Directors:
Paul J. DeNicola Aubrey K. Lucas
Edwin E. Downer Gerald J. St. Pe'
Robert S. Gaddis N. Eugene Warr
Walter H. Hurt, III
By: /s/ Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 23, 1995
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized. The signature of the
undersigned company shall be deemed to relate only to matters having reference
to such company and any subsidiaries thereof.
SAVANNAH ELECTRIC AND POWER COMPANY
By: Arthur M. Gignilliat, Jr., President and
Chief Executive Officer
By: /s/ Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 23, 1995
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities and on the dates indicated. The signature of each of the
undersigned shall be deemed to relate only to matters having reference to the
above-named company and any subsidiaries thereof.
Arthur M. Gignilliat, Jr.
President, Chief Executive Officer and Director
(Principal Executive Officer)
Kirby R. Willis
Vice President, Treasurer and
Chief Financial Officer
(Principal Financial and Accounting Officer)
Directors:
Helen Q. Artley Robert B. Miller, III
Paul J. DeNicola James M. Piette
Brian R. Foster Arnold M. Tenenbaum
Walter D. Gnann Frederick F. Williams, Jr.
By: /s/ Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 23, 1995
IV-4
Exhibit 21. Subsidiaries of the Registrants.
Name of Company Jurisdiction of Organization
----------------------------------------------------------------- ----------------------------
Alabama Power Company Alabama
Alabama Property Company Alabama
Columbia Fuels, Inc. Alabama
Southern Electric Generating Company Alabama
Georgia Power Company Georgia
Piedmont-Forrest Corporation Georgia
Georgia Power L. P. Holdings Corp. Georgia
Southern Electric Generating Company Alabama
Gulf Power Company Maine
Mississippi Power Company Mississippi
Savannah Electric and Power Company Georgia
Energia de Nuevo Leon, S.A. de C.V. Mexico
Mobile Energy Services Company, Inc. Alabama
SEI Holdings, Inc. Delaware
Asociados de Electricidad, S. A. Argentina
SEI y Asociados de Argentina, S. A. Argentina
Hidroelectrica Alicura, S. A. Argentina
SEI Holdings III, Inc. Delaware
SEI Chile, S. A. Chile
Inversiones SEI Chile Limitada Chile
Electrica SEI Chile Limitada Chile
Empresa Electrica del Norte Grande, S. A. (Edelnor) Chile
SEI Holdings IV, Inc. Delaware
Tesro Holding B.V. Netherlands
SEI Bahamas Argentina II, Inc. Bahamas
SEI Holdings VIII, Inc. Delaware
Delaware
SEI Beteiligungs GmbH Germany
SEI Holdings IX, Inc. Delaware
The Power Generation Company of Trinidad and Tobago Trinidad and Tobago
SEI Holdings X, Inc. Delaware
Southern Electric Brasil Participacoes, Ltda. Brazil
SEI Holdings XI, Inc. Delaware
Southern Electric Brasil Participacoes, Ltda. Brazil
Southern Communications Services, Inc. Delaware
Southern Company Services, Inc. Alabama
Southern Electric Bahamas Holdings, Ltd. Bahamas
Southern Electric Bahamas, Ltd. Bahamas
Freeport Power Company Limited Bahamas
Southern Electric, Inc. Delaware
SEI Bahamas Argentina I, Inc. Bahamas
SEI Inversora, S. A. Argentina
Southern Electric International, Inc. Delaware
SEI Operadora de Argentina, S.A. Argentina
Southern Electric Railroad Company Delaware
Southern Electric Wholesale Generators, Inc. Delaware
Birchwood Development Corp. Delaware
SEI Birchwood, Inc. Delaware
Birchwood Power Partners, L.P. Delaware
SEI Hawaiian Cogenerators, Inc. Delaware
Kalaeloa Partners, L. P. Delaware
Southern Nuclear Operating Company, Inc. Delaware
The Southern Development and Investment Group, Inc. Georgia
IV-5
ARTHUR ANDERSEN LLP
Exhibit 23(a)
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation
of our reports dated February 15, 1995 on the financial statements of The
Southern Company and its subsidiaries and the related financial statement
schedules, included in this Form 10-K, into The Southern Company's previously
filed Registration Statement File Nos. 2-78617, 33-3546, 33-23152, 33-30171,
33-23153, 33-51433, 33-54415, and 33-57951.
/s/ ARTHUR ANDERSEN LLP
Atlanta, Georgia
March 23, 1995
IV-6
Exhibit 23(b)
ARTHUR ANDERSEN LLP
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation
of our reports dated February 15, 1995 on the financial statements of Alabama
Power Company and the related financial statement schedules, included in this
Form 10-K, into Alabama Power Company's previously filed Registration Statement
File No. 33-49653.
/s/ ARTHUR ANDERSEN LLP
Birmingham, Alabama
March 23, 1995
IV-7
Exhibit 23(c)
ARTHUR ANDERSEN LLP
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation
of our reports dated February 15, 1995 on the financial statements of Georgia
Power Company and the related financial statement schedules, included in this
Form 10-K, into Georgia Power Company's previously filed Registration Statement
File No. 33-49661.
/s/ ARTHUR ANDERSEN LLP
Atlanta, Georgia
March 23, 1995
IV-8
Exhibit 23(d)
ARTHUR ANDERSEN LLP
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation
of our reports dated February 15, 1995 on the financial statements of Gulf Power
Company and the related financial statement schedules, included in this Form
10-K, into Gulf Power Company's previously filed Registration Statement File No.
33-50165.
/s/ ARTHUR ANDERSEN LLP
Atlanta, Georgia
March 23, 1995
IV-9
Exhibit 23(e)
ARTHUR ANDERSEN LLP
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation
of our reports dated February 15, 1995 on the financial statements of
Mississippi Power Company and the related financial statement schedules,
included in this Form 10-K, into Mississippi Power Company's previously filed
Registration Statement File Nos.
33-49320 and 33-49649.
/s/ ARTHUR ANDERSEN LLP
Atlanta, Georgia
March 23, 1995
IV-10
Exhibit 23(f)
ARTHUR ANDERSEN LLP
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation
of our reports dated February 15, 1995 on the financial statements of Savannah
Electric and Power Company and the related financial statement schedules,
included in this Form 10-K, into Savannah Electric and Power Company's
previously filed Registration Statement File Nos. 33-45757 and 33-52509.
/s/ ARTHUR ANDERSEN LLP
Atlanta, Georgia
March 23, 1995
IV-11
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULES
To The Southern Company:
We have audited in accordance with generally accepted auditing standards,
the consolidated financial statements of The Southern Company and its
subsidiaries included in this Form 10-K, and have issued our report thereon
dated February 15, 1995. Our report on the consolidated financial statements
includes an explanatory paragraph which states that an uncertainty exists with
respect to the actions of the regulators regarding recoverability of the
investment in the Rocky Mountain pumped storage hydroelectric project, as
discussed in Note 4 to The Southern Company's consolidated financial statements.
Our audits were made for the purpose of forming an opinion on those statements
taken as a whole. The schedules listed under Item 14(a)(2) herein as it relates
to The Southern Company and its subsidiaries (pages S-2 through S-4) are the
responsibility of The Southern Company's management and are presented for
purposes of complying with the Securities and Exchange Commission's rules and
are not part of the basic consolidated financial statements. These schedules
have been subjected to the auditing procedures applied in the audits of the
basic consolidated financial statements and, in our opinion, fairly state in all
material respects the financial data required to be set forth therein in
relation to the basic consolidated financial statements taken as a whole.
/s/ ARTHUR ANDERSEN LLP
Atlanta, Georgia
February 15, 1995
IV-12
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULES
To Alabama Power Company:
We have audited in accordance with generally accepted auditing standards,
the financial statements of Alabama Power Company included in this Form 10-K,
and have issued our report thereon dated February 15, 1995. Our audits were made
for the purpose of forming an opinion on those statements taken as a whole. The
schedules listed under Item 14(a)(2) herein as it relates to Alabama Power
Company (pages S-5 through S-7) are the responsibility of Alabama Power
Company's management and are presented for purposes of complying with the
Securities and Exchange Commission's rules and are not part of the basic
financial statements. These schedules have been subjected to the auditing
procedures applied in the audits of the basic financial statements and, in our
opinion, fairly state in all material respects the financial data required to be
set forth therein in relation to the basic financial statements taken as a
whole.
/s/ ARTHUR ANDERSEN LLP
Birmingham, Alabama
February 15, 1995
IV-13
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULES
To Georgia Power Company:
We have audited in accordance with generally accepted auditing standards,
the financial statements of Georgia Power Company included in this Form 10-K,
and have issued our report thereon dated February 15, 1995. Our report on the
financial statements includes an explanatory paragraph which states that an
uncertainty exists with respect to the actions of the regulators regarding the
recoverability of Georgia Power Company's investment in the Rocky Mountain
pumped storage hydroelectric project, as discussed in Note 4 to Georgia Power
Company's financial statements. Our audits were made for the purpose of forming
an opinion on those statements taken as a whole. The schedules listed under Item
14(a)(2) herein as it relates to Georgia Power Company (pages S-8 through S-10)
are the responsibility of Georgia Power Company's management and are presented
for purposes of complying with the Securities and Exchange Commission's rules
and are not part of the basic financial statements. These schedules have been
subjected to the auditing procedures applied in the audits of the basic
financial statements and, in our opinion, fairly state in all material respects
the financial data required to be set forth therein in relation to the basic
financial statements taken as a whole.
/s/ ARTHUR ANDERSEN LLP
Atlanta, Georgia
February 15, 1995
IV-14
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULES
To Gulf Power Company:
We have audited in accordance with generally accepted auditing standards,
the financial statements of Gulf Power Company included in this Form 10-K, and
have issued our report thereon dated February 15, 1995. Our audits were made for
the purpose of forming an opinion on those statements taken as a whole. The
schedules listed under Item 14(a)(2) herein as it relates to Gulf Power Company
(pages S-11 through S-13) are the responsibility of Gulf Power Company's
management and are presented for purposes of complying with the Securities and
Exchange Commission's rules and are not part of the basic financial statements.
These schedules have been subjected to the auditing procedures applied in the
audits of the basic financial statements and, in our opinion, fairly state in
all material respects the financial data required to be set forth therein in
relation to the basic financial statements taken as a whole.
/s/ ARTHUR ANDERSEN LLP
Atlanta, Georgia
February 15, 1995
IV-15
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULES
To Mississippi Power Company:
We have audited in accordance with generally accepted auditing standards,
the financial statements of Mississippi Power Company included in this Form
10-K, and have issued our report thereon dated February 15, 1995. Our audits
were made for the purpose of forming an opinion on those statements taken as a
whole. The schedules listed under Item 14(a)(2) herein as it relates to
Mississippi Power Company (pages S-14 through S-16) are the responsibility of
Mississippi Power Company's management and are presented for purposes of
complying with the Securities and Exchange Commission's rules and are not part
of the basic financial statements. These schedules have been subjected to the
auditing procedures applied in the audits of the basic financial statements and,
in our opinion, fairly state in all material respects the financial data
required to be set forth therein in relation to the basic financial statements
taken as a whole.
/s/ ARTHUR ANDERSEN LLP
Atlanta, Georgia
February 15, 1995
IV-16
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULES
To Savannah Electric and Power Company:
We have audited in accordance with generally accepted auditing standards,
the financial statements of Savannah Electric and Power Company included in this
Form 10-K, and have issued our report thereon dated February 15, 1995. Our
audits were made for the purpose of forming an opinion on those statements taken
as a whole. The schedules listed under Item 14(a)(2) herein as it relates to
Savannah Electric and Power Company (pages S-17 through S-19) are the
responsibility of Savannah Electric and Power Company's management and are
presented for purposes of complying with the Securities and Exchange
Commission's rules and are not part of the basic financial statements. These
schedules have been subjected to the auditing procedures applied in the audits
of the basic financial statements and, in our opinion, fairly state in all
material respects the financial data required to be set forth therein in
relation to the basic financial statements taken as a whole.
/s/ ARTHUR ANDERSEN LLP
Atlanta, Georgia
February 15, 1995
IV-17
INDEX TO FINANCIAL STATEMENT SCHEDULES
Schedule Page
II Valuation and Qualifying Accounts and Reserves
1994, 1993 and 1992
The Southern Company and Subsidiary Companies.......................................................... S-2
Alabama Power Company.................................................................................. S-5
Georgia Power Company.................................................................................. S-8
Gulf Power Company..................................................................................... S-11
Mississippi Power Company.............................................................................. S-14
Savannah Electric and Power Company.................................................................... S-17
Schedules I through V not listed above are omitted as not applicable or not
required. Columns omitted from schedules filed have been omitted because the
information is not applicable or not required.
S-1
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEAR ENDED DECEMBER 31, 1994
(Stated in Thousands of Dollars)
Additions
------------------
Balance at Beginning Charged to Charged to Other Balance at End
Description of Period Income Accounts Deductions of Period
---------------------------------------------------------------------------------------------------------------------------------
Provision for uncollectible
accounts $9,067 $23,322 $8 $23,268 (1) $9,129
Deferred credits:
Provision for property insurance $22,047 $31,306 $236 $1,112 (2) $52,477
Other property and investments:
Nuclear
decommissioning trust (3) $87,487 $18,695 $19,129 - $125,311
Deferred charges:
Uranium enrichment,
decontamination and
decommissioning fund (4) $86,342 - $(938) $6,514 $78,890
-------------------
Notes:
(1) Represents write-off of accounts considered to be uncollectible, less
recoveries of amounts previously written off.
(2) Insurance recoveries net of charges to reserve for purposes for which
reserve was created.
(3) See Note 1 to SOUTHERN's financial statements under "Depreciation and
Nuclear Decommissioning" in Item 8 herein for further information.
(4) See Note 1 to SOUTHERN's financial statements under "Revenues and Fuel
Costs" in Item 8 herein for further information.
S-2
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEAR ENDED DECEMBER 31, 1993
(Stated in Thousands of Dollars)
Additions
------------------
Balance at Beginning Charged to Charged to Other Balance at End
Description of Period Income Accounts Deductions of Period
---------------------------------------------------------------------------------------------------------------------------------
Provision for uncollectible
accounts $7,255 $24,040 $2 $22,230 (1) $9,067
Deferred credits:
Provision for property insurance $23,594 $4,164 - $5,711 (2) $22,047
Other property and investments:
Nuclear
decommissioning trust (3) $52,701 $15,759 $19,351 (4) $324 $87,487
Deferred charges:
Uranium enrichment,
decontamination and
decommissioning fund (5) $90,099 - $1,219 $4,976 $86,342
-------------------------
Notes:
(1) Represents write-off of accounts considered to be uncollectible, less
recoveries of amounts previously written off.
(2) Insurance recoveries net of charges to reserve for purposes for which
reserve was created.
(3) See Note 1 to SOUTHERN's financial statements under "Depreciation
and Nuclear Decommissioning" in Item 8 herein for further information.
(4) Represents additional funding to reserve.
(5) See Note 1 to SOUTHERN's financial statements under "Revenues and Fuel
Costs" in Item 8 herein for further information.
S-3
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEAR ENDED DECEMBER 31, 1992
(Stated in Thousands of Dollars)
Additions
------------------
Balance at Beginning Charged to Charged to Other Balance at End
Description of Period Income Accounts Deductions of Period
---------------------------------------------------------------------------------------------------------------------------------
Provision for uncollectible
accounts $12,568 $18,366 - $23,679 (1) $7,255
Deferred credits:
Provision for property insurance $20,928 $3,298 $25 (4) $657 $23,594
Other property and investments:
Nuclear
decommissioning trust (2) $25,871 $14,782 $12,189 $141 $52,701
Deferred charges:
Uranium enrichment,
decontamination and
decommissioning fund (3) - - $90,099 - $90,099
-------------------
Notes:
(1) Represents write-off of accounts considered to be uncollectible, less
recoveries of amounts previously written off.
(2) See Note 1 to SOUTHERN's financial statements under "Depreciation
and Nuclear Decommissioning" in Item 8 herein for further information.
(3) See Note 1 to SOUTHERN's financial statements under "Revenues
and Fuel Costs" in Item 8 herein for further information.
(4) Capitalized.
S-4
ALABAMA POWER COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEAR ENDED DECEMBER 31, 1994
(Stated in Thousands of Dollars)
Additions
------------------
Balance at Beginning Charged to Charged to Other Balance at End
Description of Period Income Accounts Deductions of Period
---------------------------------------------------------------------------------------------------------------------------------
Provision for uncollectible
accounts $2,632 $4,967 - $5,302 (1) $2,297
Deferred credits:
Provision for natural disaster
reserve (4) - $28,750 - - $28,750
Other property and investments:
Nuclear
decommissioning trust (2) $49,550 $18,143 $3,321 - $71,014
Deferred charges:
Uranium enrichment,
decontamination and
decommissioning fund (3) $45,554 - $69 $2,627 $42,996
-------------------
Notes:
(1) Represents write-off of accounts considered to be uncollectible, less
recoveries of amounts previously written off.
(2) See Note 1 to ALABAMA's financial statements under "Depreciation and
Nuclear Decommissioning" in Item 8 herein for further information.
(3) See Note 1 to ALABAMA's financial statements under "Revenues and Fuel
Costs" in Item 8 herein for further information.
(4) See Note 1 to ALABAMA's financial statements under "Natural Disaster
Reserve" in Item 8 herein for further information.
S-5
ALABAMA POWER COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEAR ENDED DECEMBER 31, 1993
(Stated in Thousands of Dollars)
Additions
------------------
Balance at Beginning Charged to Charged to Other Balance at End
Description of Period Income Accounts Deductions of Period
---------------------------------------------------------------------------------------------------------------------------------
Provision for uncollectible
accounts $1,482 $7,157 - $6,007(1) $2,632
Other property and investments:
Nuclear
decommissioning trust (2) $32,390 $13,617 $3,543 (3) - $49,550
Deferred charges:
Uranium enrichment,
decontamination and
decommissioning fund (4) $47,730 - $1,873 $4,049 $45,554
--------------------
Notes:
(1) Represents write-off of accounts considered to be uncollectible, less
recoveries of amounts previously written off.
(2) See Note 1 to ALABAMA's financial statements under "Depreciation
and Nuclear Decommissioning" in Item 8 herein for further information.
(3) Represents additional funding to reserve.
(4) See Note 1 to ALABAMA's financial statements under "Revenues and Fuel
Costs" in Item 8 herein for further information.
S-6
ALABAMA POWER COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEAR ENDED DECEMBER 31, 1992
(Stated in Thousands of Dollars)
Additions
------------------
Balance at Beginning Charged to Charged to Other Balance at End
Description of Period Income Accounts Deductions of Period
---------------------------------------------------------------------------------------------------------------------------------
Provision for uncollectible
accounts $1,721 $4,878 - $5,117(1) $1,482
Other property and investments:
Nuclear
decommissioning trust (2) $15,864 $13,617 $2,909 - $32,390
Deferred charges:
Uranium enrichment,
decontamination and
decommissioning fund (3) - - $47,730 - $47,730
-------------------
Notes:
(1) Represents write-off of accounts considered to be uncollectible, less
recoveries of amounts previously written off.
(2) See Note 1 to ALABAMA's financial statements under "Depreciation and
Nuclear Decommissioning" in Item 8 herein for further information.
(3) See Note 1 to ALABAMA's financial statements under "Revenues and Fuel
Costs" in Item 8 herein for further Information.
S-7
GEORGIA POWER COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEAR ENDED DECEMBER 31, 1994
(Stated in Thousands of Dollars)
Additions
------------------
Balance at Beginning Charged to Charged to Other Balance at End
Description of Period Income Accounts Deductions of Period
---------------------------------------------------------------------------------------------------------------------------------
Provision for uncollectible
accounts $4,300 $15,424 - $15,224(1) $4,500
Other property and investments:
Nuclear
decommissioning trust (2) $37,937 $552 $15,808(3) - $54,297
Deferred charges:
Uranium enrichment,
decontamination and
decommissioning fund (4) $40,788 - $(1,007) $3,887 $35,894
-------------------
Notes:
(1) Represents write-off of accounts considered to be uncollectible, less
recoveries of amounts previously written off.
(2) See Note 1 to GEORGIA's financial statements under "Depreciation
and Nuclear Decommissioning" in Item 8 herein for further information.
(3) Represents additional funding to reserve.
(4) See Note 1 to GEORGIA's financial statements under "Revenues and Fuel
Costs" in Item 8 herein for further information.
S-8
GEORGIA POWER COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEAR ENDED DECEMBER 31, 1993
(Stated in Thousands of Dollars)
Additions
------------------
Balance at Beginning Charged to Charged to Other Balance at End
Description of Period Income Accounts Deductions of Period
---------------------------------------------------------------------------------------------------------------------------------
Provision for uncollectible
accounts $4,121 $14,310 - $14,131 (1) $4,300
Other property and investments:
Nuclear
decommissioning trust (2) $20,311 $2,142 $15,808 (3) $324 $37,937
Deferred charges:
Uranium enrichment,
decontamination and
decommissioning fund (4) $42,369 - $(654) $927 $40,788
-------------------
Notes:
(1) Represents write-off of accounts considered to be uncollectible, less
recoveries of amounts previously written off.
(2) See Note 1 to GEORGIA's financial statements under "Depreciation and
Nuclear Decommissioning" in Item 8 herein for further information.
(3) Represents additional funding to reserve.
(4) See Note 1 to GEORGIA's financial statements under "Revenues and Fuel
Costs" in Item 8 herein for further information.
S-9
GEORGIA POWER COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEAR ENDED DECEMBER 31, 1992
(Stated in Thousands of Dollars)
Additions
------------------
Balance at Beginning Charged to Charged to Other Balance at End
Description of Period Income Accounts Deductions of Period
---------------------------------------------------------------------------------------------------------------------------------
Provision for uncollectible
accounts $7,519 $11,440 - $14,838 (1) $4,121
Other property and investments:
Nuclear
decommissioning trust (2) $10,007 $1,165 $9,280 $141 $20,311
Deferred charges:
Uranium enrichment,
decontamination and
decommissioning fund (3) - - $42,369 - $42,369
-------------------
Notes:
(1) Represents write-off of accounts considered to be uncollectible, less
recoveries of amounts previously written off.
(2) See Note 1 to GEORGIA's financial statements under "Depreciation and
Nuclear Decommissioning" in Item 8 herein for further information.
(3) See Note 1 to GEORGIA's financial statements under "Revenues and Fuel
Costs" in Item 8 herein for further information.
S-10
GULF POWER COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEAR ENDED DECEMBER 31, 1994
(Stated in Thousands of Dollars)
Additions
------------------
Balance at Beginning Charged to Charged to Other Balance at End
Description of Period Income Accounts Deductions of Period
---------------------------------------------------------------------------------------------------------------------------------
Provision for uncollectible
accounts $447 $1,195 $9 $1,051 (Note) $600
Deferred credit:
Provision for property insurance $10,509 $1,200 $236 $423 $11,522
-------------------
Note: Represents write-off of accounts considered to be uncollectible,
less recoveries of amounts previously written off.
S-11
GULF POWER COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEAR ENDED DECEMBER 31, 1993
(Stated in Thousands of Dollars)
Additions
------------------
Balance at Beginning Charged to Charged to Other Balance at End
Description of Period Income Accounts Deductions of Period
---------------------------------------------------------------------------------------------------------------------------------
Provision for uncollectible
accounts $356 $875 - $784 (Note) $447
Deferred credit:
Provision for property insurance $9,692 $1,200 - $383 $10,509
-------------------
Note: Represents write-off of accounts considered to be uncollectible, less
recoveries of amounts previously written off.
S-12
GULF POWER COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEAR ENDED DECEMBER 31, 1992
(Stated in Thousands of Dollars)
Additions
------------------
Balance at Beginning Charged to Charged to Other Balance at End
Description of Period Income Accounts Deductions of Period
--------------------------------------------------------------------------------------------------------------------------------
Provision for uncollectible
accounts $660 $356 - $660 (Note) $356
Deferred credit:
Provision for property insurance $8,492 $1,200 - - $9,692
-------------------
Note: Represents write-off of accounts considered to be uncollectible, less
recoveries of amounts previously written off.
S-13
MISSISSIPPI POWER COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEAR ENDED DECEMBER 31, 1994
(Stated in Thousands of Dollars)
Additions
------------------
Balance at Beginning Charged to Charged to Other Balance at End
Description of Period Income Accounts Deductions of Period
---------------------------------------------------------------------------------------------------------------------------------
Provision for uncollectible
accounts $737 $1,234 $ (1) $1,300 (1) $670
Deferred credit:
Provision for property
insurance $10,538 $1,056 - $689 (2) $10,905
-------------------
Notes:
(1) Represents write-off of accounts considered to be uncollectible, less
recoveries of amounts previously written off.
(2) Net of insurance reimbursement.
S-14
MISSISSIPPI POWER COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEAR ENDED DECEMBER 31, 1993
(Stated in Thousands of Dollars)
Additions
------------------
Balance at Beginning Charged to Charged to Other Balance at End
Description of Period Income Accounts Deductions of Period
--------------------------------------------------------------------------------------------------------------------------------
Provision for uncollectible
accounts $508 $1,326 $2 $1,099 (Note) $737
Deferred credit:
Provision for property insurance $9,294 $1,244 - - $10,538
-------------------
Note: Represents write-off of accounts considered to be uncollectible, less
recoveries of amounts previously written off.
S-15
MISSISSIPPI POWER COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEAR ENDED DECEMBER 31, 1992
(Stated in Thousands of Dollars)
Additions
------------------
Balance at Beginning Charged to Charged to Other Balance at End
Description of Period Income Accounts Deductions of Period
---------------------------------------------------------------------------------------------------------------------------------
Provision for uncollectible
accounts $2,102 $1,173 - $2,767 (Note) $508
Deferred credit:
Provision for property insurance $8,216 $1,078 - - $9,294
-------------------
Note: Represents write-off of accounts considered to be uncollectible, less
recoveries of amounts previously written off.
S-16
SAVANNAH ELECTRIC AND POWER COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEAR ENDED DECEMBER 31, 1994
(Stated in Thousands of Dollars)
Additions
------------------
Balance at Beginning Charged to Charged to Other Balance at End
Description of Period Income Accounts Deductions of Period
---------------------------------------------------------------------------------------------------------------------------------
Provision for uncollectible
accounts $762 $419 - $315 (Note) $866
Deferred credit:
Provision for property insurance $1,000 $300 - - $1,300
-------------------
Note: Represents write-off of accounts receivable considered to be
uncollectible, less recoveries of amounts previously written off.
S-17
SAVANNAH ELECTRIC AND POWER COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEAR ENDED DECEMBER 31, 1993
(Stated in Thousands of Dollars)
Additions
------------------
Balance at Beginning Charged to Charged to Other Balance at End
Description of Period Income Accounts Deductions of Period
---------------------------------------------------------------------------------------------------------------------------------
Provision for uncollectible
accounts $536 $330 - $104 (Note) $762
Deferred credit:
Provision for property insurance $300 $700 - - $1,000
-------------------
Note: Represents write-off of accounts receivable considered to be
uncollectible, less recoveries of amounts previously written off.
S-18
SAVANNAH ELECTRIC AND POWER COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEAR ENDED DECEMBER 31, 1992
(Stated in Thousands of Dollars)
Additions
------------------
Balance at Beginning Charged to Charged to Other Balance at End
Description of Period Income Accounts Deductions of Period
---------------------------------------------------------------------------------------------------------------------------------
Provision for uncollectible
accounts $339 $455 - $258 (Note) $536
Deferred credit:
Provision for property insurance $300 - - - $300
--------------------
Note: Represents write-off of accounts receivable considered to be
uncollectible, less recoveries of amounts previously written off.
S-19
EXHIBIT INDEX
The following exhibits indicated by an asterisk preceding the exhibit
number are filed herewith. The balance of the exhibits have heretofore been
filed with the SEC, respectively, as the exhibits and in the file numbers
indicated and are incorporated herein by reference. Reference is made to a
duplicate list of exhibits being filed as a part of this Form 10-K, which list,
prepared in accordance with Item 601 of Regulation S-K of the SEC, immediately
precedes the exhibits being physically filed with this Form 10-K.
(3) Articles of Incorporation and By-Laws
SOUTHERN
(a) 1 - Composite Certificate of Incorporation of SOUTHERN,
reflecting all amendments thereto through January 5, 1994.
(Designated in Registration No. 33-3546 as Exhibit 4(a), in
Certificate of Notification, File No. 70-7341, as Exhibit A
and in Certificate of Notification, File No. 70-8181, as
Exhibit A.)
(a) 2 - By-laws of SOUTHERN as amended effective October 21, 1991,
and as presently in effect. (Designated in Form U-1, File
No. 70-8181, as Exhibit A-2.)
ALABAMA
(b) 1 - Charter of ALABAMA and amendments thereto through October
14, 1994. (Designated in Registration Nos. 2-59634 as
Exhibit 2(b), 2-60209 as Exhibit 2(c), 2-60484 as Exhibit
2(b), 2-70838 as Exhibit 4(a)-2, 2-85987 as Exhibit 4(a)-2,
33-25539 as Exhibit 4(a)-2, 33-43917 as Exhibit 4(a)-2, in
Form 8-K dated February 5, 1992, File No. 1-3164, as
Exhibit 4(b)-3, in Form 8-K dated July 8, 1992, File No. 1-
3164, as Exhibit 4(b)-3, in Form 8-K dated October 27,
1993, File No. 1-3164, as Exhibits 4(a) and 4(b), in Form
8-K dated November 16, 1993, File No. 1-3164, as Exhibit
4(a) and in Certificate of Notification, File No. 70-8191,
as Exhibit A.)
(b) 2 - By-laws of ALABAMA as amended effective July 23, 1993, and
as presently in effect. (Designated in Form U-1, File No.
70-8191, as Exhibit A-2.)
GEORGIA
(c) 1 - Charter of GEORGIA and amendments thereto through October
25, 1993. (Designated in Registration Nos. 2-63392 as
Exhibit 2(a)-2, 2-78913 as Exhibits 4(a)-(2) and 4(a)-(3),
2-93039 as Exhibit 4(a)-(2), 2-96810 as Exhibit 4(a)-2, 33-
141 as Exhibit 4(a)-(2), 33-1359 as Exhibit 4(a)(2), 33-
5405 as Exhibit 4(b)(2), 33-14367 as Exhibits 4(b)-(2) and
4(b)-(3), 33-22504 as Exhibits 4(b)-(2), 4(b)-(3) and 4(b)-
(4), in GEORGIA's Form 10-K for the year ended December 31,
1991, File No. 1-6468, as Exhibits 4(a)(2) and 4(a)(3), in
Registration No. 33-48895 as Exhibits 4(b)-(2) and 4(b)-
(3), in Form 8-K dated December 10, 1992, File No. 1-6468
as Exhibit 4(b), in Form 8-K dated June 17, 1993, File No.
1-6468, as Exhibit 4(b) and in Form 8-K dated October 20,
1993, File No. 1-6468, as Exhibit 4(b).)
E-1
(c) 2 - By-laws of GEORGIA as amended effective July 18, 1990, and
as presently in effect. (Designated in GEORGIA's Form 10-K
for the year ended December 31, 1990, File No. 1-6468, as
Exhibit 3.)
GULF
(d) 1 - Restated Articles of Incorporation of GULF and amendments
thereto through November 8, 1993. (Designated in
Registration No. 33-43739 as Exhibit 4(b)-1, in Form 8-K
dated January 15, 1992, File No. 0-2429, as Exhibit 1(b),
in Form 8-K dated August 18, 1992, File No. 0-2429, as
Exhibit 4(b)-2, in Form 8-K dated September 22, 1993, File
No. 0-2429, as Exhibit 4 and in Form 8-K dated November 3,
1993, File No. 0-2429, as Exhibit 4.)
(d) 2 - By-laws of GULF as amended effective February 25, 1994, and
as presently in effect. (Designated in GULF's Form 10-K
for the year ended December 31, 1993, as Exhibit 3(d)2.)
MISSISSIPPI
(e) 1 - Articles of incorporation of MISSISSIPPI, articles of
merger of Mississippi Power Company (a Maine corporation)
into MISSISSIPPI and articles of amendment to the articles
of incorporation of MISSISSIPPI through August 19, 1993.
(Designated in Registration No. 2-71540 as Exhibit 4(a)-1,
in Form U5S for 1987, File No. 30-222-2, as Exhibit B-10,
in Registration No. 33-49320 as Exhibit 4(b)-(1), in Form
8-K dated August 5, 1992, File No. 0-6849, as Exhibits
4(b)-2 and 4(b)-3, in Form 8-K dated August 4, 1993, File
No. 0-6849, as Exhibit 4(b)-3 and in Form 8-K dated August
18, 1993, File No. 0-6849, as Exhibit 4(b)-3.)
(e) 2 - By-laws of MISSISSIPPI as amended effective August 22,
1989, and as presently in effect. (Designated in
MISSISSIPPI's Form 10-K for the year ended December 31,
1989, as Exhibit 3(b).)
SAVANNAH
(f) 1 - Charter of SAVANNAH and amendments thereto through November
10, 1993. (Designated in Registration Nos. 33-25183 as
Exhibit 4(b)-(1), 33-45757 as Exhibit 4(b)-(2) and in Form
8-K dated November 9, 1993, File No. 1-5072, as Exhibit
4(b).)
(f) 2 - By-laws of SAVANNAH as amended effective February 16, 1994,
and as presently in effect. (Designated in SAVANNAH's Form
10-K for the year ended December 31, 1993, as Exhibit
3(f)2.)
E-2
(4) Instruments Describing Rights of Security Holders, Including Indentures
ALABAMA
(b) - Indenture dated as of January 1, 1942, between ALABAMA and
Chemical Bank, as Trustee, and indentures supplemental
thereto through that dated as of December 1, 1994.
(Designated in Registration Nos. 2-59843 as Exhibit 2(a)-2,
2-60484 as Exhibits 2(a)-3 and 2(a)-4, 2-60716 as Exhibit
2(c), 2-67574 as Exhibit 2(c), 2-68687 as Exhibit 2(c), 2-
69599 as Exhibit 4(a)-2, 2-71364 as Exhibit 4(a)-2, 2-73727
as Exhibit 4(a)-2, 33-5079 as Exhibit 4(a)-2, 33-17083 as
Exhibit 4(a)-2, 33-22090 as Exhibit 4(a)-2, in ALABAMA's
Form 10-K for the year ended December 31, 1990, File No. 1-
3164, as Exhibit 4(c), in Registration Nos. 33-43917 as
Exhibit 4(a)-2, 33-45492 as Exhibit 4(a)-2, 33-48885 as
Exhibit 4(a)-2, 33-48917 as Exhibit 4(a)-2, in Form 8-K
dated January 20, 1993, File No. 1-3436, as Exhibit 4(a)-3,
in Form 8-K dated February 17, 1993, File No. 1-3436, as
Exhibit 4(a)-3, in Form 8-K dated March 10, 1993, File No.
1-3436, as Exhibit 4(a)-3, in Certificate of Notification,
File No. 70-8069, as Exhibits A and B, in Form 8-K dated
June 24, 1993, File No. 1-3436, as Exhibit 4, in
Certificate of Notification, File No. 70-8069, as Exhibit
A, in Form 8-K dated November 16, 1993, File No. 1-3436, as
Exhibit 4(b), in Certificate of Notification, File No. 70-
8069, as Exhibits A and B, in Certificate of Notification,
File No. 70-8069, as Exhibit A, in Certificate of
Notification, File No. 70-8069, as Exhibit A and in Form 8-
K dated November 30, 1994, File No. 1-3436, as Exhibit 4.)
GEORGIA
(c) 1 - Indenture dated as of March 1, 1941, between GEORGIA and
Chemical Bank, as Trustee, and indentures supplemental
thereto dated as of March 1, 1941, March 3, 1941 (3
indentures), March 6, 1941 (139 indentures), March 1, 1946
(88 indentures) and December 1, 1947, through December 1,
1994. (Designated in Registration Nos. 2-4663 as Exhibits
B-3 and B-3(a), 2-7299 as Exhibit 7(a)-2, 2-61116 as
Exhibit 2(a)-3 and 2(a)-4, 2-62488 as Exhibit 2(a)-3, 2-
63393 as Exhibit 2(a)-4, 2-63705 as Exhibit 2(a)-3, 2-68973
as Exhibit 2(a)-3, 2-70679 as Exhibit 4(a)-(2), 2-72324 as
Exhibit 4(a)-2, 2-73987 as Exhibit 4(a)-(2), 2-77941 as
Exhibits 4(a)-(2) and 4(a)-(3), 2-79336 as Exhibit 4(a)-
(2), 2-81303 as Exhibit 4(a)-(2), 2-90105 as Exhibit 4(a)-
(2), 33-5405 as Exhibit 4(a)-(2), 33-14367 as Exhibits
4(a)-(2) and 4(a)-(3), 33-22504 as Exhibits 4(a)-(2), 4(a)-
(3) and 4(a)-(4), 33-32420 as Exhibit 4(a)-(2), 33-35683
as Exhibit 4(a)-(2), in GEORGIA's Form 10-K for the year
ended December 31, 1990, File No. 1-6468, as Exhibit
4(a)(3), in Form 10-K for the year ended December 31, 1991,
File No. 1-6468, as Exhibit 4(a)(5), in Registration No.
33-48895 as Exhibit 4(a)-(2), in Form 8-K dated August 26,
1992, File No. 1-6468, as Exhibit 4(a)-(3), in Form 8-K
dated September 9, 1992, File No. 1-6468, as Exhibits 4(a)-
(3) and 4(a)-(4), in Form 8-K dated September 23, 1992,
File No. 1-6468, as Exhibit 4(a)-(3), in Form 8-A dated
October 12, 1992, as Exhibit 2(b), in Form 8-K dated
January 27, 1993, File No. 1-6468, as Exhibit 4(a)-(3), in
Registration No. 33-49661 as Exhibit 4(a)-(2), in Form 8-K
dated July 26, 1993, File No. 1-6468, as Exhibit 4, in
Certificate of Notification, File No. 70-7832, as Exhibit
M, in Certificate of Notification, File No. 70-7832, as
Exhibit C, in Certificate of Notification, File No. 70-
7832, as Exhibits K and L, in Certificate of Notification,
File No. 70-8443, as Exhibit C, in Certificate of
Notification, File No. 70-8443, as Exhibit C, in
Certificate of Notification, File No. 70-8443, as Exhibit
E, in Certificate of Notification, File No. 70-8443, as
Exhibit E and in Certificate of Notification, File No. 70-
8443, as Exhibit E.)
E-3
* (c) 2 - Supplemental Indenture dated as of June 1, 1994, between
GEORGIA and Chemical Bank, as Trustee.
* (c) 3 - Supplemental Indenture dated as of September 1, 1994,
between GEORGIA and Chemical Bank, as Trustee.
(c) 4 - Indenture dated as of December 1, 1994, between GEORGIA and
Trust Company Bank, as Trustee. (Designated in Certificate
of Notification, File No. 70-8461, as Exhibit E.)
(c) 5 - First Supplemental Indenture dated as of December 15, 1994,
between GEORGIA and Trust Company Bank, as Trustee.
(Designated in Certificate of Notification, File No. 70-
8461, as Exhibit F.)
GULF
(d) - Indenture dated as of September 1, 1941, between GULF and
The Chase Manhattan Bank (National Association), as
Trustee, and indentures supplemental thereto through
September 1, 1994. (Designated in Registration Nos. 2-4833
as Exhibit B-3, 2-62319 as Exhibit 2(a)-3, 2-63765 as
Exhibit 2(a)-3, 2-66260 as Exhibit 2(a)-3, 33-2809 as
Exhibit 4(a)-2, 33-43739 as Exhibit 4(a)-2, in GULF's Form
10-K for the year ended December 31, 1991, File No. 0-2429,
as Exhibit 4(b), in Form 8-K dated August 18, 1992, File
No. 0-2429, as Exhibit 4(a)-3, in Registration No. 33-50165
as Exhibit 4(a)-2, in Form 8-K dated July 12, 1993, File
No. 0-2429, as Exhibit 4, in Certificate of Notification,
File No. 70-8229, as Exhibit A and in Certificate of
Notification, File No. 70-8229, as Exhibits E and F.)
MISSISSIPPI
(e) - Indenture dated as of September 1, 1941, between
MISSISSIPPI and Bankers Trust Company, as Successor
Trustee, and indentures supplemental thereto through March
1, 1994. (Designated in Registration Nos. 2-4834 as
Exhibit B-3, 2-62965 as Exhibit 2(b)-2, 2-66845 as Exhibit
2(b)-2, 2-71537 as Exhibit 4(a)-(2), 33-5414 as Exhibit
4(a)-(2), 33-39833 as Exhibit 4(a)-2, in MISSISSIPPI's Form
10-K for the year ended December 31, 1991, File No. 0-6849,
as Exhibit 4(b), in Form 8-K dated August 5, 1992, File No.
0-6849, as Exhibit 4(a)-2, in Second Certificate of
Notification, File No. 70-7941, as Exhibit I, in
MISSISSIPPI's Form 8-K dated February 26, 1993, File No. 0-
6849, as Exhibit 4(a)-2, in Certificate of Notification,
File No. 70-8127, as Exhibit A, in Form 8-K dated June 22,
1993, File No. 0-6849, as Exhibit 1, in Certificate of
Notification, File No. 70-8127, as Exhibit A and in Form 8-
K dated March 8, 1994, File No. 0-6849, as Exhibit 4.)
E-4
SAVANNAH
(f) - Indenture dated as of March 1, 1945, between SAVANNAH and
NationsBank of Georgia, National Association, as Trustee,
and indentures supplemental thereto through July 1, 1993.
(Designated in Registration Nos. 33-25183 as Exhibit 4(a)-
(1), 33-41496 as Exhibit 4(a)-(2), 33-45757 as Exhibit
4(a)-(2), in SAVANNAH's Form 10-K for the year ended
December 31, 1991, File No. 1-5072, as Exhibit 4(b), in
Form 8-K dated July 8, 1992, File No. 1-5072, as Exhibit
4(a)-3, in Registration No. 33-50587 as Exhibit 4(a)-(2)
and in Form 8-K dated July 22, 1993, File No. 1-5072, as
Exhibit 4.)
(10) Material Contracts
SOUTHERN
(a) 1 - Service contracts dated as of January 1, 1984 and Amendment
No. 1 dated as of September 6, 1985, between SCS and
ALABAMA, GEORGIA, GULF, MISSISSIPPI, SEGCO and SOUTHERN.
(Designated in SOUTHERN's Form 10-K for the year ended
December 31, 1984, File No. 1-3526, as Exhibit 10(a) and in
SOUTHERN's Form 10-K for the year ended December 31, 1985,
File No. 1-3526, as Exhibit 10(a)(3).)
(a) 2 - Service contract dated as of July 17, 1981, between SCS and
SEI. (Designated in SOUTHERN's Form 10-K for the year
ended December 31, 1985, File No. 1-3526, as Exhibit
10(a)(2).)
(a) 3 - Service contract dated as of March 3, 1988, between SCS and
SAVANNAH. (Designated in SAVANNAH's Form 10-K for the year
ended December 31, 1987, File No. 1-5072, as Exhibit 10-p.)
(a) 4 - Service contract dated as of January 15, 1991, between SCS
and Southern Nuclear. (Designated in SOUTHERN's Form 10-K
for the year ended December 31, 1991, File No. 1-3526, as
Exhibit 10(a)(4).)
(a) 5 - Interchange contract dated October 28, 1988, effective
January 1, 1989, between ALABAMA, GEORGIA, GULF,
MISSISSIPPI, SAVANNAH and SCS. (Designated in SAVANNAH's
Form 10-K for the year ended December 31, 1988, File No.
1-5072, as Exhibit 10(b).)
(a) 6 - Agreement dated as of January 27, 1959 and Amendment No. 1
dated as of October 27, 1982, among SEGCO, ALABAMA and
GEORGIA. (Designated in Registration No. 2-59634 as
Exhibit 5(c) and in GEORGIA's Form 10-K for the year ended
December 31, 1982, File No. 1-6468, as Exhibit 10(d)(2).)
E-5
(a) 7 - Joint Committee Agreement dated as of August 27, 1976,
among GEORGIA, OPC, MEAG and Dalton. (Designated in
Registration No. 2-61116 as Exhibit 5(d).)
(a) 8 - Edwin I. Hatch Nuclear Plant Purchase and Ownership
Participation Agreement dated as of January 6, 1975,
between GEORGIA and OPC. (Designated in Form 8-K for
January, 1975, File No. 1-6468, as Exhibit (b)(1).)
(a) 9 - Edwin I. Hatch Nuclear Plant Operating Agreement dated as
of January 6, 1975, between GEORGIA and OPC. (Designated
in Form 8-K for January, 1975, File No. 1-6468, as Exhibit
(b)(3).)
(a) 10 - Revised and Restated Integrated Transmission System
Agreement dated as of November 12, 1990, between GEORGIA
and OPC. (Designated in GEORGIA's Form 10-K for the year
ended December 31, 1990, File No. 1-6468, as Exhibit
10(g).)
(a) 11 - Plant Hal Wansley Purchase and Ownership Participation
Agreement dated as of March 26, 1976, between GEORGIA and
OPC. (Designated in Certificate of Notification, File No.
70-5592, as Exhibit A.)
(a) 12 - Plant Hal Wansley Operating Agreement dated as of March 26,
1976, between GEORGIA and OPC. (Designated in Certificate
of Notification, File No. 70-5592, as Exhibit B.)
(a) 13 - Edwin I. Hatch Nuclear Plant Purchase and Ownership
Participation Agreement dated as of August 27, 1976,
between GEORGIA, MEAG and Dalton. (Designated in Form 8-K
dated as of June 13, 1977, File No. 1-6468, as Exhibit
(b)(1).)
(a) 14 - Edwin I. Hatch Nuclear Plant Operating Agreement dated as
of August 27, 1976, between GEORGIA, MEAG and Dalton.
(Designated in Form 8-K for February 1977, File No. 1-6468,
as Exhibit (b)(2).)
(a) 15 - Alvin W. Vogtle Nuclear Units Number One and Two Purchase
and Ownership Participation Agreement dated as of August
27, 1976 and Amendment No. 1 dated as of January 18, 1977,
among GEORGIA, OPC, MEAG and Dalton. (Designated in Form
U-1, File No. 70-5792, as Exhibit B-1 and in Form 8-K for
January 1977, File No. 1-6468, as Exhibit (B)(3).)
(a) 16 - Alvin W. Vogtle Nuclear Units Number One and Two Operating
Agreement dated as of August 27, 1976, among GEORGIA, OPC,
MEAG and Dalton. (Designated in Form U-1, File No.
70-5792, as Exhibit B-2.)
(a) 17 - Alvin W. Vogtle Nuclear Units Number One and Two Purchase,
Amendment, Assignment and Assumption Agreement dated as of
November 16, 1983, between GEORGIA and MEAG. (Designated
in GEORGIA's Form 10-K for the year ended December 31,
1983, File No. 1-6468, as Exhibit 10(k)(4).)
E-6
(a) 18 - Plant Hal Wansley Purchase and Ownership Participation
Agreement dated as of August 27, 1976, between GEORGIA and
MEAG. (Designated in Form 8-K dated as of July 5, 1977,
File No. 1-6468, as Exhibit (b)(2).)
(a) 19 - Plant Hal Wansley Operating Agreement dated as of August
27, 1976, between GEORGIA and MEAG. (Designated in Form
8-K dated as of July 5, 1977, File No. 1-6468, as Exhibit
(b)(4).)
(a) 20 - Integrated Transmission System Agreement dated as of August
27, 1976, between GEORGIA and Dalton. (Designated in Form
8-K dated as of July 5, 1977, File No. 1-6468, as Exhibit
(b)(8).)
(a) 21 - Integrated Transmission System Agreement dated as of August
27, 1976, between GEORGIA and MEAG. (Designated in Form
8-K for February 1977, File No. 1-6468, as Exhibit (b)(4).)
(a) 22 - Plant Hal Wansley Purchase and Ownership Participation
Agreement dated as of April 19, 1977, between GEORGIA and
Dalton. (Designated in Form 8-K dated as of June 13, 1977,
File No. 1-6468, as Exhibit (b)(3).)
(a) 23 - Plant Hal Wansley Operating Agreement dated as of April 19,
1977, between GEORGIA and Dalton. (Designated in Form 8-K
dated as of June 13, 1977, File No. 1-6468, as Exhibit
(b)(7).)
(a) 24 - Plant Robert W. Scherer Units Number One and Two Purchase
and Ownership Participation Agreement dated as of May 15,
1980, Amendment No. 1 dated as of December 30, 1985,
Amendment No. 2 dated as of July 1, 1986, Amendment No. 3
dated as of August 1, 1988 and Amendment No. 4 dated as of
December 31, 1990, among GEORGIA, OPC, MEAG and Dalton.
(Designated in Form U-1, File No. 70-6481, as Exhibit B-3,
in SOUTHERN's Form 10-K for the year ended December 31,
1987, File No. 1-3526, as Exhibit 10(o)(2), in SOUTHERN's
Form 10-K for the year ended December 31, 1989, File No. 1-
3526, as Exhibit 10(n)(2) and in SOUTHERN's Form 10-K for
the year ended December 31, 1993, File No. 1-3526, as
Exhibit 10(a)54.)
(a) 25 - Plant Robert W. Scherer Units Number One and Two Operating
Agreement dated as of May 15, 1980, Amendment No. 1 dated
as of December 3, 1985 and Amendment No. 2 dated as of
December 31, 1990, among GEORGIA, OPC, MEAG and Dalton.
(Designated in Form U-1, File No. 70-6481, as Exhibit B-4,
in SOUTHERN's Form 10-K for the year ended December 31,
1987, File No. 1-3526, as Exhibit 10(o)(4) and in
SOUTHERN's Form 10-K for the year ended December 31, 1993,
File No. 1-3526, as Exhibit 10(a)55.)
(a) 26 - Plant Robert W. Scherer Purchase, Sale and Option Agreement
dated as of May 15, 1980, between GEORGIA and MEAG.
(Designated in Form U-1, File No. 70-6481, as Exhibit B-1.)
E-7
(a) 27 - Plant Robert W. Scherer Purchase and Sale Agreement dated
as of May 16, 1980, between GEORGIA and Dalton.
(Designated in Form U-1, File No. 70-6481, as Exhibit B-2.)
(a) 28 - Plant Robert W. Scherer Unit Number Three Purchase and
Ownership Participation Agreement dated as of March 1,
1984, Amendment No. 1 dated as of July 1, 1986 and
Amendment No. 2 dated as of August 1, 1988, between GEORGIA
and GULF. (Designated in Form U-1, File No. 70-6573, as
Exhibit B-4, in SOUTHERN's Form 10-K for the year ended
December 31, 1987, as Exhibit 10(o)(2) and in SOUTHERN's
Form 10-K for the year ended December 31, 1989, as Exhibit
10(n)(2).)
(a) 29 - Plant Robert W. Scherer Unit Number Three Operating
Agreement dated as of March 1, 1984, between GEORGIA and
GULF. (Designated in Form U-1, File No. 70-6573, as
Exhibit B-5.)
(a) 30 - Plant Robert W. Scherer Unit No. Four Amended and Restated
Purchase and Ownership Participation Agreement by and among
GEORGIA, FP&L and JEA, dated as of December 31, 1990.
(Designated in Form U-1, File No. 70-7843, as Exhibit B-1.)
(a) 31 - Plant Robert W. Scherer Unit No. Four Operating Agreement
by and among GEORGIA, FP&L and JEA, dated as of December
31, 1990. (Designated in Form U-1, File No. 70-7843, as
Exhibit B-2.)
(a) 32 - Amended and Restated Unit Power Sales Agreement dated
February 18, 1982 and Amendment No. 1 dated May 18, 1982,
between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI and
SCS. (Designated in MISSISSIPPI's Form 10-K for the year
ended December 31, 1981, File No. 0-6849, as Exhibit
10(c)(2) and in GEORGIA's Form 10-K for the year ended
December 31, 1982, File No. 1-6468, as Exhibit 10(r)(3).)
(a) 33 - Amended and Restated Unit Power Sales Agreement dated May
19, 1982, Amendment No. 1 dated August 30, 1984 and
Amendment No. 2 dated October 30, 1987, between JEA and
ALABAMA, GEORGIA, GULF, MISSISSIPPI and SCS. (Designated
in GEORGIA's Form 10-K for the year ended December 31,
1982, File No. 1-6468, as Exhibit 10(s)(2), in SOUTHERN's
Form 10-K for the year ended December 31, 1984, File No.
1-3526, as Exhibit 10(r)(2) and in GEORGIA's Form 10-K for
the year ended December 31, 1990, File No. 1-6468, as
Exhibit 10(s)(2).)
(a) 34 - Unit Power Sales Agreement dated July 19, 1988, between FPC
and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS.
(Designated in SAVANNAH's Form 10-K for the year ended
December 31, 1988, File No. 1-5072, as Exhibit 10(d).)
E-8
(a) 35 - Amended Unit Power Sales Agreement dated July 20, 1988,
between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
SAVANNAH and SCS. (Designated in SAVANNAH's Form 10-K for
the year ended December 31, 1988, File No. 1-5072, as
Exhibit 10(e).)
(a) 36 - Amended Unit Power Sales Agreement dated August 17, 1988,
between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
SAVANNAH and SCS. (Designated in SAVANNAH's Form 10-K for
the year ended December 31, 1988, File No. 1-5072, as
Exhibit 10(f).)
(a) 37 - Unit Power Sales Agreement dated December 8, 1990, between
Tallahassee and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
SAVANNAH and SCS. (Designated in GEORGIA's Form 10-K for
the year ended December 31, 1990, File No. 1-6468, as
Exhibit 10(x).)
(a) 38 - The Southern Company Executive Stock Plan For the Southern
Electric System and the First Amendment thereto.
(Designated in Registration No. 33-30171 as Exhibit 4(c).)
(a) 39 - Transition Energy Agreement dated December 31, 1990,
between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
SAVANNAH and SCS. (Designated in GULF's Form 10-K for the
year ended December 31, 1991, File No. 0-2429, as Exhibit
10(1).)
(a) 40 - Transition Energy Agreement dated December 31, 1990,
between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
SAVANNAH and SCS. (Designated in GULF's Form 10-K for the
year ended December 31, 1991, File No. 0-2429, as Exhibit
10(m).)
(a) 41 - Rocky Mountain Pumped Storage Hydroelectric Project
Ownership Participation Agreement dated November 18, 1988,
between OPC and GEORGIA. (Designated in GEORGIA's Form
10-K for the year ended December 31, 1988, File No. 1-6468,
as Exhibit 10(x).)
(a) 42 - Rocky Mountain Pumped Storage Hydroelectric Project
Operating Agreement dated November 18, 1988, between OPC
and GEORGIA. (Designated in GEORGIA's Form 10-K for the
year ended December 31, 1988, File No. 1-6468, as Exhibit
10(y).)
(a) 43 - Purchase and Ownership Agreement for Joint Ownership
Interest in the James H. Miller, Jr. Steam Electric
Generating Plant Units One and Two dated November 18, 1988,
between ALABAMA and AEC. (Designated in Form U-1, File No.
70-7609, as Exhibit B-1.)
(a) 44 - Operating Agreement for Joint Ownership Interest in the
James H. Miller, Jr. Steam Electric Generating Plant Units
One and Two dated November 18, 1988, between ALABAMA and
AEC. (Designated in Form U-1, File No. 70-7609, as Exhibit
B-2.)
E-9
(a) 45 - Transmission Facilities Agreement dated February 25, 1982,
Amendment No. 1 dated May 12, 1982 and Amendment No. 2
dated December 6, 1983, between Gulf States and
MISSISSIPPI. (Designated in MISSISSIPPI's Form 10-K for
the year ended December 31, 1981, File No. 0-6849, as
Exhibit 10(f), in MISSISSIPPI's Form 10-K for the year
ended December 31, 1982, File No. 0-6849, as Exhibit
10(f)(2) and in MISSISSIPPI's Form 10-K for the year ended
December 31, 1983, File No. 0-6849, as Exhibit 10(f)(3).)
(a) 46 - Form of commitment agreement, Amendment No. 1 and Amendment
No. 2 with respect to SOUTHERN, ALABAMA, GEORGIA and
MISSISSIPPI revolving credits. (Designated in Form U-1,
File No. 70-7738, as Exhibit A-5 and in Form U-1, File No.
70-7937, as A-5(b).)
(a) 47 - Block Power Sale Agreement between GEORGIA and OPC dated as
of November 12, 1990. (Designated in GEORGIA's Form 10-K
for the year ended December 31, 1990, File No. 1-6468, as
Exhibit 10(cc).)
(a) 48 - Coordination Services Agreement between GEORGIA and OPC
dated as of November 12, 1990. (Designated in GEORGIA's
Form 10-K for the year ended December 31, 1990, File No.
1-6468, as Exhibit 10(dd).)
(a) 49 - Amended and Restated Nuclear Managing Board Agreement for
Plant Hatch and Plant Vogtle among GEORGIA, OPC, MEAG and
Dalton dated as of July 1, 1993. (Designated in SOUTHERN's
Form 10-K for the year ended December 31, 1993, File No. 1-
3526, as Exhibit 10(a)49.)
(a) 50 - Integrated Transmission System Agreement, Power Sale and
Coordination Umbrella Agreement between GEORGIA and OPC
dated as of November 12, 1990. (Designated in GEORGIA's
Form 10-K for the year ended December 31, 1990, File No.
1-6468, as Exhibit 10(ff).)
(a) 51 - Revised and Restated Integrated Transmission System
Agreement between GEORGIA and Dalton dated as of December
7, 1990. (Designated in GEORGIA's Form 10-K for the year
ended December 31, 1990, File No. 1-6468, as Exhibit
10(gg).)
(a) 52 - Revised and Restated Integrated Transmission System
Agreement between GEORGIA and MEAG dated as of December 7,
1990. (Designated in GEORGIA's Form 10-K for the year
ended December 31, 1990, File No. 1-6468, as Exhibit
10(hh).)
(a) 53 - Long Term Transmission Service Agreement between Entergy
Power, Inc. and ALABAMA, MISSISSIPPI and SCS. (Designated
in SOUTHERN's Form 10-K for the year ended December 31,
1992, File No. 1-3526, as Exhibit 10(a)53.)
E-10
(a) 54 - Plant Scherer Managing Board Agreement dated as of December
31, 1990 among GEORGIA, OPC, MEAG, Dalton, GULF, FP&L and
JEA. (Designated in SOUTHERN's Form 10-K for the year
ended December 31, 1993, File No. 1-3526, as Exhibit
10(a)56.)
(a) 55 - Plant McIntosh Combustion Turbine Purchase and Ownership
Participation Agreement between GEORGIA and SAVANNAH dated
as of December 15, 1992. (Designated in SOUTHERN's Form
10-K for the year ended December 31, 1993, File No. 1-3526,
as Exhibit 10(a)57.)
(a) 56 - Plant McIntosh Combustion Turbine Operating Agreement
between GEORGIA and SAVANNAH dated as of December 15, 1992.
(Designated in SOUTHERN's Form 10-K for the year ended
December 31, 1993, File No. 1-3526, as Exhibit 10(a)58.)
(a) 57 - Power Purchase Agreement dated as of December 3, 1993
between GEORGIA and FPC. (Designated in SOUTHERN's Form 10-
K for the year ended December 31, 1993, File No. 1-3526, as
Exhibit 10(a)59.)
* (a) 58 - Service Contract dated as of December 12, 1994, between SCS
and Mobile Energy Services Company, Inc.
(a) 59 - The Southern Company Outside Directors Stock Plan.
(Designated in Registration No. 33-54415 as Exhibit 4(c).)
* (a) 60 - Amendment No. 1 dated as of June 15, 1994, to the Plant
Robert W. Scherer Unit Number Four Amended and Restated
Purchase and Ownership Participation Agreement.
* (a) 61 - Amendment No. 1 dated as of June 15, 1994, to the Plant
Robert W. Scherer Unit Number Four Operating Agreement.
(a) 62 - Operating Agreement for the Joseph M. Farley Nuclear Plant
between ALABAMA and Southern Nuclear dated as of December
23, 1991. (Designated in Form U-1, File No. 70-7530, as
Exhibit B-7.)
(a) 63 - Nuclear Services Agreement between Southern Nuclear and
GEORGIA dated as of October 31, 1991. (Designated in Form
U-1, File No. 70-7530, as Exhibit B-6.)
(a) 64 - Nuclear Managing Board Agreement among GEORGIA, OPC, MEAG
and Dalton dated as of November 12, 1990. (Designated in
GEORGIA's Form 10-K for the year ended December 31, 1990,
File No. 1-6468, as Exhibit 10(ee).)
* (a) 65 - The Southern Company Productivity Improvement Plan, Amended
and Restated effective January 1, 1994.
* (a) 66 - The Southern Company Executive Productivity Improvement
Plan, effective January 1, 1994.
E-11
(a) 67 - The Southern Company Employee Savings Plan, Amended and
Restated effective January 1, 1989. (Designated in
Registration No. 33-23152 as Exhibit 4(c).)
(a) 68 - The Southern Company Employee Stock Ownership Plan, Amended
and Restated effective January 1, 1989. (Designated in
Form U-1, File No. 70-7654, as Exhibit B-1 and in Form U-1,
File No. 70-8435, as Exhibit B-4(b).)
* (a) 69 - Pension Plan For Employees of ALABAMA, Amended and Restated
effective as of January 1, 1989.
* (a) 70 - Pension Plan For Employees of GEORGIA, Amended and Restated
effective as of January 1, 1989.
* (a) 71 - Pension Plan For Employees of SCS, Amended and Restated
effective as of January 1, 1989.
* (a) 72 - The Southern Company Performance Pay Plan, Amended and
Restated effective January 1, 1993.
* (a) 73 - Supplemental Benefit Plan for ALABAMA.
* (a) 74 - Supplemental Benefit Plan for GEORGIA.
* (a) 75 - Supplemental Benefit Plan for SCS and SEI.
* (a) 76 - The Deferred Compensation Plan for the Directors of The
Southern Company.
* (a) 77 - The Southern Company Outside Directors Pension Plan.
* (a) 78 - The Deferred Compensation Plan for the Southern Electric
System.
ALABAMA
(b) 1 - Service contracts dated as of January 1, 1984 and Amendment
No. 1 dated as of September 6, 1985, between SCS and
ALABAMA, GEORGIA, GULF, MISSISSIPPI, SEGCO and SOUTHERN.
See Exhibit 10(a)1 herein.
(b) 2 - Interchange contract dated October 28, 1988, effective
January 1, 1989, between ALABAMA, GEORGIA, GULF,
MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)5 herein.
(b) 3 - Agreement dated as of January 27, 1959 and Amendment No. 1
dated as of October 27, 1982, among SEGCO, ALABAMA and
GEORGIA. See Exhibit 10(a)6 herein.
(b) 4 - Amended and Restated Unit Power Sales Agreement dated
February 18, 1982 and Amendment No. 1 dated May 18, 1982,
between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI and
SCS. See Exhibit 10(a)32 herein.
E-12
(b) 5 - Amended and Restated Unit Power Sales Agreement dated May
19, 1982, Amendment No. 1, dated August 30, 1984 and
Amendment No. 2, dated October 30, 1987, between JEA and
ALABAMA, GEORGIA, GULF, MISSISSIPPI and SCS. See Exhibit
10(a)33 herein.
(b) 6 - Unit Power Sales Agreement dated July 19, 1988, between FPC
and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS.
See Exhibit 10(a)34 herein.
(b) 7 - Amended Unit Power Sales Agreement dated July 20, 1988,
between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
SAVANNAH and SCS. See Exhibit 10(a)35 herein.
(b) 8 - Amended Unit Power Sales Agreement dated August 17, 1988,
between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
SAVANNAH and SCS. See Exhibit 10(a)36 herein.
(b) 9 - Unit Power Sales Agreement dated December 8, 1990, between
Tallahassee and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
SAVANNAH and SCS. See Exhibit 10(a)37 herein.
(b) 10 - Transition Energy Agreement dated December 31, 1990,
between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
SAVANNAH and SCS. See Exhibit 10(a)39 herein.
(b) 11 - Transition Energy Agreement dated December 31, 1990,
between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
SAVANNAH and SCS. See Exhibit 10(a)40 herein.
(b) 12 - Firm Power Purchase Contract between ALABAMA and AMEA.
(Designated in Certificate of Notification, File No. 70-
7212, as Exhibit B.)
(b) 13 - 1991 Firm Power Purchase Contract between ALABAMA and AMEA.
(Designated in Form U-1, File No. 70-7873, as Exhibit B-1.)
(b) 14 - Purchase and Ownership Agreement for Joint Ownership
Interest in the James H. Miller, Jr. Steam Electric
Generating Plant Units One and Two dated November 18, 1988,
between ALABAMA and AEC. See Exhibit 10(a)43 herein.
(b) 15 - Operating Agreement for Joint Ownership Interest in the
James H. Miller, Jr. Steam Electric Generating Plant Units
One and Two dated November 18, 1988, between ALABAMA and
AEC. See Exhibit 10(a)44 herein.
(b) 16 - Form of commitment agreement, Amendment No. 1 and Amendment
No. 2 with respect to SOUTHERN, ALABAMA, GEORGIA and
MISSISSIPPI revolving credits. See Exhibit 10(a)46 herein.
E-13
(b) 17 - Long Term Transmission Service Agreement between Entergy
Power, Inc. and ALABAMA, MISSISSIPPI and SCS. See Exhibit
10(a)53 herein.
* (b) 18 - Amendment No. 2 dated November 4, 1993 and effective June
1, 1994, to Agreement dated January 27, 1959, among SEGCO,
ALABAMA and GEORGIA.
(b) 19 - Operating Agreement for the Joseph M. Farley Nuclear Plant
between ALABAMA and Southern Nuclear dated as of December
23, 1991. See Exhibit 10(a)62 herein.
* (b) 20 - The Southern Company Productivity Improvement Plan, Amended
and Restated effective January 1, 1994. See Exhibit
10(a)65 herein.
* (b) 21 - The Southern Company Executive Productivity Improvement
Plan, effective January 1, 1994. See Exhibit 10(a)66
herein.
(b) 22 - The Southern Company Employee Savings Plan, Amended and
Restated effective January 1, 1989. See Exhibit 10(a)67
herein.
(b) 23 - The Southern Company Employee Stock Ownership Plan, Amended
and Restated effective January 1, 1989. See Exhibit
10(a)68 herein.
* (b) 24 - Pension Plan For Employees of ALABAMA, Amended and Restated
effective as of January 1, 1989. See Exhibit 10(a)69
herein.
* (b) 25 - The Southern Company Performance Pay Plan, Amended and
Restated effective January 1, 1993. See Exhibit 10(a)72
herein.
* (b) 26 - Supplemental Benefit Plan for ALABAMA. See Exhibit 10(a)73
herein.
* (b) 27 - The Deferred Compensation Plan for the Southern Electric
System. See Exhibit 10(a)78 herein.
* (b) 28 - The Southern Company Outside Directors Pension Plan. See
Exhibit 10(a)77 herein.
GEORGIA
(c) 1 - Service contracts dated as of January 1, 1984 and Amendment
No. 1 dated as of September 6, 1985, between SCS and
ALABAMA, GEORGIA, GULF, MISSISSIPPI, SEGCO and SOUTHERN.
See Exhibit 10(a)1 herein.
(c) 2 - Interchange contract dated October 28, 1988, effective
January 1, 1989, between ALABAMA, GEORGIA, GULF,
MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)5 herein.
E-14
(c) 3 - Agreement dated as of January 27, 1959 and Amendment No. 1
dated as of October 27, 1982, among SEGCO, ALABAMA and
GEORGIA. See Exhibit 10(a)6 herein.
(c) 4 - Joint Committee Agreement dated as of August 27, 1976,
among GEORGIA, OPC, MEAG and Dalton. See Exhibit 10(a)7
herein.
(c) 5 - Edwin I. Hatch Nuclear Plant Purchase and Ownership
Participation Agreement dated as of January 6, 1975,
between GEORGIA and OPC. See Exhibit 10(a)8 herein.
(c) 6 - Edwin I. Hatch Nuclear Plant Operating Agreement dated as
of January 6, 1975, between GEORGIA and OPC. See Exhibit
10(a)9 herein.
(c) 7 - Revised and Restated Integrated Transmission System
Agreement dated as of November 12, 1990, between GEORGIA
and OPC. See Exhibit 10(a)10 herein.
(c) 8 - Plant Hal Wansley Purchase and Ownership Participation
Agreement dated as of March 26, 1976, between GEORGIA and
OPC. See Exhibit 10(a)11 herein.
(c) 9 - Plant Hal Wansley Operating Agreement dated as of March 26,
1976, between GEORGIA and OPC. See Exhibit 10(a)12 herein.
(c) 10 - Edwin I. Hatch Nuclear Plant Purchase and Ownership
Participation Agreement dated as of August 27, 1976,
between GEORGIA, MEAG and Dalton. See Exhibit 10(a)13
herein.
(c) 11 - Edwin I. Hatch Nuclear Plant Operating Agreement dated as
of August 27, 1976, between GEORGIA, MEAG and Dalton. See
Exhibit 10(a)14 herein.
(c) 12 - Alvin W. Vogtle Nuclear Units Number One and Two Purchase
and Ownership Participation Agreement dated as of August
27, 1976 and Amendment No. 1 dated as of January 18, 1977,
among GEORGIA, OPC, MEAG and Dalton. See Exhibit 10(a)15
herein.
(c) 13 - Alvin W. Vogtle Nuclear Units Number One and Two Operating
Agreement dated as of August 27, 1976, among GEORGIA, OPC,
MEAG and Dalton. See Exhibit 10(a)16 herein.
(c) 14 - Alvin W. Vogtle Nuclear Units Number One and Two Purchase,
Amendment, Assignment and Assumption Agreement dated as of
November 16, 1983, between GEORGIA and MEAG. See Exhibit
10(a)17 herein.
(c) 15 - Plant Hal Wansley Purchase and Ownership Participation
Agreement dated as of August 27, 1976, between GEORGIA and
MEAG. See Exhibit 10(a)18 herein.
E-15
(c) 16 - Plant Hal Wansley Operating Agreement dated as of August
27, 1976, between GEORGIA and MEAG. See Exhibit 10(a)19
herein.
(c) 17 - Integrated Transmission System Agreement dated as of August
27, 1976, between GEORGIA and Dalton. See Exhibit 10(a)20
herein.
(c) 18 - Integrated Transmission System Agreement dated as of August
27, 1976, between GEORGIA and MEAG. See Exhibit 10(a)21
herein.
(c) 19 - Plant Hal Wansley Purchase and Ownership Participation
Agreement dated as of April 19, 1977, between GEORGIA and
Dalton. See Exhibit 10(a)22 herein.
(c) 20 - Plant Hal Wansley Operating Agreement dated as of April 19,
1977, between GEORGIA and Dalton. See Exhibit 10(a)23
herein.
(c) 21 - Plant Robert W. Scherer Units Number One and Two Purchase
and Ownership Participation Agreement dated as of May 15,
1980, Amendment No. 1 dated as of December 30, 1985,
Amendment No. 2 dated as of July 1, 1986, Amendment No. 3
dated as of August 1, 1988 and Amendment No. 4 dated as of
December 31, 1990, among GEORGIA, OPC, MEAG and Dalton.
See Exhibit 10(a)24 herein.
(c) 22 - Plant Robert W. Scherer Units Number One and Two Operating
Agreement dated as of May 15, 1980, Amendment No. 1 dated
as of December 3, 1985 and Amendment No. 2 dated as of
December 31, 1990, among GEORGIA, OPC, MEAG and Dalton.
See Exhibit 10(a)25 herein.
(c) 23 - Plant Robert W. Scherer Purchase, Sale and Option Agreement
dated as of May 15, 1980, between GEORGIA and MEAG. See
Exhibit 10(a)26 herein.
(c) 24 - Plant Robert W. Scherer Purchase and Sale Agreement dated
as of May 16, 1980, between GEORGIA and Dalton. See
Exhibit 10(a)27 herein.
(c) 25 - Plant Robert W. Scherer Unit Number Three Purchase and
Ownership Participation Agreement dated as of March 1,
1984, Amendment No. 1 dated as of July 1, 1986 and
Amendment No. 2 dated as of August 1, 1988, between GEORGIA
and GULF. See Exhibit 10(a)28 herein.
(c) 26 - Plant Robert W. Scherer Unit Number Three Operating
Agreement dated as of March 1, 1984, between GEORGIA and
GULF. See Exhibit 10(a)29 herein.
(c) 27 - Plant Robert W. Scherer Unit No. Four Amended and Restated
Purchase and Ownership Participation Agreement by and among
GEORGIA, FP&L and JEA dated as of December 31, 1990. See
Exhibit 10(a)30 herein.
(c) 28 - Plant Robert W. Scherer Unit No. Four Operating Agreement
by and among GEORGIA, FP&L and JEA dated as of December 31,
1990. See Exhibit 10(a)31 herein.
E-16
(c) 29 - Amended and Restated Unit Power Sales Agreement dated
February 18, 1982 and Amendment No. 1 dated May 18, 1982,
between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI and
SCS. See Exhibit 10(a)32 herein.
(c) 30 - Amended and Restated Unit Power Sales Agreement dated May
19, 1982, Amendment No. 1, dated August 30, 1984 and
Amendment No. 2 dated October 30, 1987, between JEA and
ALABAMA, GEORGIA, GULF, MISSISSIPPI and SCS. See Exhibit
10(a)33 herein.
(c) 31 - Unit Power Sales Agreement dated July 19, 1988, between FPC
and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS.
See Exhibit 10(a)34 herein.
(c) 32 - Amended Unit Power Sales Agreement dated July 20, 1988,
between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
SAVANNAH and SCS. See Exhibit 10(a)35 herein.
(c) 33 - Amended Unit Power Sales Agreement dated August 17, 1988,
between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
SAVANNAH and SCS. See Exhibit 10(a)36 herein.
(c) 34 - Unit Power Sales Agreement dated December 8, 1990, between
Tallahassee and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
SAVANNAH and SCS. See Exhibit 10(a)37 herein.
(c) 35 - Power Purchase Agreement dated as of December 3, 1993
between GEORGIA and FPC. See Exhibit 10(a)57 herein.
(c) 36 - Transition Energy Agreement dated December 31, 1990,
between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
SAVANNAH and SCS. See Exhibit 10(a)39 herein.
(c) 37 - Transition Energy Agreement dated December 31, 1990,
between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
SAVANNAH and SCS. See Exhibit 10(a)40 herein.
(c) 38 - Rocky Mountain Pumped Storage Hydroelectric Project
Ownership Participation Agreement dated November 18, 1988,
between OPC and GEORGIA. See Exhibit 10(a)41 herein.
(c) 39 - Rocky Mountain Pumped Storage Hydroelectric Project
Operating Agreement dated November 18, 1988, between OPC
and GEORGIA. See Exhibit 10(a)42 herein.
(c) 40 - Form of commitment agreement, Amendment No. 1 and Amendment
No. 2 with respect to SOUTHERN, ALABAMA, GEORGIA and
MISSISSIPPI revolving credits. See Exhibit 10(a)46 herein.
E-17
(c) 41 - Block Power Sale Agreement between GEORGIA and OPC dated as
of November 12, 1990. See Exhibit 10(a)47 herein.
(c) 42 - Coordination Services Agreement between GEORGIA and OPC
dated as of November 12, 1990. See Exhibit 10(a)48 herein.
(c) 43 - Amended and Restated Nuclear Managing Board Agreement for
Plant Hatch and Plant Vogtle among GEORGIA, OPC, MEAG and
Dalton dated as of July 1, 1993. See Exhibit 10(a)49
herein.
(c) 44 - Integrated Transmission System Agreement, Power Sale and
Coordination Umbrella Agreement between GEORGIA and OPC
dated as of November 12, 1990. See Exhibit 10(a)50 herein.
(c) 45 - Revised and Restated Integrated Transmission System
Agreement between GEORGIA and Dalton dated as of December
7, 1990. See Exhibit 10(a)51 herein.
(c) 46 - Revised and Restated Integrated Transmission System
Agreement between GEORGIA and MEAG dated as of December 7,
1990. See Exhibit 10(a)52 herein.
(c) 47 - Plant Scherer Managing Board Agreement dated as of December
31, 1990 among GEORGIA, OPC, MEAG, Dalton, GULF, FP&L and
JEA. See Exhibit 10(a)54 herein.
(c) 48 - Plant McIntosh Combustion Turbine Purchase and Ownership
Participation Agreement between GEORGIA and SAVANNAH dated
as of December 15, 1992. See Exhibit 10(a)55 herein.
(c) 49 - Plant McIntosh Combustion Turbine Operating Agreement
between GEORGIA and SAVANNAH dated as of December 15, 1992.
See Exhibit 10(a)56 herein.
(c) 50 - Certificate of Limited Partnership of Georgia Power
Capital. (Designated in Certificate of Notification, File
No. 70-8461, as Exhibit B.)
(c) 51 - Amended and Restated Agreement of Limited Partnership of
Georgia Power Capital, dated as of December 1, 1994.
(Designated in Certificate of Notification, File No. 70-
8461, as Exhibit C.)
(c) 52 - Action of General Partner of Georgia Power Capital creating
the Series A Preferred Securities. (Designated in
Certificate of Notification, File No. 70-8461, as Exhibit
D.)
(c) 53 - Guarantee Agreement of GEORGIA dated as of December 1,
1994, for the benefit of the holders from time to time of
the Series A Preferred Securities. (Designated in
Certificate of Notification, File No. 70-8461, as Exhibit
G.)
E-18
* (c) 54 - Amendment No. 1 dated as of June 15, 1994, to the Plant
Robert W. Scherer Unit Number Four Amended and Restated
Purchase and Ownership Participation Agreement. See
Exhibit 10(a)60 herein.
* (c) 55 - Amendment No. 1 dated as of June 15, 1994, to the Plant
Robert W. Scherer Unit Number Four Operating Agreement.
See Exhibit 10(a)61 herein.
* (c) 56 - Amendment No. 2 dated November 4, 1993 and effective June
1, 1994, to Agreement dated as of January 27, 1959, among
SEGCO, ALABAMA and GEORGIA. See Exhibit 10(b)18 herein.
(c) 57 - Nuclear Services Agreement between Southern Nuclear and
GEORGIA dated as of October 31, 1991. See Exhibit 10(a)63
herein.
(c) 58 - Nuclear Managing Board Agreement among GEORGIA, OPC, MEAG
and Dalton dated as of November 12, 1990. See Exhibit
10(a)64 herein.
* (c) 59 - The Southern Company Productivity Improvement Plan, Amended
and Restated effective January 1, 1994. See Exhibit
10(a)65 herein.
* (c) 60 - The Southern Company Executive Productivity Improvement
Plan, effective January 1, 1994. See Exhibit 10(a)66
herein.
(c) 61 - The Southern Company Employee Savings Plan, Amended and
Restated effective January 1, 1989. See Exhibit 10(a)67
herein.
(c) 62 - The Southern Company Employee Stock Ownership Plan, Amended
and Restated effective January 1, 1989. See Exhibit
10(a)68 herein.
* (c) 63 - Pension Plan For Employees of GEORGIA, Amended and Restated
effective as of January 1, 1989. See Exhibit 10(a)70
herein.
* (c) 64 - The Southern Company Performance Pay Plan, Amended and
Restated effective January 1, 1993. See Exhibit 10(a)72
herein.
* (c) 65 - Supplemental Benefit Plan for GEORGIA. See Exhibit 10(a)74
herein.
* (c) 66 - The Deferred Compensation Plan for the Southern Electric
System. See Exhibit 10(a)78 herein.
* (c) 67 - The Southern Company Outside Directors Pension Plan. See
Exhibit 10(a)77 herein.
GULF
(d) 1 - Service contracts dated as of January 1, 1984 and Amendment
No. 1 dated as of September 6, 1985, between SCS and
ALABAMA, GEORGIA, GULF, MISSISSIPPI, SEGCO and SOUTHERN.
See Exhibit 10(a)1 herein.
E-19
(d) 2 - Interchange contract dated October 28, 1988, effective
January 1, 1989, between ALABAMA, GEORGIA, GULF,
MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)5 herein.
(d) 3 - Plant Robert W. Scherer Unit Number Three Purchase and
Ownership Participation Agreement dated as of March 1,
1984, Amendment No. 1 dated as of July 1, 1986 and
Amendment No. 2 dated as of August 1, 1988, between GEORGIA
and GULF. See Exhibit 10(a)28 herein.
(d) 4 - Plant Robert W. Scherer Unit Number Three Operating
Agreement dated as of March 1, 1984, between GEORGIA and
GULF. See Exhibit 10(a)29 herein.
(d) 5 - Amended and Restated Unit Power Sales Agreement dated
February 18, 1982 and Amendment No. 1 dated May 18, 1982,
between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI and
SCS. See Exhibit 10(a)32 herein.
(d) 6 - Amended and Restated Unit Power Sales Agreement dated May
19, 1982, Amendment No. 1 dated August 30, 1984 and
Amendment No. 2 dated October 30, 1987, between JEA and
ALABAMA, GEORGIA, GULF, MISSISSIPPI and SCS. See Exhibit
10(a)33 herein.
(d) 7 - Unit Power Sales Agreement dated July 19, 1988, between FPC
and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS.
See Exhibit 10(a)34 herein.
(d) 8 - Amended Unit Power Sales Agreement dated July 20, 1988,
between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
SAVANNAH and SCS. See Exhibit 10(a)35 herein.
(d) 9 - Amended Unit Power Sales Agreement dated August 17, 1988,
between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
SAVANNAH and SCS. See Exhibit 10(a)36 herein.
(d) 10 - Agreement between GULF and AEC, effective August 1, 1985.
(Designated in GULF's Form 10-K for the year ended December
31, 1985, File No. 0-2429, as Exhibit 10(g).)
(d) 11 - Unit Power Sales Agreement dated December 8, 1990, between
Tallahassee and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
SAVANNAH and SCS. See Exhibit 10(a)37 herein.
(d) 12 - Transition Energy Agreement dated December 31, 1990,
between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
SAVANNAH and SCS. See Exhibit 10(a)39 herein.
(d) 13 - Transition Energy Agreement dated December 31, 1990,
between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
SAVANNAH and SCS. See Exhibit 10(a)40 herein.
E-20
* (d) 14 - The Southern Company Productivity Improvement Plan, Amended
and Restated effective January 1, 1994. See Exhibit
10(a)65 herein.
* (d) 15 - The Southern Company Executive Productivity Improvement
Plan, effective January 1, 1994. See Exhibit 10(a)66
herein.
(d) 16 - The Southern Company Employee Savings Plan, Amended and
Restated effective January 1, 1989. See Exhibit 10(a)67
herein.
(d) 17 - The Southern Company Employee Stock Ownership Plan, Amended
and Restated effective January 1, 1989. See Exhibit
10(a)68 herein.
* (d) 18 - Pension Plan For Employees of GULF, Amended and Restated
effective as of January 1, 1989.
* (d) 19 - The Southern Company Performance Pay Plan, Amended and
Restated effective January 1, 1993. See Exhibit 10(a)72
herein.
* (d) 20 - Supplemental Benefit Plan for GULF.
* (d) 21 - The Deferred Compensation Plan for the Southern Electric
System. See Exhibit 10(a)78 herein.
* (d) 22 - The Southern Company Outside Directors Pension Plan. See
Exhibit 10(a)77 herein.
MISSISSIPPI
(e) 1 - Service contracts dated as of January 1, 1984 and Amendment
No. 1 dated September 6, 1985, between SCS and ALABAMA,
GEORGIA, GULF, MISSISSIPPI, SEGCO and SOUTHERN. See
Exhibit 10(a)1 herein.
(e) 2 - Interchange contract dated October 28, 1988, effective
January 1, 1989, between ALABAMA, GEORGIA, GULF,
MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)5 herein.
(e) 3 - Amended and Restated Unit Power Sales Agreement dated
February 18, 1982 and Amendment No. 1 dated May 18, 1982,
between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI and
SCS. See Exhibit 10(a)32 herein.
(e) 4 - Amended and Restated Unit Power Sales Agreement dated May
19, 1982, Amendment No. 1 dated August 30, 1984, and
Amendment No. 2 dated October 30, 1987, between JEA and
ALABAMA, GEORGIA, GULF, MISSISSIPPI and SCS. See Exhibit
10(a)33 herein.
(e) 5 - Unit Power Sales Agreement dated July 19, 1988, between FPC
and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS.
See Exhibit 10(a)34 herein.
E-21
(e) 6 - Amended Unit Power Sales Agreement dated July 20, 1988,
between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
SAVANNAH and SCS. See Exhibit 10(a)35 herein.
(e) 7 - Amended Unit Power Sales Agreement dated August 17, 1988,
between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
SAVANNAH and SCS. See Exhibit 10(a)36 herein.
(e) 8 - Unit Power Sales Agreement dated December 8, 1990, between
Tallahassee and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
SAVANNAH and SCS. See Exhibit 10(a)37 herein.
(e) 9 - Transition Energy Agreement dated December 31, 1990,
between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
SAVANNAH and SCS. See Exhibit 10(a)39 herein.
(e) 10 - Transition Energy Agreement dated December 31, 1990,
between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
SAVANNAH and SCS. See Exhibit 10(a)40 herein.
(e) 11 - Transmission Facilities Agreement dated February 25, 1982,
Amendment No. 1 dated May 12, 1982 and Amendment No. 2
dated December 6, 1983, between Gulf States and
MISSISSIPPI. See Exhibit 10(a)45 herein.
(e) 12 - Form of commitment agreement, Amendment No. 1 and Amendment
No. 2 with respect to SOUTHERN, ALABAMA, GEORGIA and
MISSISSIPPI revolving credits. See Exhibit 10(a)46 herein.
(e) 13 - Long Term Transmission Service Agreement between Entergy
Power, Inc. and ALABAMA MISSISSIPPI and SCS. See Exhibit
10(a)53 herein.
* (e) 14 - The Southern Company Productivity Improvement Plan, Amended
and Restated effective January 1, 1994. See Exhibit
10(a)65 herein.
* (e) 15 - The Southern Company Executive Productivity Improvement
Plan, effective January 1, 1994. See Exhibit 10(a)66
herein.
(e) 16 - The Southern Company Employee Savings Plan, Amended and
Restated effective January 1, 1989. See Exhibit 10(a)67
herein.
(e) 17 - The Southern Company Employee Stock Ownership Plan, Amended
and Restated effective January 1, 1989. See Exhibit
10(a)68 herein.
* (e) 18 - Pension Plan For Employees of MISSISSIPPI, Amended and
Restated effective as of January 1, 1989.
* (e) 19 - The Southern Company Performance Pay Plan, Amended and
Restated effective January 1, 1993. See Exhibit 10(a)72
herein.
E-22
* (e) 20 - Supplemental Benefit Plan for MISSISSIPPI.
* (e) 21 - The Deferred Compensation Plan for the Southern Electric
System. See Exhibit 10(a)78 herein.
* (e) 22 - The Southern Company Outside Directors Pension Plan. See
Exhibit 10(a)77 herein.
SAVANNAH
(f) 1 - Service contract dated as of March 3, 1988, between SCS and
SAVANNAH. See Exhibit 10(a)3 herein.
(f) 2 - Interchange contract dated October 28, 1988, effective
January 1, 1989, between ALABAMA, GEORGIA, GULF,
MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)5 herein.
(f) 3 - Unit Power Sales Agreement dated July 19, 1988, between FPC
and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and SCS.
See Exhibit 10(a)34 herein.
(f) 4 - Amended Unit Power Sales Agreement dated July 20, 1988,
between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
SAVANNAH and SCS. See Exhibit 10(a)35 herein.
(f) 5 - Amended Unit Power Sales Agreement dated August 17, 1988,
between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
SAVANNAH and SCS. See Exhibit 10(a)36 herein.
(f) 6 - Unit Power Sales Agreement dated December 8, 1990, between
Tallahassee and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
SAVANNAH and SCS. See Exhibit 10(a)37 herein.
(f) 7 - Transition Energy Agreement dated December 31, 1990,
between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
SAVANNAH and SCS. See Exhibit 10(a)39 herein.
(f) 8 - Transition Energy Agreement dated December 31, 1990,
between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
SAVANNAH and SCS. See Exhibit 10(a)40 herein.
(f) 9 - Plant McIntosh Combustion Turbine Purchase and Ownership
Participation Agreement between GEORGIA and SAVANNAH dated
as of December 15, 1992. See Exhibit 10(a)55 herein.
(f) 10 - Plant McIntosh Combustion Turbine Operating Agreement
between GEORGIA and SAVANNAH dated December 15, 1992. See
Exhibit 10(a)56 herein.
E-23
* (f) 11 - The Southern Company Productivity Improvement Plan, Amended
and Restated effective January 1, 1994. See Exhibit
10(a)65 herein.
* (f) 12 - The Southern Company Executive Productivity Improvement
Plan, effective January 1, 1994. See Exhibit 10(a)66
herein.
(f) 13 - The Southern Company Employee Savings Plan, Amended and
Restated effective January 1, 1989. See Exhibit 10(a)67
herein.
(f) 14 - The Southern Company Employee Stock Ownership Plan, Amended
and Restated effective January 1, 1989. See Exhibit
10(a)68 herein.
* (f) 15 - Employees' Retirement Plan of SAVANNAH, Amended and
Restated effective January 1, 1989.
* (f) 16 - Supplemental Executive Retirement Plan of SAVANNAH.
* (f) 17 - Deferred Compensation Plan for Key Employees of SAVANNAH.
* (f) 18 - The Southern Company Performance Pay Plan, Amended and
Restated effective January 1, 1993. See Exhibit 10(a)72
herein.
* (f) 19 - The Southern Company Outside Directors Pension Plan. See
Exhibit 10(a)77 herein.
* (f) 20 - Deferred Compensation Plan for Directors of SAVANNAH.
(21) *Subsidiaries of Registrants - Contained herein at page IV-5.
(23) Consents of Experts and Counsel
SOUTHERN
* (a) - The consent of Arthur Andersen LLP is contained herein at
page IV-6.
ALABAMA
* (b) - The consent of Arthur Andersen LLP is contained herein at
page IV-7.
GEORGIA
* (c) - The consent of Arthur Andersen LLP is contained herein at
page IV-8.
GULF
* (d) - The consent of Arthur Andersen LLP is contained herein at
page IV-9.
E-24
MISSISSIPPI
* (e) - The consent of Arthur Andersen LLP is contained herein at
page IV-10.
SAVANNAH
* (f) - The consent of Arthur Andersen LLP is contained herein at
page IV-11.
(24) Powers of Attorney and Resolutions
SOUTHERN
* (a) - Power of Attorney and resolution.
ALABAMA
* (b) - Power of Attorney and resolution.
E-25
GEORGIA
* (c) - Power of Attorney and resolution.
GULF
* (d) - Power of Attorney and resolution.
MISSISSIPPI
* (e) - Power of Attorney and resolution.
SAVANNAH
* (f) - Power of Attorney and resolution.
(27) Financial Data Schedule
SOUTHERN
(a) - Financial Data Schedule. (Designated in Form 8-K dated
February 15, 1995, File No. 1-3526, as Exhibit 27.)
ALABAMA
(b) - Financial Data Schedule. (Designated in Form 8-K dated
February 15, 1995, File No. 1-3164, as Exhibit 27.)
GEORGIA
(c) - Financial Data Schedule. (Designated in Form 8-K dated
February 15, 1995, File No. 1-6468, as Exhibit 27.)
GULF
(d) - Financial Data Schedule. (Designated in Form 8-K dated
February 15, 1995, File No. 0-2429, as Exhibit 27.)
MISSISSIPPI
(e) - Financial Data Schedule. (Designated in Form 8-K dated
February 15, 1995, File No. 0-6849, as Exhibit 27.)
SAVANNAH
(f) - Financial Data Schedule. (Designated in Form 8-K dated
February 15, 1995, File No. 1-5072, as Exhibit 27.)