==============================================================================
UNITED STATES
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, 1998
OR
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the Transition Period from to
Commission Registrant, State of Incorporation, I.R.S. Employer
File Number Address and Telephone Number Identification No.
1-3526 The Southern Company 58-0690070
(A Delaware Corporation)
270 Peachtree Street, N.W.
Atlanta, Georgia 30303
(404) 506-5000
1-3164 Alabama Power Company 63-0004250
(An Alabama Corporation)
600 North 18th Street
Birmingham, Alabama 35291
(205) 257-1000
1-6468 Georgia Power Company 58-0257110
(A Georgia Corporation)
241 Ralph McGill Boulevard, N.E.
Atlanta, Georgia 30308-3374
(404) 506-6526
0-2429 Gulf Power Company 59-0276810
(A Maine Corporation)
One Energy Place
Pensacola, Florida 32520-0102
(850) 444-6111
0-6849 Mississippi Power Company 64-0205820
(A Mississippi Corporation)
2992 West Beach
Gulfport, Mississippi 39501
(228) 864-1211
1-5072 Savannah Electric and Power Company 58-0418070
(A Georgia Corporation)
600 East Bay Street
Savannah, Georgia 31401
(912) 644-7171
=============================================================================
Securities registered pursuant to Section 12(b) of the Act: 1
Each of the following classes or series of securities registered pursuant to
Section 12(b) of the Act is registered on the New York Stock Exchange.
Title of each class Registrant
Common Stock, $5 par value The Southern Company
Company obligated mandatorily redeemable
preferred securities, $25 liquidation amount
7.75% Cumulative Quarterly Income Preferred Securities 2
7 1/8% Trust Originated Preferred Securities 3
6.875% Cumulative Quarterly Income Preferred Securities 4
---------------------------------------------------
Class A preferred, cumulative, $25 stated capital Alabama Power Company
5.20% Series Adjustable Rate (1993 Series)
5.83% Series
Senior Notes
7 1/8% Series A 7% Series C
7% Series B
Company obligated mandatorily redeemable
preferred securities, $25 liquidation amount
7.375% Trust Preferred Securities 5
7.60% Trust Originated Preferred Securities 6
---------------------------------------------------
Senior Notes Georgia Power Company
6 7/8% Series A
6.60% Series B
Company obligated mandatorily redeemable
preferred securities, $25 liquidation amount
9% Monthly Income Preferred Securities, Series A 7
7.75% Trust Preferred Securities 8
7.60% Trust Preferred Securities 9
7.75% Quarterly Income Preferred Securities 10
First mortgage bonds
6 1/8% Series due 1999 6 7/8% Series due 2002
------------------------------------------------------
==============================================================================
1 As of December 31, 1998.
2 Issued by Southern Company Capital Trust III and guaranteed by The Southern
Company.
3 Issued by Southern Company Capital Trust IV and guaranteed by The Southern
Company.
4 Issued by Southern Company Capital Trust V and guaranteed by The Southern
Company.
5 Issued by Alabama Power Capital Trust I and guaranteed by Alabama Power
Company.
6 Issued by Alabama Power Capital Trust II and guaranteed by Alabama Power
Company.
7 Issued by Georgia Power Capital, L.P. and guaranteed by Georgia Power
Company.
8 Issued by Georgia Power Capital Trust I and guaranteed by Georgia Power
Company.
9 Issued by Georgia Power Capital Trust II and guaranteed by Georgia Power
Company.
10 Issued by Georgia Power Capital Trust III and guaranteed by Georgia Power
Company.
Company obligated mandatorily redeemable Gulf Power Company
preferred securities, $25 liquidation amount
7.625% Quarterly Income Preferred Securities 11
7.00% Quarterly Income Preferred Securities 12
------------------------------------------------------
Depositary preferred shares, each Mississippi Power Company
representing one-fourth
of a share of preferred stock,
cumulative, $100 par value
6.32% Series 6.65% Series
Company obligated mandatorily redeemable
preferred securities, $25 liquidation amount
7.75% Trust Originated Preferred Securities 13
---------------------------------------------------
Company obligated mandatorily Savannah Electric and Power Company
redeemable preferred
securities, $25 liquidation amount
6.85% Trust Preferred Securities 14
Securities registered pursuant to Section 12(g) of the Act: 15
Title of each class Registrant
Preferred stock, cumulative, $100 par value Alabama Power Company
4.20% Series 4.60% Series 4.72% Series
4.52% Series 4.64% Series 4.92% Series
Class A preferred, cumulative, $100,000 stated capital
Auction (1993 Series)
Class A preferred, cumulative, $100 stated capital
Auction (1988 Series)
----------------------------------------------------------
Preferred stock, cumulative, $100 stated value Georgia Power Company
$4.60 Series $4.72 Series $5.64 Series
$4.60 Series (1962) $4.92 Series $6.48 Series
$4.60 Series (1963) $4.96 Series $6.60 Series
$4.60 Series (1964) $5.00 Series
----------------------------------------------------------
===============================================================================
11 Issued by Gulf Power Capital Trust I and guaranteed by Gulf Power Company.
12 Issued by Gulf Power Capital Trust II and guaranteed by Gulf Power Company.
13 Issued by Mississippi Power Capital Trust I and guaranteed by Misissippi
Power Company.
14 Issued by Savannal Electric Capital Trust I and guaranteed by Savannah
Electric and Power Company.
15 As of December 31, 1998.
Preferred stock, cumulative, $100 par value Gulf Power Company
4.64% Series 5.44% Series
5.16% 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, 1999: $17.5 billion. Each of such other
registrants is a wholly-owned subsidiary of The Southern Company and has no
voting stock other than its common stock. A description of registrants' common
stock follows:
Description of Shares Outstanding
Registrant Common Stock at February 28, 1999
The Southern Company Par Value $5 Per Share 698,630,431
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 1999 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
Traditional Business........................................................I-1
Non-Traditional Business....................................................I-2
Certain Factors Affecting the Industry......................................I-4
Construction Programs.......................................................I-4
Year 2000...................................................................I-5
Financing Programs..........................................................I-6
Fuel Supply.................................................................I-7
Territory Served By Operating Affiliates....................................I-9
Competition.................................................................I-12
Regulation..................................................................I-13
Rate Matters................................................................I-15
Employee Relations..........................................................I-17
Item 2 Properties....................................................................I-18
Item 3 Legal Proceedings.............................................................I-23
Item 4 Submission of Matters to a Vote of Security Holders...........................I-23
Executive Officers of SOUTHERN................................................I-24
PART II
Item 5 Market for Registrants' Common Equity and Related Stockholder Matters.........II-1
Item 6 Selected Financial Data.......................................................II-2
Item 7 Management's Discussion and Analysis of Results of Operations
and Financial Condition.....................................................II-2
Item 7A Quantitative and Qualitative Disclosures about Market Risk....................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-31
Item 13 Certain Relationships and Related Transactions...............................III-37
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
APEA.......................................... Applicant Prepared Environmental Assessment
CEMIG......................................... Companhia Energetica de Minas Gerais
CEPA.......................................... Consolidated Electric Power Asia
Clean Air Act................................. Clean Air Act Amendments of 1990
Dalton........................................ City of Dalton, Georgia
DOE........................................... United States Department of Energy
Edelnor....................................... Empresa Electrica del Norte Grande, S.A. (Chile)
EMF........................................... Electromagnetic field
Energy Act.................................... Energy Policy Act of 1992
Energy Solutions.............................. Southern Company Energy Solutions,
Inc. (formerly The Southern
Development and Investment Group,
Inc.)
Entergy Gulf States........................... Entergy Gulf States Utilities Company
EPA........................................... United States Environmental Protection Agency
EWG........................................... Exempt wholesale generator
FERC.......................................... Federal Energy Regulatory Commission
FPC........................................... Florida Power Corporation
FP&L.......................................... Florida Power & Light Company
Freeport...................................... Freeport Power Company (Bahamas)
FUCO.......................................... Foreign utility company
GEORGIA....................................... Georgia Power Company
GULF.......................................... Gulf Power Company
Holding Company Act........................... Public Utility Holding Company Act of 1935, as amended
IBEW.......................................... International Brotherhood of Electrical Workers
IRS........................................... Internal Revenue Service
JEA........................................... Jacksonville Electric Authority
MEAG.......................................... Municipal Electric Authority of Georgia
MISSISSIPPI................................... Mississippi Power Company
Mobile Energy................................. Mobile Energy Services Company, LLC
NRC........................................... Nuclear Regulatory Commission
OPC........................................... Oglethorpe Power Corporation
operating affiliates.......................... ALABAMA, GEORGIA, GULF, MISSISSIPPI
and SAVANNAH
PSC........................................... Public Service Commission
RUS........................................... Rural Utility Service (formerly Rural Electrification Administration)
SAVANNAH...................................... Savannah Electric and Power Company
SCS........................................... Southern Company Services, Inc.
SEC........................................... Securities and Exchange Commission
SEGCO......................................... Southern Electric Generating Company
SEPA.......................................... Southeastern Power Administration
SERC.......................................... Southeastern Electric Reliability Council
SMEPA......................................... South Mississippi Electric Power Association
SOUTHERN...................................... The Southern Company
Southern LINC................................. Southern Communications Services, Inc.
Southern Energy............................... Southern Energy, Inc. (formerly Southern Electric International, Inc.)
Southern Nuclear.............................. Southern Nuclear Operating Company, Inc.
ii
DEFINITIONS
(continued)
SOUTHERN system............................... SOUTHERN, the operating affiliates, SEGCO, Southern Energy,
Southern Nuclear, SCS, Southern LINC, Energy Solutions and
other subsidiaries
SWEB.......................................... South Western Electricity plc (United Kingdom)
TVA........................................... Tennessee Valley Authority
iii
CAUTIONARY STATEMENT REGARDING
FORWARD-LOOKING INFORMATION
This Annual Report on Form 10-K includes forward-looking and historical
information. The registrants caution that there are various important factors
that could cause actual results to differ materially from those indicated in the
forward-looking information; accordingly, there can be no assurance that such
indicated results will be realized. These factors include legislative and
regulatory initiatives regarding deregulation and restructuring of the electric
utility industry; the extent and timing of the entry of additional competition
in the markets of SOUTHERN's subsidiaries; potential business strategies,
including acquisitions or dispositions of assets or internal restructuring, that
may be pursued by the registrants; state and federal rate regulation in the
United States; Year 2000 issues; changes in or application of environmental and
other laws and regulations to which SOUTHERN and its subsidiaries are subject;
political, legal and economic conditions and developments in the United States
and in foreign countries in which the subsidiaries operate; financial market
conditions and the results of financing efforts; changes in commodity prices and
interest rates; weather and other natural phenomena; the performance of projects
undertaken by the non-traditional business and the success of efforts to invest
in and develop new opportunities; and other factors discussed elsewhere herein
and in other reports filed from time to time by the registrants with the SEC.
iv
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 Southern Energy,
Southern LINC, Southern Nuclear, SCS (the system service company), Energy
Solutions and other direct and indirect subsidiaries. Southern Energy is focused
on several key international and domestic business lines, including energy
distribution, integrated utilities, stand-alone generation, and other
energy-related products and services. A further description of Southern Energy's
business and organization follows later in this section under "Non-Traditional
Business." Southern LINC provides digital wireless communications services to
SOUTHERN's operating affiliates and also markets these services to the public
within the Southeast. Southern Nuclear provides services to the Southern
electric system's nuclear plants. Energy Solutions 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
Traditional Business
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 By Operating Affiliates" herein.)
I-1
Operating contracts covering arrangements in effect with principal
neighboring utility systems provide for capacity exchanges, capacity purchases
and sales, transfers of economy energy and other similar transactions.
Additionally, the operating affiliates have entered into voluntary reliability
agreements with the subsidiaries of Entergy Corporation, Florida Electric Power
Coordinating Group and TVA and with Carolina Power & Light Company, Duke Energy
Corporation, 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, Southern Energy,
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. Southern
Energy, Energy Solutions and Southern LINC have also secured from the operating
affiliates certain services which are furnished at cost.
Southern Nuclear has contracts with ALABAMA to operate the Farley Nuclear
Plant, and with GEORGIA to operate Plants Hatch and Vogtle. See Item 1 -
BUSINESS - "Regulation - Atomic Energy Act of 1954" herein.
Non-Traditional Business
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
Southern Energy and other subsidiaries. SOUTHERN has filed with the SEC an
application for authority to invest up to nearly $8 billion in the
non-traditional domestic and international business. A consumer group has filed
a motion to intervene in this proceeding. The current SEC authority is $3.9
billion, of which $3.6 billion has been invested as of December 31, 1998.
Worldwide, Southern Energy develops and manages electricity and other energy
related projects, including domestic energy trading and marketing. As the energy
marketplace evolves, Southern Energy continues to position SOUTHERN to become a
major competitor. During 1998, Southern Energy further refined its business
strategy to focus on a few geographic regions of the world. In Asia, Southern
Energy will focus primarily on China, the Philippines and India. In South
America, Southern Energy will pursue opportunities in Brazil. In Europe,
Southern Energy will concentrate efforts on the European Union countries. And in
North America, Southern Energy will target efforts in Northeast, the Midwest,
Texas and California. See Item 7 for SOUTHERN's Management's Discussion and
Analysis under the heading "Future Earnings Potential" for additional
information regarding this strategy.
Reference is also made to Note 14 to the financial statements of SOUTHERN in
Item 8 herein for additional information regarding SOUTHERN's segment and
related information.
In 1995, SOUTHERN, through its subsidiary Southern Energy, acquired SWEB,
one of the United Kingdom's 12 regional electric distribution companies, for
approximately $1.8 billion. In July 1996, a 25 percent interest in SWEB was sold
to PP&L Resources.
I-2
In June 1998, SOUTHERN through its subsidiary Southern Energy
sold an additional 26% interest in SWEB to PP&L Resources for $170 million. SWEB
is, to a limited extent, involved in power generation and certain non-regulated
activities which include gas marketing and telecommunications. In mid-1997, the
acquisition of CEPA was completed for a total net investment of $2.1 billion.
CEPA is engaged in the business of developing, constructing, owning and
operating electric power generation facilities. Its current operations include
installed operating capacity of approximately 3,306 megawatts, with projects
either completed or under development in the Philippines, the People's Republic
of China, and India. (For additional information related to the acquisition of
CEPA, reference is made to Note 13 to SOUTHERN's financial statements in Item 8
herein.) In 1997, Southern Energy also acquired a 26% interest in a German
utility for approximately $820 million.
In January 1998, Southern Energy entered into a joint venture with Vastar
Resources, Inc. The two companies combined their energy trading and marketing
operations to form a new full-service energy provider, Southern Company Energy
Marketing. The joint venture agreement gives Southern Company Energy Marketing
rights to market virtually all of Vastar's natural gas production over the next
10 years.
In December 1998, Southern Energy completed its $537 million purchase of
1,267 megawatts of generating capacity from Commonwealth Electric. In addition,
Southern Energy plans to add 685 megawatts of capacity at the plants. In late
1998, Southern Energy announced the $801 million planned acquisition of 3,065
megawatts of generating capacity from Pacific Gas & Electric in northern
California. Additionally, Southern Energy announced plans to acquire from Orange
and Rockland Utilities Inc. and Consolidated Edison Inc. in New York 1,776
megawatts of capacity for $480 million. These transactions are expected to close
during 1999. Further, Southern Energy has announced plans to build or purchase
an additional 980 megawatts of capacity in Texas and Wisconsin. Through Southern
Company Energy Marketing, Southern Energy has also gained access to additional
capacity through marketing agreements. Southern Energy additionally has access
to almost 2,000 megawatts of capacity through marketing agreements with Sithe
Energies in New York and Brazos Electric Cooperative in Texas.
After refining its international focus and reviewing the financial
performance of existing assets, Southern Energy announced plans to sell its
holdings in Edelnor in Chile and Alicura in Argentina. As a result, Southern
Energy recorded a write down of $200 million, after taxes, in December 1998
related to these holdings. Because of regulatory and market conditions, these
assets did not meet expectations.
In January 1999, Mobile Energy, an indirect subsidiary of SOUTHERN, and its
direct parent filed petitions for Chapter 11 bankruptcy relief in the U.S.
Bankruptcy Court for the Southern District of Alabama. For additional
information regarding this matter, reference is made to Item 3 - LEGAL
PROCEEDINGS herein.
See Item 2 - PROPERTIES - "Other Electric Generation Facilities" herein for
additional information regarding Southern Energy projects.
Southern Energy and Energy Solutions render consulting services and market
SOUTHERN system expertise in the United States and throughout the world. They
contract with other public utilities, commercial concerns and government
agencies for the rendition of services and the licensing of intellectual
property. More specifically, Energy Solutions is focusing on new and existing
programs to enhance customer satisfaction and efficiency and stockholder value,
such as: Good Cents, an energy efficiency program for electric utility
customers; Energy Services, providing total energy solutions to industrial and
commercial customers; Heat Pump financing for residential customers; and
telecommunications operations and security monitoring for both commercial and
residential customers.
In 1995, Southern LINC began serving SOUTHERN's operating affiliates and
marketing its services to non-affiliates within the Southeast. Its system covers
122,000 square miles and combines the functions of two-way radio dispatch,
cellular phone, short text and numeric messaging and wireless data transfer. In
the spring of 1999, Southern LINC will add more than 7,000 square miles to its
present coverage area.
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 1999-2001 in
these and other new businesses.
I-3
Certain Factors Affecting the Industry
Various factors are currently affecting the electric utility industry in
general, including increasing competition and the regulatory changes related
thereto, costs required to comply with environmental regulations, and the
potential for new business opportunities (with their associated risks) outside
of traditional rate-regulated operations. The effects of these and other factors
on the SOUTHERN system are described herein. Particular reference is made to
Item 1 - BUSINESS - "Non-Traditional Business," "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 1999 through
2001 by the operating affiliates, SEGCO, SCS, Southern LINC and Southern Energy
are estimated as follows: (in millions)
------------------------------ -------- --------- ----------
1999 2000 2001
-------- --------- ----------
ALABAMA $ 875 $653 $ 668
GEORGIA 755 734 829
GULF 72 100 262
MISSISSIPPI 67 52 45
SAVANNAH 29 32 31
SEGCO 13 4 5
SCS 66 16 15
Southern LINC 46 19 14
Southern Energy* 630 481 230
Other 15 10 16
=========================== =========== ========= ==========
SOUTHERN system $2,568 $2,101 $2,115
=========================== =========== ========= ==========
*These construction estimates do not include amounts which may be expended
by Southern Energy on future power production projects or by any subsidiaries
created to effect such future projects. (See Item 1 - BUSINESS -
"Non-Traditional Business" herein.)
I-4
Estimated construction costs in 1999 are expected to be apportioned approximately as follows: (in millions)
--------------------------------- --------------- --------------- ---------------- ----------- ---------------- ---------
SOUTHERN
system* ALABAMA GEORGIA GULF MISSISSIPPI SAVANNAH
--------------- --------------- ---------------- ----------- ---------------- ---------
Combustion turbines $ 345 $194 $144 $ - $ 7 $ -
Other generating
facilities including
associated plant substations 799 196 93 17 10 5
New business 349 142 160 23 14 10
Transmission 329 136 130 9 12 3
Joint line and substation 42 - 34 8 - -
Distribution 307 84 63 9 18 9
Nuclear fuel 120 63 57 - - -
General plant 277 60 74 6 6 2
--------------- ---------- ---------------- ----------- ------------ -----------------
$2,568 $875 $755 $72 $67 $29
=============== ========== ================ =========== ============ =================
*Southern LINC, SCS and Southern Nuclear plan capital additions to general
plant in 1999 of $46 million, $66 million and $270 thousand, respectively, while
SEGCO plans capital additions of $13 million to generating facilities. Southern
Energy plans capital additions of $465 million to generating facilities, $124
million to distribution facilities, $39 million to transmission facilities, and
$2 million to general plant. These estimates do not reflect the possibility of
Southern Energy's securing a contract(s) to buy or build additional generating
facilities. Other non-traditional capital additions planned for 1999 are
approximately $15 million. (See Item 1 - BUSINESS - "Non-Traditional Business"
herein.)
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.
The operating affiliates have approximately 2,700 megawatts of combined
cycle generation scheduled to be placed in service by 2001. In addition,
significant construction will continue related to transmission and distribution
facilities and the upgrading of generating plants. (See Item 2 - PROPERTIES -
"Other Electric Generation Facilities" herein for additional information
relating to facilities under development.)
In 1991, the Georgia legislature passed legislation which requires GEORGIA
and SAVANNAH each to file an Integrated Resource Plan for approval by the
Georgia PSC. Under the plan rules, the Georgia PSC must pre-certify the
construction of new power plants and new purchase power contracts. (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.
Year 2000
Reference is made to each registrant's "Management's Discussion and Analysis -
Year 2000" in Item 7 herein for information relating to Year 2000 issues.
I-5
Financing Programs
In 1998, SOUTHERN raised net proceeds of $109 million from the issuance of
common stock under SOUTHERN's various stock plans. Also in 1998, SOUTHERN issued
a total of $350 million in trust preferred securities for the direct benefit of
SOUTHERN. SOUTHERN plans to issue additional equity capital in 1999. The amount
and timing of additional equity capital to be raised in 1999, 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. Any portion of the common stock required
during 1999 for SOUTHERN'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 affiliates plan to obtain the funds required for construction
and other purposes from sources similar to those used in the past, which were
primarily from internal sources. However, the type and timing of any financings
- - - - - - - -- if needed -- will depend on market conditions and regulatory approval.
Historically the operating affiliates have relied on issuances of first mortgage
bonds and preferred stock, in addition to pollution control revenue bonds issued
for their benefit by public authorities, to meet their long-term external
financing requirements. Recently, financings have consisted of unsecured debt
and trust preferred securities. In this regard, the operating affiliates sought
and obtained stockholder approval in 1997 and 1998 to amend their respective
corporate charters eliminating restrictions on the amount of unsecured
indebtedness they may incur.
Short-term debt is often utilized as appropriate at SOUTHERN and the
operating affiliates.
The maximum amounts of short-term or term-loan indebtedness authorized by
the appropriate regulatory authorities are shown on the following table:
Outstanding at
Amount December 31, 1998
------------ ---------------------
(in millions)
ALABAMA $ 750 (1) $0
GEORGIA 1,700 (2) 340.9
GULF 300(1) 58.5
MISSISSIPPI 350(1) 93.0
SAVANNAH 90(2) 30.0
SOUTHERN 2,000(1) 738.3
------------------ -------------- -- -------------------
Notes:
(1) ALABAMA's authority is based on authorization received from the Alabama
PSC, which expires December 31, 2000. No SEC authorization is required for
ALABAMA. GULF, MISSISSIPPI and SOUTHERN have received SEC authorization to issue
from time to time short-term and/or term-loan notes to banks and commercial
paper to dealers in the amounts shown through December 31, 2003, December 31,
2002 and March 31, 2001, respectively.
(2) GEORGIA and SAVANNAH have received SEC authorization to issue from time
to time short-term and term-loan notes to banks and commercial paper to dealers
in the amounts shown through December 31, 2002. Authorization for term-loan
indebtedness is also required by the Georgia PSC. At December 31, 1998, GEORGIA
had remaining authority of $920 million expiring December 31, 1999. SAVANNAH has
applied for authority from the Georgia PSC for $70 million expiring December 31,
2000.
Reference is made to Note 5 to the financial statements for SOUTHERN,
ALABAMA, GULF, MISSISSIPPI and SAVANNAH and Note 9 to the financial statements
for GEORGIA in Item 8 herein for information regarding the registrants' credit
arrangements.
New projects undertaken by subsidiaries of Southern Energy are generally
financed through a combination of equity funds provided by SOUTHERN and
non-recourse debt incurred on a project-specific basis.
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 1996 through
1998 and the estimates for 1999 are shown below:
Oil and
ALABAMA Coal Nuclear Hydro Gas
--------- ---------- --------- ---------
1996 72 20 8 *
1997 72 20 8 *
1998 72 18 8 2
1999 72 19 7 2
GEORGIA
1996 74 22 3 1
1997 75 22 2 1
1998 73 22 3 2
1999 74 22 3 1
GULF
1996 99 ** ** 1
1997 100 ** ** *
1998 98 ** ** 2
1999 99 ** ** 1
MISSISSIPPI
1996 85 ** ** 15
1997 85 ** ** 15
1998 80 ** ** 20
1999 83 ** ** 17
SAVANNAH
1996 90 ** ** 10
1997 87 ** ** 13
1998 76 ** ** 24
1999 87 ** ** 13
SEGCO
1996 100 ** ** *
1997 100 ** ** *
1998 100 ** ** *
1999 100 ** ** *
SOUTHERN system***
1996 77 17 4 2
1997 77 17 4 2
1998 76 16 4 4
1999 77 17 4 2
---------- ------- --------- ---------- --------- ---------
*Less than 0.5%.
**Not applicable.
***Amounts shown for the SOUTHERN system are weighted
averages of the operating affiliates and SEGCO.
The average costs of fuel in cents per net kilowatt-hour generated for 1996
through 1998 are shown below:
1996 1997 1998
-------------- --------------- ---------------
ALABAMA 1.46 1.49 1.54
GEORGIA 1.35 1.32 1.36
GULF 2.02 1.99 1.69
MISSISSIPPI 1.57 1.54 1.62
SAVANNAH 2.42 2.27 2.33
SEGCO 1.72 1.51 1.53
SOUTHERN
System* 1.48 1.46 1.48
- - - - - - - ------------------- -------------- --------------- ---------------
* Amounts shown for the SOUTHERN system are weighted averages of the
operating affiliates and SEGCO.
See SELECTED FINANCIAL DATA in Item 6 herein for each registrant's source
of energy supply.
I-7
As of February 12, 1999, the operating affiliates and SEGCO had stockpiles
of coal on hand at their respective coal-fired plants which represented an
estimated 19 days of recoverable supply for bituminous coal and 24 days for
sub-bituminous coal. It is estimated that approximately 68.0 million tons of
coal will be consumed in 1999 by the operating affiliates and SEGCO (including
those units GEORGIA owns jointly with OPC, MEAG and Dalton and operates for FP&L
and JEA and the units ALABAMA owns jointly with AEC). The operating affiliates
and SEGCO currently have 45 coal contracts. These contracts cover remaining
terms of up to 13 years. Approximately 22% of 1999 estimated coal requirements
will be purchased in the spot market. Management has set a goal whereby the spot
market should be utilized, absent the transition from coal contract expirations,
for 20 to 30% of the SOUTHERN system's coal supply. Additionally, it has been
determined that approximately 30 days of recoverable supply is the appropriate
level for coal stockpiles. During 1998, the operating affiliates' and SEGCO's
average price of coal delivered was approximately $36.39 per ton.
In 1998, the weighted average sulfur content of all coal purchased by the
operating affiliates and SEGCO for use in the coal-fired facilities was 0.89%
sulfur. This sulfur level allowed the operating affiliates and SEGCO to remain
well below the limits as set forth by Phase I of the Clean Air Act Amendments of
1990. With the approach of Phase II of the Clean Air Act in 2000, the operating
affiliates and SEGCO have secured sufficient quantities of lower sulfur coal to
help meet the more stringent Phase II sulfur requirements. As more and more
strict environmental regulations are proposed that impact the utilization of
coal, the fuel mix will be monitored to insure that sufficient quantities of the
proper type of coal or natural gas are in place to remain in compliance with
applicable laws and regulations. See Item 1 - BUSINESS - "Regulation -
Environmental Regulation" herein.
Changes in fuel prices are generally reflected in fuel adjustment clauses
contained in rate schedules. See Item 1 - BUSINESS - "Rate Matters - Rate
Structure" herein.
ALABAMA owns coal lands and mineral rights in the Warrior Coal Field,
located northwest of Birmingham in the vicinity of its Gorgas Steam Plant. SEGCO
also owns coal reserves in the Warrior Coal Field and in the Cahaba Coal Field,
which is located southwest of Birmingham. ALABAMA has agreements with
non-affiliated mining firms to mine coal from ALABAMA's reserves, as well as
their own reserves, for supply to ALABAMA's generating units.
The operating affiliates have renegotiated, bought out or otherwise
terminated various coal supply contracts. For more information on certain of
these transactions, see Note 5 to the financial statements of GULF in Item 8
herein.
ALABAMA and GEORGIA have numerous contracts covering a portion of their
nuclear fuel needs for uranium, conversion services, enrichment services and
fuel fabrication. These contracts have varying expiration dates and most are
short to medium term (less than 10 years). Management believes that sufficient
capacity for nuclear fuel supplies and processing exists to preclude the
impairment of normal operations of the SOUTHERN system's nuclear generating
units.
ALABAMA and GEORGIA have contracts with the DOE that provide for the
permanent disposal of spent nuclear fuel. Although disposal was scheduled to
begin in 1998, the actual year this service will begin is uncertain. The DOE
failed to begin disposing of spent fuel in January 1998, as required by the
contracts, and the companies are pursuing legal remedies against the government
for breach of contract. Sufficient on-site storage capacity currently is
available to permit operation into 2003 at Plant Hatch, into 2017 at Plant
Vogtle, and into 2009 and 2013 at Plant Farley units 1 and 2, respectively.
Plant Vogtle's spent fuel storage capacity includes the installation in 1998 of
additional rack capacity. Activities for adding dry cask storage capacity at
Plant Hatch by as early as 1999 are in progress.
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.
I-8
Territory Served By Operating Affiliates
The territory in which the operating affiliates provide electric service
comprises most of the states of Alabama and Georgia together with the
northwestern portion of Florida and southeastern Mississippi. In this territory
there are non-affiliated electric distribution systems which obtain some or all
of their power requirements either directly or indirectly from the operating
affiliates. The territory has an area of approximately 120,000 square miles and
an estimated population of approximately 11 million.
ALABAMA is engaged, within the State of Alabama, in the generation and
purchase of electricity and the distribution and sale of such electricity at
retail in over 1,000 communities (including Anniston, Birmingham, Gadsden,
Mobile, Montgomery and Tuscaloosa) and at wholesale to 15 municipally-owned
electric distribution systems, 11 of which are served indirectly through sales
to AMEA, and two rural distributing cooperative associations. ALABAMA also
supplies steam service in downtown Birmingham. ALABAMA owns coal reserves near
its steam-electric generating plant at Gorgas and uses the output of coal from
these reserves in some of its generating plants. ALABAMA also sells, and
cooperates with dealers in promoting the sale of, electric appliances.
GEORGIA is engaged in the generation and purchase of electricity and the
distribution and sale of such electricity within the State of Georgia at retail
in over 600 communities, as well as in rural areas, and at wholesale currently
to OPC, MEAG, the City of Dalton and the City of Hampton.
GULF is engaged, within the northwestern portion of Florida, in the
generation and purchase of electricity and the distribution and sale of such
electricity at retail in 71 communities (including Pensacola, Panama City and
Fort Walton Beach), as well as in rural areas, and at wholesale to a
non-affiliated utility and a municipality. GULF also sells electric appliances.
MISSISSIPPI is engaged in the generation and purchase of electricity and the
distribution and sale of such energy within the 23 counties of southeastern
Mississippi, at retail in 123 communities (including Biloxi, Gulfport,
Hattiesburg, Laurel, Meridian and Pascagoula), as well as in rural areas, and at
wholesale to one municipality, six rural electric distribution cooperative
associations and one generating and transmitting cooperative.
SAVANNAH is engaged, within a five-county area in eastern Georgia, in the
generation and purchase of electricity and the distribution and sale of such
electricity at retail and, as a member of the SOUTHERN system power pool, the
transmission and sale of wholesale energy.
For information relating to kilowatt-hour sales by classification for each
registrant, reference is made to "Management's Discussion and Analysis-Revenues"
in Item 7 herein. Also, for information relating to the sources of revenues for
the Southern system and each of the operating affiliates, reference is made to
Item 6 herein.
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 RUS has authority to make loans to cooperative associations or
corporations to enable them to provide electric service to customers in rural
sections of the country. There are 71 electric cooperative organizations
operating in the territory in which the operating affiliates provide electric
service at retail or wholesale.
One of these, AEC, is a generating and transmitting cooperative selling
power to several distributing cooperatives, municipal systems and other
customers in south Alabama and northwest Florida. AEC owns generating units with
approximately 840 megawatts of nameplate capacity, including an undivided
ownership interest in ALABAMA's Plant Miller Units 1 and 2. AEC's facilities
were financed with RUS loans secured by long-term contracts requiring
distributing cooperatives to take their requirements from AEC to the extent such
energy is available. Two of the 14 distributing cooperatives operating in
ALABAMA's service territory obtain a portion of their power requirements
directly from ALABAMA.
I-9
Four electric cooperative associations, financed by the RUS, operate within
GULF's service area. These cooperatives purchase their full requirements from
AEC and SEPA. A non-affiliated utility also operates within GULF's service area
and purchases a portion of its requirements from GULF.
ALABAMA and GULF have entered into separate agreements with AEC involving
interconnection between the respective systems. The delivery of capacity and
energy from AEC to certain distributing cooperatives in the service areas of
ALABAMA and GULF is governed by SOUTHERN's AEC Network Transmission Service
Agreement. The rates for this service to AEC are based on the negotiated
agreement on file with the FERC. See Item 2 - PROPERTIES - "Jointly-Owned
Facilities" herein for details of ALABAMA's joint-ownership with AEC of a
portion of Plant Miller.
MISSISSIPPI has an interchange agreement with SMEPA, a generating and
transmitting cooperative, pursuant to which various services are provided,
including the furnishing of protective capacity by MISSISSIPPI to SMEPA. SMEPA
has a generating capacity of 739,000 kilowatts and a transmission system
estimated to be 1,357 miles in length.
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 a power
coordination 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. OPC decreased its purchases of capacity by
250 megawatts each in September 1996, 1997 and 1998 and has notified GEORGIA of
its intent to decrease purchases of capacity by an additional 250 megawatts in
September 1999 and 125 megawatts in September 2000. In December 1997, a revised
power coordination agreement was implemented between GEORGIA and OPC. Under the
amended 1995 Integrated Resource Plan approved by the Georgia PSC in March 1997,
the resources associated with the decreased purchases by OPC in 1996, 1997 and
1998 will be used to meet the needs of GEORGIA's retail customers through 2004.
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 commencing October 1, 1991. In both
contracts the power will be sold to AMEA for its member municipalities that
previously were served directly by ALABAMA as wholesale customers. Under the
terms of the contracts, ALABAMA received payments from AMEA representing the net
present value of the revenues associated with the respective capacity
entitlements. See Note 7 to ALABAMA's financial statements in Item 8 herein for
further information on these contracts.
Forty-eight municipally-owned electric distribution systems and one
county-owned system 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 purchases from
others. In August 1997, a power coordination agreement was implemented between
GEORGIA and MEAG that replaced the partial requirements tariff pursuant to which
GEORGIA previously sold wholesale energy to MEAG. Since 1977, Dalton has filled
its requirements from generation facilities acquired from GEORGIA and through
partial requirements purchases. One municipally-owned electric distribution
system's full requirements are served under a market-based contract by GEORGIA.
(See Item 2 - PROPERTIES - "Jointly-Owned Facilities" herein.)
I-10
GULF and MISSISSIPPI provide wholesale requirements for one municipal system
each.
GEORGIA has entered into substantially similar agreements with Georgia
Transmission Corporation (formerly OPC's transmission division), 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.)
SCS, acting on behalf of ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH,
also has a contract with SEPA (a federal power marketing agency) providing for
the use of those companies' facilities at government expense to deliver to
certain cooperatives and municipalities, entitled by federal statute to
preference in the purchase of power from SEPA, quantities of power equivalent to
the amounts of power allocated to them by SEPA from certain United States
Government hydroelectric projects.
The retail service rights of all electric suppliers in the State of Georgia
are regulated by the 1973 State Territorial Electric Service Act. Pursuant to
the provisions of this Act, all areas within existing municipal limits were
assigned to the primary electric supplier therein on March 29, 1973 (451
municipalities, including Atlanta, Columbus, Macon, Augusta, Athens, Rome and
Valdosta, to GEORGIA; 115 to electric cooperatives; and 50 to publicly-owned
systems). Areas outside of such municipal limits were either to be assigned or
to be declared open for customer choice of supplier by action of the Georgia PSC
pursuant to standards set forth in the Act. Consistent with such standards, the
Georgia PSC has assigned substantially all of the land area in the state to a
supplier. Notwithstanding such assignments, the Act provides that any new
customer locating outside of 1973 municipal limits and having a connected load
of at least 900 kilowatts may receive electric service from the supplier of its
choice. (See also Item 1 - BUSINESS - "Competition" herein.)
Under and subject to the provisions of its franchises and concessions and
the 1973 State Territorial Electric Service Act, SAVANNAH has the full but
nonexclusive right to serve the City of Savannah, the Towns of Bloomingdale,
Pooler, Garden City, Guyton, Newington, Oliver, Port Wentworth, Rincon, Tybee
Island, Springfield, Thunderbolt, Vernonburg, and in conjunction with a
secondary supplier, the Town of Richmond Hill. In addition, SAVANNAH has been
assigned certain unincorporated areas in Chatham, Effingham, Bryan, Bulloch and
Screven Counties by the Georgia PSC. (See also Item 1 - BUSINESS - "Competition"
herein.)
Pursuant to the 1956 Utility Act, the Mississippi PSC issued "Grandfather
Certificates" of public convenience and necessity to MISSISSIPPI and to six
distribution rural cooperatives operating in southeastern Mississippi, then
served in whole or in part by MISSISSIPPI, authorizing them to distribute
electricity in certain specified geographically described areas of the state.
The six cooperatives serve approximately 300,000 retail customers in a
certificated area of approximately 10,300 square miles. In areas included in a
"Grandfather Certificate," the utility holding such certificate may, without
further certification, extend its lines up to five miles; other extensions
within that area by such utility, or by other utilities, may not be made except
upon a showing of, and a grant of a certificate of, public convenience and
necessity. Areas included in such a certificate which are subsequently annexed
to municipalities may continue to be served by the holder of the certificate,
irrespective of whether it has a franchise in the annexing municipality. On the
other hand, the holder of the municipal franchise may not extend service into
such newly annexed area without authorization by the Mississippi PSC.
Long-Term Power Sales Agreements
Reference is made to Note 7 to the financial statements for SOUTHERN, ALABAMA,
GEORGIA, GULF and MISSISSIPPI in Item 8 herein for information regarding
contracts for the sales of capacity and energy to non-territorial customers.
I-11
Competition
The electric utility industry in the United States is currently undergoing a
period of dramatic change as a result of regulatory and competitive factors.
Among the primary agents of change has been the Energy Policy Act of 1992
(Energy Act). The Energy Act allows independent power producers (IPPs) to access
a utility's transmission network in order to sell electricity to other
utilities. This enhances the incentive for IPPs to build cogeneration plants for
a utility's large industrial and commercial customers, and sell energy
generation to other utilities. Also, electricity sales for resale rates are
being driven down by wholesale transmission access and numerous potential new
energy suppliers, including power marketers and brokers. SOUTHERN is
aggressively working to maintain and expand its share of wholesale sales in the
Southeastern power markets.
Although the Energy Act does not permit retail customer access, it was a
major catalyst for the current restructuring and consolidation taking place
within the utility industry. Numerous federal and state initiatives are in
varying stages to promote wholesale and retail competition. Among other things,
these initiatives allow customers to choose their electricity provider. As these
initiatives materialize, the structure of the utility industry could radically
change. Some states have approved initiatives that result in a separation of the
ownership and/or operation of generating facilities from the ownership and/or
operation of transmission and distribution facilities. While various
restructuring and competition initiatives have been or are being discussed in
Alabama, Florida, Georgia, and Mississippi, none have been enacted to date.
Enactment would require numerous issues to be resolved, including significant
ones relating to transmission pricing and recovery of any stranded investments.
The inability of an operating company to recover its investments, including the
regulatory assets described in Note 1 to each registrant's respective financial
statements, could have a material adverse effect on the financial condition of
that operating company. The operating companies are attempting to minimize or
reduce their cost exposure. Reference is made to Note 3 to the financial
statements for SOUTHERN for information regarding these efforts.
Continuing to be a low-cost producer could provide opportunities to increase
market share and profitability in markets that evolve with changing regulation.
Conversely, unless SOUTHERN 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. Reference is made to each registrant's
"Management's Discussion and Analysis - Future Earnings Potential" in Item 7
herein for further discussion of competition.
To adapt to a less regulated, more competitive environment, SOUTHERN
continues to evaluate and consider a wide array of potential business
strategies. These strategies may include business combinations, acquisitions
involving other utility or non-utility businesses or properties, internal
restructuring, disposition of certain assets, or some combination thereof.
Furthermore, SOUTHERN may engage in other new business ventures that arise from
competitive and regulatory changes in the utility industry. Pursuit of any of
the above strategies, or any combination thereof, may significantly affect the
business operations and financial condition of SOUTHERN. (See Item 1 - BUSINESS
- - - - - - - - "Non-Traditional Business" herein.)
As a result of the foregoing factors, SOUTHERN has experienced increasing
competition for available off-system sales of capacity and energy from
neighboring utilities and alternative sources of energy. Additionally, the
future effect of cogeneration and small-power production facilities on the
SOUTHERN system cannot currently be determined but may be adverse.
ALABAMA currently has cogeneration contracts in effect with eleven
industrial customers. Under the terms of these contracts, ALABAMA purchases
excess generation of such companies. During 1998, ALABAMA purchased
approximately 60 million kilowatt-hours from such companies at a cost of $1.2
million.
GEORGIA currently has contracts in effect with six small power producers
whereby GEORGIA purchases their excess generation. During 1998, GEORGIA
purchased 5.0 million kilowatt-hours from such companies at a cost of $277,510.
GEORGIA has entered into a 30-year purchase power agreement, which began in June
1998, for electricity from a 300-megawatt cogeneration facility. Payments are
subject to reductions for failure to meet minimum capacity output. During 1998,
GEORGIA purchased 732.8 million kilowatt-hours at a cost of $33 million from
this facility. Reference is made to Note 4 to the financial statements for
GEORGIA in Item 8 herein for information regarding purchase power commitments.
I-12
GULF currently has agreements in effect with four industrial customers
pursuant to which GULF purchases "as available" energy from customer-owned
generation. During 1998, GULF purchased 151 million kilowatt-hours from such
companies for $4.2 million.
In 1996, MISSISSIPPI entered into agreements to purchase options for summer
peaking power for the years 1997 through 2000. Also, MISSISSIPPI has purchased
options from power marketers. Reference is made to Note 5 to the financial
statements for MISSISSIPPI in Item 8 herein for information regarding fuel and
purchased power commitments.
SAVANNAH currently has cogeneration contracts in effect with six large
customers. Under the terms of these contracts, SAVANNAH purchases excess
generation of such companies. During 1998, SAVANNAH purchased 23 million
kilowatt-hours from such companies at a cost of $1.3 million.
The competition for retail energy sales among competing suppliers of energy
is influenced by various factors, including price, availability, technological
advancements and reliability. These factors are, in turn, affected by, among
other influences, regulatory, political and environmental considerations,
taxation and supply.
The operating affiliates have experienced, and expect to continue to
experience, competition in their respective retail service territories in
varying degrees as the result of self-generation (as described above) and fuel
switching by customers and other factors. (See also Item 1 - BUSINESS -
"Territory Served By Operating Affiliates" herein for information concerning
suppliers of electricity operating within or near the areas served at retail by
the operating affiliates.)
Regulation
State Commissions
The operating affiliates 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 By Operating Affiliates" herein.)
In early 1999, the Florida PSC staff initiated informal discussions with
GULF related to its authorized return on equity and the outstanding balances of
certain regulatory assets. On March 2, 1999, GULF filed a petition with the
Florida PSC proposing a reduction in its authorized return; the sharing of
revenues above a certain earnings level, which included credits on customers'
bills; and the write-off of certain regulatory assets. A recommendation by the
Florida PSC staff was also filed with the Commission relating to the same
issues. At the March 16, 1999, agenda conference, the Commission directed GULF
and the Florida PSC staff to reconvene their discussions, working within a
framework established by the Commission, and pursue a compromise to be presented
at the April 20, 1999, agenda conference or shortly thereafter.
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.
While various proposals have been introduced in Congress regarding the
Holding Company Act, the prospects for legislative reform or repeal are
uncertain at this time.
I-13
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.
Reference is made to Note 3 to each registrant's financial statements
(except SAVANNAH) in Item 8 herein for further information regarding FERC
Reviews of Equity Returns.
ALABAMA and GEORGIA are also subject to the provisions of the Federal Power
Act or the earlier Federal Water Power Act applicable to licensees with respect
to their hydroelectric developments. Among the hydroelectric projects subject to
licensing by the FERC are 14 existing ALABAMA generating stations having an
aggregate installed capacity of 1,582,725 kilowatts and 18 existing GEORGIA
generating stations having an aggregate installed capacity of 1,074,696
kilowatts.
GEORGIA filed, in September, 1996, with the FERC, a notice of its intent to
seek a new license for the Flint River Project. GEORGIA is required to file a
new license by September 1999. GEORGIA filed an application for a new license
for the Flint River Project (FERC Project Number 1218) in November 1998 with the
FERC. The application contained an APEA. The FERC noticed the application in the
Federal Register on January 15, 1999. Comments on the APEA are due by March
1999. Since all outstanding issues were resolved prior to the submittal of the
APEA, GEORGIA anticipates that a license will be issued by the FERC by the
summer or fall of 1999.
GEORGIA has also started the relicensing process for the Middle
Chattahoochee Project (FERC Project Number 2177). This project consists of the
Goat Rock, Oliver, and North Highlands facilities. GEORGIA again plans to use
the APEA process. Initial scoping and stakeholder involvement has occurred.
GEORGIA is developing its final scoping document that outlines the proposed
environmental studies. Initial field work is anticipated to start in the second
quarter of 1999.
GEORGIA and OPC also have a license, expiring in 2027, for the Rocky
Mountain Plant, a pure pumped storage facility of 847,800 kilowatt capacity
which began commercial operation in 1995. (See Item 2 - PROPERTIES -
"Jointly-Owned Facilities" herein and Note 3 to SOUTHERN's and GEORGIA's
financial statements in Item 8 herein for additional information.)
Licenses for all projects, excluding those discussed above, expire in the
period 2007-2033 in the case of ALABAMA's projects and in the period 2005-2036
in the case of GEORGIA's projects.
Upon or after the expiration of each license, the United States Government,
by act of Congress, may take over the project, or the FERC may relicense the
project either to the original licensee or to a new licensee. In the event of
takeover or relicensing to another, the original licensee is to be compensated
in accordance with the provisions of the Federal Power Act, such compensation to
reflect the net investment of the licensee in the project, not in excess of the
fair value of the property taken, plus reasonable damages to other property of
the licensee resulting from the severance therefrom of the property taken.
Atomic Energy Act of 1954
ALABAMA, GEORGIA and Southern Nuclear are subject to the provisions of the
Atomic Energy Act of 1954, as amended, which vests jurisdiction in the NRC over
the construction and operation of nuclear reactors, particularly with regard to
certain public health and safety and antitrust matters. The National
Environmental Policy Act has been construed to expand the jurisdiction of the
NRC to consider the environmental impact of a facility licensed under the Atomic
Energy Act of 1954, as amended.
NRC operating licenses currently expire in June 2017 and March 2021 for
Plant Farley units 1 and 2, respectively, in August 2014 and June 2018 for Plant
Hatch units 1 and 2, respectively, and in January 2027 and February 2029 for
Plant Vogtle units 1 and 2, respectively.
Reference is made to Notes 1 and 12 to SOUTHERN's, Notes 1 and 12 to
ALABAMA's and Notes 1 and 5 to GEORGIA's financial statements in Item 8 herein
for information on nuclear decommissioning costs and nuclear insurance.
Additionally, Note 3 to GEORGIA's financial statements contains information
I-14
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.
The operating affiliates' and SEGCO's estimated capital expenditures for
environmental quality control facilities for the years 1999, 2000 and 2001
are as follows: (in millions)
--------------------- --- ---------- ---------- -----------
1999 2000 2001
---------- ---------- -----------
ALABAMA $61.9 $57.6 $ 75.7
GEORGIA 32.2 53.3 102.8
GULF 4.5 4.3 1.2
MISSISSIPPI 9.0 - -
SAVANNAH 0.1 0.2 -
SEGCO 10.0 - -
---------- ---------- -----------
Total $117.7 $115.4 $179.7
===================== === ========== ========== ===========
*The foregoing estimates are included in the current construction programs.
(See Item 1 - BUSINESS - "Construction Programs" herein.)
Additionally, each operating affiliate and SEGCO has incurred costs for
environmental remediation of various sites. Reference is made to each
registrant's "Management's Discussion and Analysis" in Item 7 herein for
information regarding the registrants' environmental remediation efforts. Also,
see Note 3 to SOUTHERN's and GEORGIA's financial statements in Item 8 herein for
information regarding the identification of sites that may require environmental
remediation by GEORGIA and Note 3 to MISSISSIPPI's financial statements in Item
8 herein for information regarding a site that will require environmental
remediation by MISSISSIPPI.
The operating affiliates and SEGCO are unable to predict at this time what
additional steps they may be required to take as a result of the implementation
of existing or future quality control requirements for air, water and hazardous
or toxic materials, but such steps could adversely affect system operations and
result in substantial additional costs.
The outcome of the matters mentioned above under "Regulation" cannot now be
determined, except that these developments may result in delays in obtaining
appropriate licenses for generating facilities, increased construction and
operating costs, or reduced generation, the nature and extent of which, while
not determinable at this time, could be substantial.
Rate Matters
Rate Structure
The rates and service regulations of the operating affiliates are uniform for
each class of service throughout their respective service areas. Rates for
residential electric service are generally of the block type based upon
kilowatt-hours used and include minimum charges.
Residential and other rates contain separate customer charges. Rates for
commercial service are presently of the block type and, for large customers, the
billing demand is generally used to determine capacity and minimum bill charges.
These large customers' rates are generally based upon usage by the customer
including those with special features to encourage off-peak usage. Additionally,
the operating affiliates are allowed by their respective PSCs to negotiate the
terms and compensation of service to large customers. Such terms and
I-15
compensation of service, however, are subject to final PSC approval. 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 recovers from retail customers costs
of fuel, net purchased power, energy conservation and environmental compliance
through provisions which are adjusted to reflect increases or decreases in such
costs. GULF's recovery of these costs is based upon an annual projection - any
over/under recovery during such period is reflected in a subsequent annual
period with interest. With respect to MISSISSIPPI's retail rates, fuel and
purchased power costs above base levels included in the various rate schedules
are billed to such customers under the fuel and energy adjustment clause. The
adjustment factors for MISSISSIPPI's retail and wholesale rates are generally
levelized based on the estimated energy cost for the year, adjusted for any
actual over/under collection from the previous year. However, in January 1998,
MISSISSIPPI received approval from the Mississippi PSC to levelize and fix its
Fuel Adjustment Factors for January 1998 through December 2000. Revenues are
adjusted for differences between recoverable fuel costs and amounts actually
recovered in current rates.
Rate Proceedings
Reference is made to Note 3 to each registrant's financial statements in Item 8
herein for a discussion of rate matters. For each registrant (except SAVANNAH),
such Note 3 includes a discussion of proceedings relating to the reasonableness
of certain of the Southern electric system's wholesale rate schedules and
contracts.
Integrated Resource Planning
In 1991, the Georgia legislature passed certain legislation under which both
GEORGIA and SAVANNAH must file Integrated Resource Plans for approval by the
Georgia PSC. The plans must specify how GEORGIA and SAVANNAH each intends to
meet the future electrical needs of their customers through a combination of
demand-side and supply-side resources. The Georgia PSC must pre-certify these
new resources. Once certified, all prudently incurred construction costs and
purchased power costs will be recoverable through rates.
In March 1997, the Georgia PSC approved amendments to GEORGIA's 1995
Integrated Resource Plan. Pursuant to the amended plan, the Georgia PSC
certified a five-year purchase power agreement scheduled to begin in June 2000
for approximately 215 megawatts. Capacity and fixed operation and maintenance
payments are estimated to be between $7 million and $8 million each year. Also
under the amended plan, resources associated with decreased purchases of 250
megawatts each in 1996, 1997 and 1998 by OPC under a power supply agreement will
be used to meet the needs of GEORGIA's retail customers through 2004.
In July 1998, the Georgia PSC approved GEORGIA's and SAVANNAH's 1998
Integrated Resource Plans as filed, with minor modifications. The approved plans
identify resource needs of approximately 800 megawatts to 1,200 megawatts
starting in the summer of 2002. As a result, GEORGIA and SAVANNAH issued a joint
request for proposals for their collective needs of 800 megawatts to 1,200
megawatts for 2002 and 2003. The bids will be evaluated against self-build
options, and a Certification Filing for the selected resources is expected to be
filed with the Georgia PSC in August 1999.
Environmental Cost Recovery Plans
GULF and MISSISSIPPI both have retail rate mechanisms that provide for recovery
of environmental compliance costs. For a description of these plans, see Note 3
to GULF's and MISSISSIPPI's financial statements in Item 8 herein.
I-16
Employee Relations
The companies of the SOUTHERN system had a total of 31,848 employees on their
payrolls at December 31, 1998.
-------------------------------- --- -------------------------
Employees
at
December 31, 1998
-------------------------
ALABAMA 6,631
GEORGIA 8,371
GULF 1,328
MISSISSIPPI 1,230
SAVANNAH 542
SCS 3,445
Southern Energy* 6,642
Southern Nuclear 3,054
Other 605
-------------------------------- --- -------------------------
Total 31,848
================================ === =========================
*Includes 5,670 employees on international payrolls.
The operating affiliates have separate agreements with local unions of the
IBEW generally covering wages, working conditions and procedures for handling
grievances and arbitration. These agreements apply with certain exceptions to
operating, maintenance and construction employees.
ALABAMA has agreements with the IBEW on a three-year contract extending to
August 14, 2001. 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, 1999.
GULF has an agreement with the IBEW on a three-year contract extending to
August 15, 2001.
MISSISSIPPI has an agreement with the IBEW on a four-year contract extending
to August 16, 2002.
SAVANNAH has three-year labor agreements with the IBEW and the Office and
Professional Employees International Union that expire April 16, 1999 and
December 1, 1999, respectively. Currently, SAVANNAH is in negotiations with the
IBEW.
Southern Energy has a 5-year labor agreement with the IBEW extending to
October 31, 2002, and the United Paperworkers International Union extending to
June 1, 2002, covering employees of Mobile Energy. At its State Line facility in
Hammond, Indiana, Southern Energy has a labor contract with the United Steel
Workers that extends to January 1, 2004.
Southern Energy Canal located in Sandwich, Massachusetts, and Southern
Energy Kendall located in Cambridge, Massachusetts, both subsidiaries of
Southern Energy, have contracts with the Utilities Workers' Union of America
which expire on June 1, 2001 and March 1, 2001, respectively.
Southern Nuclear has agreements with the IBEW on separate three-year
contracts extending to August 15, 2001 for Plant Farley and to July 1, 1999 for
Plants Hatch and Vogtle. Upon notice given at least 60 days prior to these
dates, negotiations may be initiated with respect to agreement terms to be
effective after such dates.
Southern Nuclear also has an agreement with the United Plant Guard Workers
of America for security officers at Plant Hatch extending to September 30, 2001.
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.
I-17
Item 2. PROPERTIES
Electric Properties
The operating affiliates and SEGCO, at December 31, 1998, operated 33
hydroelectric generating stations, 33 fossil fuel generating stations and three
nuclear generating stations. The amounts of capacity owned by each company are
shown in the table below.
------------------------- -------------------------------------
Nameplate
Generating Station Location Capacity (1)
------------------------- ------------------- -----------------
(Kilowatts)
Fossil Steam
Gadsden Gadsden, AL 120,000
Gorgas Jasper, AL 1,221,250
Barry Mobile, AL 1,525,000
Chickasaw Chickasaw, AL 40,000
Greene County Demopolis, AL 300,000 (2)
Gaston Unit 5 Wilsonville, AL 880,000
Miller Birmingham, AL 2,532,288 (3)
---------
ALABAMA Total 6,618,538
---------
Arkwright Macon, GA 160,000
Atkinson Atlanta, GA 180,000
Bowen Cartersville, GA 3,160,000
Branch Milledgeville, GA 1,539,700
Hammond Rome, GA 800,000
McDonough Atlanta, GA 490,000
McManus Brunswick, GA 115,000
Mitchell Albany, GA 170,000
Scherer Macon, GA 750,924 (4)
Wansley Carrollton, GA 925,550 (5)
Yates Newnan, GA 1,250,000
---------
GEORGIA Total 9,541,174
---------
Crist Pensacola, FL 1,045,000
Lansing Smith Panama City, FL 305,000
Scholz Chattahoochee, FL 80,000
Daniel Pascagoula, MS 500,000 (6)
Scherer Unit 3 Macon, GA 204,500 (4)
-----------
GULF Total 2,134,500
---------
Eaton Hattiesburg, MS 67,500
Sweatt Meridian, MS 80,000
Watson Gulfport, MS 1,012,000
Daniel Pascagoula, MS 500,000 (6)
Greene County Demopolis, AL 200,000 (2)
-----------
MISSISSIPPI Total 1,859,500
-----------
---------------------------------------------- ----------------
------------------------- -----------------------------------------
Nameplate
Generating Station Location Capacity
---------------------- ------------------------- ------------------
(Kilowatts)
McIntosh Effingham County, GA 163,117
Kraft Port Wentworth, GA 281,136
Riverside Savannah, GA 102,278
-----------
SAVANNAH Total 546,531
-----------
Gaston Units 1-4 Wilsonville, AL
SEGCO Total 1,000,000 (7)
-----------
Total Fossil Steam 21,700,243
-----------
Nuclear Steam
Farley Dothan, AL
ALABAMA Total 1,720,000
-----------
Hatch Baxley, GA 862,669 (8)
Vogtle Augusta, GA 1,060,240 (9)
-----------
GEORGIA Total 1,922,909
----------
Total Nuclear Steam 3,642,909
-----------
Combustion Turbines
Greene County Demopolis, AL
ALABAMA Total 720,000
Arkwright Macon, GA 30,580
Atkinson Atlanta, GA 78,720
Bowen Cartersville, GA 39,400
Intercession City Intercession City, FL 47,333 (10)
McDonough Atlanta, GA 78,800
McIntosh
Units 1,2,3,4,7,8 Effingham County, GA 480,000
McManus Brunswick, GA 481,700
Mitchell Albany, GA 118,200
Robins Warner Robins, GA 160,000
Wilson Augusta, GA 354,100
Wansley Carrollton, GA 26,322 (5)
-----------
GEORGIA Total 1,895,155
---------
Lansing Smith
Unit A Panama City, FL 39,400
Pea Ridge
Units 1-3 Pea Ridge, FL 14,250
GULF Total 53,650
Chevron Cogenerating
Station Pascagoula, MS 147,292 (11)
Sweatt Meridian, MS 39,400
Watson Gulfport, MS 39,360
---------
MISSISSIPPI Total 226,052
---------
------------------------------------------------- -----------------
I-18
--------------------------- -------------------- -----------------
Nameplate
Generating Station Location Capacity
--------------------------- -------------------- -----------------
(Kilowatts)
Boulevard Savannah, GA 59,100
Kraft Port Wentworth, GA 22,000
McIntosh
Units 5&6 Effingham County, 160,000
-------
GA
SAVANNAH Total 241,100
241,100
Gaston (SEGCO) Wilsonville, AL 19,680 (7)
Total Combustion Turbines 3,155,637
Hydroelectric Facilities
Weiss Leesburg, AL 87,750
Henry Ohatchee, AL 72,900
Logan Martin Vincent, AL 128,250
Lay Clanton, AL 177,000
Mitchell Verbena, AL 170,000
Jordan Wetumpka, AL 100,000
Bouldin Wetumpka, AL 225,000
Harris Wedowee, AL 135,000
Martin Dadeville, AL 154,200
Yates Tallassee, AL 32,000
Thurlow Tallassee, AL 58,000
Lewis Smith Jasper, AL 157,500
Bankhead Holt, AL 45,125
Holt Holt, AL 40,000
-----------
ALABAMA Total 1,582,725
----------
Barnett Shoals
(Leased) Athens, GA 2,800
Bartletts Ferry Columbus, GA 173,000
Goat Rock Columbus, GA 26,000
Lloyd Shoals Jackson, GA 14,400
Morgan Falls Atlanta, GA 16,800
North Highlands Columbus, GA 29,600
Oliver Dam Columbus, GA 60,000
Rocky Mountain Rome, GA 215,256 (12)
Sinclair Dam Milledgeville, GA 45,000
Tallulah Falls Clayton, GA 72,000
Terrora Clayton, GA 16,000
Tugalo Clayton, GA 45,000
Wallace Dam Eatonton, GA 321,300
Yonah Toccoa, GA 22,500
6 Other Plants 18,080
-----------
GEORGIA Total 1,077,736
----------
Total Hydroelectric Facilities 2,660,461
-----------
Total Generating Capacity 31,159,250
------------------------------------------------ -----------------
Notes:
(1) For additional information regarding facilities jointly-owned with
non-affiliated parties, see Item 2 - PROPERTIES -
"Jointly-Owned Facilities" herein.
(2) Owned by ALABAMA and MISSISSIPPI as
tenants in common in the proportions of 60% and 40%, respectively.
(3) Excludes the capacity owned by AEC.
(4) Capacity shown for GEORGIA is 8.4% of Units 1 and 2 and 75% of Unit 3.
Capacity shown for GULF is 25% of Unit 3.
(5) Capacity shown is GEORGIA's portion (53.5%) of total plant capacity.
(6) Represents 50% of the plant which is owned as tenants in common by
GULF and MISSISSIPPI.
(7) SEGCO is jointly-owned by ALABAMA and GEORGIA. (See Item 1 - BUSINESS
herein.)
(8) Capacity shown is GEORGIA's portion (50.1%) of total plant capacity.
(9) Capacity shown is GEORGIA's portion (45.7%) of total plant capacity.
(10) Capacity shown represents 33-1/3% of total plant capacity. GEORGIA
owns a 1/3 interest in the unit with 100% use of the
unit from June through September. FPC operates the unit.
(11) Generation is dedicated to a single industrial customer.
(12) Capacity shown is GEORGIA's portion (25.4%) of total plant capacity.
OPC operates the plant.
Except as discussed below under "Titles to Property," the principal plants
and other important units of the operating affiliates and SEGCO are owned in fee
by the respective companies. 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 Entergy Gulf States. The line, completed in 1984, extends from Plant
Daniel to the Louisiana state line. Entergy 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. At December 31, 1998, the unamortized portion of
this cost was $37 million.
The all-time maximum demand on the operating affiliates and SEGCO was
28,933,700 kilowatts and occurred in June 1998. This amount excludes demand
served by capacity retained by MEAG and Dalton and excludes demand associated
I-19
with power purchased from OPC and SEPA by its preference customers. The reserve
margin for the operating affiliates and SEGCO at that time was 12.8%. For
additional information on 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 -
"Regulation - Atomic Energy Act of 1954" and Note 1 to SOUTHERN's, ALABAMA's and
GEORGIA's financial statements in Item 8 herein.)
Other Electric Generation Facilities
Through special purpose subsidiaries, SOUTHERN owns interests in or operates
independent power production facilities and foreign utility companies. The
generating capacity of these utilities (or facilities) at December 31, 1998, was
as follows:
Facilities in Operation
------------------------------------------------------------------------------------------------------------------
Megawatts of Capacity Percent
Facility Location Units Owned Operated Ownership Type
---------------- --------------------------- --------- ------------ ------------- ----------------- -------------
Alicura Argentina 4 551 (1) 1,000 55.14 (1) Hydro
BEWAG Germany 18 443 - 26.00 Coal
BEWAG Germany 17 375 - 26.00 Oil & Gas
Birchwood Virginia 1 111 222 50.00 Coal (2)
CEPA China 3 634 - (3) 32.00 Coal
CEPA Philippines 2 641 735 87.22 Coal
CEPA Philippines 3 189 210 90.00 Oil
CEPA Philippines 13 381 381 100.00 Oil
CEMIG Brazil 33 193 - 3.60 Hydro
CEMIG Brazil 2 5 - 3.60 Thermal
CEMIG Brazil 1 - - 3.60 Wind
Edelnor Chile 2 281 341 82.34 Coal
Edelnor Chile 37 95 115 82.34 Oil
Edelnor Chile 2 8 10 82.34 Hydro
Freeport Grand Bahamas 8 79 126 62.50 Oil & Gas
Mobile Energy Alabama 3 111 111 100.00 Waste/Biomass (2)
Penal Trinidad and Tobago 5 92 236 39.00 Gas
Port of Spain Trinidad and Tobago 6 120 308 39.00 Gas
Pt. Lisas Trinidad and Tobago 10 247 634 39.00 Gas
State Line Indiana 2 490 490 100.00 Coal
SWEB United Kingdom 8 71 - (3) 3.77 Gas
SWEB United Kingdom 12 8 16 49.00 Oil & Gas
SWEB United Kingdom 3 3 - (3) 18.62 Wind
SWEB United Kingdom 3 - - 12.25 Landfill Gas
SE New
England Maine 8 1,267 1,267 100.00 Oil & Gas
======================================================================================================================
Total Capacity 6,395 6,202 (3)
=======================================================================================================================
I-20
Notes: (1) Represents megawatts of capacity under a concession agreement expiring in the year 2023.
(2) Cogeneration facility.
(3) Does not include Shajiao C (1,980 MW) or UK power plants (150 MW) that are partially owned but not operated by
CEPA and SWEB, respectively.
Facilities Under Development
-------------------------------------------------------------------------------------------------------------------------------
Megawatts of Capacity Percent
Facility Location Units Own Operate Ownership Type
-------------------------------------------------------------------------------------------------------------------------------
CEMIG Brazil 1 1 - 3.60 Hydro
CEPA Philippines 2 1,121 1,218 92.00 Coal
Edelnor Chile 1 206 250 82.34 Gas
-------------------------------------------------------------------------------------------------------------------------------
Total Capacity 1,328 1,468
===============================================================================================================================
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 FPC
------------- ----------- -------- ------------ -------- --------- --------- --------
(Megawatts)
Plant Miller
Units 1 and 2 1,320 91.8% 8.2% -% -% -% -% -%
Plant Hatch 1,722 - - 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 -
Plant Wansley 1,779 - - 53.5 30.0 15.1 1.4 -
Rocky Mountain 848 - - 25.4 74.6 - - -
Intercession City, FL 142 - - 33.3 - - - 66.7
----------------------------- ------------- ----------- -------- ------------ -------- --------- --------- --------
ALABAMA and GEORGIA have contracted to operate and maintain the respective
units in which each has an interest (other than Rocky Mountain and Intercession
City, as described below) as agent for the joint owners.
In connection with the joint ownership arrangements for Plant Vogtle,
GEORGIA made commitments to purchase portions of OPC's and MEAG's capacity and
energy from this plant. Declining commitments were in effect during periods of
up to seven years following commercial operation and ended in 1996. In addition,
the Company has commitments regarding a portion of a 5 percent interest in Plant
Vogtle owned by MEAG that are in effect until the later of retirement of the
plant or the latest stated maturity date of MEAG's bonds issued to finance such
ownership interest. The payments for capacity are required whether any capacity
is available. The energy cost is a function of each unit's variable operating
costs. Except for the portion of the capacity payments related to the 1987 and
1990 write-offs of Plant Vogtle costs, the cost of such capacity and energy is
included in purchased power from non-affiliates in GEORGIA's Statements of
Income in Item 8 herein.
In December 1988, GEORGIA and OPC entered into a joint ownership agreement
for the Rocky Mountain plant under which GEORGIA agreed to retain its present
investment in the project and OPC agreed to finance, complete and operate the
facility. In 1995, the plant went into commercial operation. GEORGIA's ownership
I-21
is 25.4 percent. On January 14, 1998, the GPSC ordered that the Company be
allowed approximately $108 million of its $142 million investment in the plant
in rate base as of December 31, 1998. GEORGIA appealed the GPSC's order. Under
the rate order approved by the GPSC on December 18, 1998, GEORGIA voluntarily
dismissed the appeal. As a result, in December 1998, GEORGIA recorded a charge
to earnings of $21 million, after taxes, associated with the write-down of the
plant. Reference is made to Note 3 to SOUTHERN's and GEORGIA's financial
statements in Item 8 herein for additional information regarding the Rocky
Mountain plant.
In 1994, GEORGIA and FPC entered into a joint ownership agreement regarding
the Intercession City combustion turbine unit. The unit began commercial
operation in January 1997, and is operated by FPC. GEORGIA owns a one-third
interest in the unit, with use of 100% of the capacity from June through
September. FPC has the capacity the remainder of the year.
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 five 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, 1994 to December 31, 1998, the operating
affiliates, SEGCO, SCS, Southern Nuclear, Southern LINC and Southern Energy
recorded gross property additions and retirements as follows:
------------------------- ------------------- --- ----------
Gross Property
Additions Retirements
--------------- -------------
(in millions)
ALABAMA $2,576 $ 426
GEORGIA (1) 2,522 1,263
GULF 327 131
MISSISSIPPI 357 98
SAVANNAH 122 13
SEGCO 27 8
SCS 108 171
Southern Nuclear 4 6
Southern
LINC 300 48
Southern Energy 1,677 54
Other 10 -
============================ =========== == ================
SOUTHERN system $8,030 $2,218
============================ =========== == ================
Notes:
(1) Includes approximately $229 million attributable to sales of Plant
Scherer Unit 4 to FP&L and JEA.
I-22
Item 3. LEGAL PROCEEDINGS
(1) Frost v. ALABAMA
(Circuit Court of Jefferson County, Alabama)
Reference is made to Note 3 to SOUTHERN's and ALABAMA's financial
statements in Item 8 herein under the captions "Alabama Power Appliance
Warranty Litigation" and "Appliance Warranty Litigation", respectively.
(2) Sullivan v. ALABAMA et al.
(Circuit Court of Jefferson County, Alabama)
Reference is made to Note 3 to SOUTHERN's and ALABAMA's financial
statements in Item 8 herein under the captions "Alabama Power
Environmental Litigation" and "Environmental Litigation", respectively.
(3) GEORGIA has been designated as a potentially responsible party under the
Comprehensive Environmental Response, Compensation and Liability Act with
respect to a site in Brunswick, Georgia.
Reference is made to Note 3 to SOUTHERN's and GEORGIA's financial
statements in Item 8 herein under the captions "Georgia Power Potentially
Responsible Party Status" and "Certain Environmental Contingencies,"
respectively.
(4) In re: Mobile Energy Services Company, LLC; In re: Mobile Energy
Services Holdings, Inc.
(U.S. Bankruptcy Court for the Southern District of Alabama).
In January 1999, Mobile Energy, an indirect subsidiary of SOUTHERN, and
its direct parent filed petitions for Chapter 11 bankruptcy relief in the
U.S. Bankruptcy Court for the Southern District of Alabama. For
additional information regarding this matter, reference is made to Note 3
to SOUTHERN's financial statements in Item 8 herein. In March 1999,
SOUTHERN paid a total of approximately $36 million in respect of guaranty
and reimbursement agreements previously entered into by it for the
benefit of Mobile Energy creditors.
See Item 1 - BUSINESS - "Construction Programs," "Fuel Supply," "Regulation
- - - - - - - - Federal Power Act" and "Rate Matters" as well as Note 3 to each registrant's
financial statements in Item 8 herein for a description of certain other
administrative and legal proceedings discussed therein.
Additionally, each of the operating affiliates, Southern Energy, SCS,
Southern Nuclear, Energy Solutions and Southern LINC are, in the normal course
of business, engaged in litigation or administrative proceedings that include,
but are not limited to, acquisition of property, injuries and damages claims,
and complaints by present and former employees.
Item 4. SUBMISSION OF MATTERS TO A
VOTE OF SECURITY HOLDERS
None.
I-23
EXECUTIVE OFFICERS OF SOUTHERN
(Identification of executive officers of SOUTHERN is inserted in Part I in
accordance with Regulation S-K, Item 401(b), Instruction 3.) The ages of the
officers set forth below are as of December 31, 1998.
A. W. Dahlberg
Chairman, President and Chief Executive Officer
Age 58
Elected Director in 1985, President effective January 1994, and Chairman and
Chief Executive Officer effective March 1995.
Paul J. DeNicola
Executive Vice President and Director
Age 50
Elected Director in 1989 and Executive Vice President of SOUTHERN in 1991. He
also has served as President and Chief Executive Officer of SCS since January
1994.
H. Allen Franklin
Executive Vice President and Director
Age 54
Elected Director in 1988 and Executive Vice President in 1991. He also has
served as President and Chief Executive Officer of GEORGIA since January 1994.
Elmer B. Harris
Executive Vice President and Director
Age 59
Elected Director in 1989, and Executive Vice President in 1991. He also has
served as President and Chief Executive Officer of ALABAMA since 1989.
Thomas G. Boren
Senior Vice President
Age 49
Elected in 1995. He also has served as President and Chief Executive Officer of
Southern Energy since 1992.
Stephen A. Wakefield
Senior Vice President and General Counsel
Age 58
Elected in 1997. Previously, he was a partner at the law firm of Akin, Gump,
Strauss, Hauer & Feld, LLP from July 1991 through August 1997.
W. L. Westbrook
Financial Vice President, Chief Financial Officer and Treasurer
Age 59
Elected in 1986; responsible primarily for all aspects of financing for
SOUTHERN. He also has served as Executive Vice President of SCS since 1986.
C. Alan Martin
Vice President
Age 50
Elected in 1998; serves as Chief Marketing Officer for the SOUTHERN system.
Previously Vice President of Human Resources of SOUTHERN from 1995 to February
1998, and Vice President of ALABAMA from 1987 to 1995.
Charles D. McCrary
Vice President
Age 47
Elected in 1998; serves as Chief Production Officer for the SOUTHERN system. He
also has served as Executive Vice President of GEORGIA since May 1998 and
Executive Vice President of ALABAMA since 1994. Previously served as Senior Vice
President of ALABAMA from 1991 to 1994.
W. G. Hairston, III
Age 53
President and Chief Executive Officer of Southern Nuclear since 1993.
The officers of SOUTHERN were elected for a term running from the last
annual meeting of the directors (May 27, 1998) for one year until the next
annual meeting or until their successors are elected and have qualified.
I-24
PART II
Item 5. MARKET FOR REGISTRANTS' COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
(a) The common stock of SOUTHERN is listed and traded on the New York
Stock Exchange. The stock is also traded on regional exchanges across
the United States. High and low stock prices, per the New York Stock
Exchange Composite Tape during each quarter for the past two years
were as follows:
------------------------ ----------- --- --------------
High Low
----------- --------------
1998
First Quarter $28-11/16 $23-15/16
Second Quarter 29 25-1/16
Third Quarter 29-13/16 25-1/4
Fourth Quarter 31-9/16 27-3/16
1997
First Quarter $23-3/8 $20-3/4
Second Quarter 22-1/4 19-7/8
Third Quarter 23 20-13/16
Fourth Quarter 26-1/4 22
-------------------- --------------- --- --------------
There is no market for the other registrants' common stock, all of
which is owned by SOUTHERN. On February 28, 1999, the closing price
of SOUTHERN's common stock was $25.0625.
(b) Number of SOUTHERN's common stockholders
at December 31, 1998:
187,053
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 1998 1997
------------------- --------- ------------- ----------
SOUTHERN First $232,449 $220,194
Second 233,623 221,544
Third 233,763 222,980
Fourth 233,506 224,287
ALABAMA First 90,400 80,100
Second 90,500 85,600
Third 90,800 86,100
Fourth 95,400 87,800
GEORGIA First 132,100 122,700
Second 132,300 131,000
Third 132,700 131,800
Fourth 139,500 134,500
GULF First 14,100 12,900
Second 14,100 13,800
Third 14,100 13,800
Fourth 14,900 24,100
MISSISSIPPI First 12,700 11,300
Second 12,800 12,100
Third 12,800 12,200
Fourth 13,400 13,800
SAVANNAH First 5,800 5,100
Second 5,800 5,400
Third 5,800 5,500
Fourth 6,100 4,500
------------------- --------- ------------- ----------
The dividend paid per share by SOUTHERN was 32.5(cent) for each quarter of
1997 and 33.5(cent) for each quarter of 1998. The dividend paid on SOUTHERN's
common stock for the first quarter of 1999 was 33.5(cent) per share.
II-1
The amount of dividends on their common stock that may be paid by the
subsidiary registrants is restricted in accordance with their first mortgage
bond indenture. The amounts of earnings retained in the business and the amounts
restricted against the payment of cash dividends on common stock at December 31,
1998, were as follows:
-------------------- ------------------ --- --------------
Retained Restricted
Earnings Amount
------------------ --------------
(in millions)
ALABAMA $1,225 $ 796
GEORGIA 1,780 897
GULF 171 127
MISSISSIPPI 174 118
SAVANNAH 113 68
Consolidated 3,878 2,003
-------------------- ------------------ --- --------------
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-45
through II-48.
ALABAMA. Reference is made to information under the heading
"Selected Financial and Operating Data," contained herein at pages II-80 through
II-83.
GEORGIA. Reference is made to information under the heading "Selected
Financial and Operating Data," contained herein at pages II-118 through II-121.
GULF. Reference is made to information under the heading "Selected
Financial and Operating Data," contained herein at pages II-151 through II-154.
MISSISSIPPI. Reference is made to information under the heading
"Selected Financial and Operating Data," contained herein at pages II-183
through II-186.
SAVANNAH. Reference is made to information under the heading
"Selected Financial and Operating Data," contained herein at pages II-211
through II-214.
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-19.
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-52 through II-60.
GEORGIA. Reference is made to information under the heading "Management's
Discussion and Analysis of Results of Operations and Financial Condition,"
contained herein at pages II-87 through II-96.
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-125 through II-133.
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-158 through II-166.
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-190 through II-197.
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Reference is made to information in SOUTHERN's "Management's Discussion
and Analysis - Derivative Financial Instruments" and to Note 1 to SOUTHERN's
financial statements under the headings "Financial Instruments for Non-Trading
Activities" and "Financial Instruments for Trading Activities" contained herein
on pages II-15 through II-16; and pages II-30 through II-32, respectively.
II-2
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO 1998 FINANCIAL STATEMENTS
Page
The Southern Company and Subsidiary Companies:
Report of Independent Public Accountants................................................................................ II-7
Consolidated Statements of Income for the Years Ended December 31, 1998, 1997 and 1996.................................. II-20
Consolidated Statements of Retained Earnings for the Years Ended
December 31, 1998, 1997 and 1996................................................................................ II-26
Consolidated Statements of Comprehensive Income for the Years Ended
December 31, 1998, 1997 and 1996................................................................................ II-26
Consolidated Statements of Accumulated Other Comprehensive Income for the Years Ended
December 31, 1998, 1997 and 1996................................................................................ II-26
Consolidated Statements of Cash Flows for the Years Ended December 31, 1998, 1997 and 1996.............................. II-21
Consolidated Balance Sheets at December 31, 1998 and 1997............................................................... II-22
Consolidated Statements of Capitalization at December 31, 1998 and 1997................................................. II-24
Consolidated Statements of Paid-In Capital for the Years Ended December 31, 1998, 1997 and 1996......................... II-26
Notes to Financial Statements........................................................................................... II-27
ALABAMA:
Report of Independent Public Accountants .............................................................................. II-51
Statements of Income for the Years Ended December 31, 1998, 1997 and 1996............................................... II-61
Statements of Cash Flows for the Years Ended December 31, 1998, 1997 and 1996........................................... II-62
Balance Sheets at December 31, 1998 and 1997 ........................................................................... II-63
Statements of Capitalization at December 31, 1998 and 1997 ............................................................. II-65
Statements of Retained Earnings for the Years Ended December 31, 1998, 1997 and 1996.................................... II-67
Statements of Paid-In Capital for the Years Ended December 31, 1998, 1997 and 1996...................................... II-67
Notes to Financial Statements........................................................................................... II-68
GEORGIA:
Report of Independent Public Accountants................................................................................ II-86
Statements of Income for the Years Ended December 31, 1998, 1997 and 1996............................................... II-97
Statements of Cash Flows for the Years Ended December 31, 1998, 1997 and 1996........................................... II-98
Balance Sheets at December 31, 1998 and 1997 ........................................................................... II-99
Statements of Capitalization at December 31, 1998 and 1997 ............................................................. II-100
Statements of Retained Earnings for the Years Ended December 31, 1998, 1997 and 1996.................................... II-103
Statements of Paid-In Capital for the Years Ended December 31, 1998, 1997 and 1996...................................... II-103
Notes to Financial Statements........................................................................................... II-104
GULF:
Report of Independent Public Accountants................................................................................ II-124
Statements of Income for the Years Ended December 31, 1998, 1997 and 1996............................................... II-134
Statements of Cash Flows for the Years Ended December 31, 1998, 1997 and 1996........................................... II-135
Balance Sheets at December 31, 1998 and 1997 ........................................................................... II-136
Statements of Capitalization at December 31, 1998 and 1997 ............................................................. II-138
Statements of Retained Earnings for the Years Ended December 31, 1998, 1997 and 1996.................................... II-140
Statements of Paid-In Capital for the Years Ended December 31, 1998, 1997 and 1996...................................... II-140
Notes to Financial Statements........................................................................................... II-141
III-3
Page
MISSISSIPPI:
Report of Independent Public Accountants................................................................................ II-157
Statements of Income for the Years Ended December 31, 1998, 1997 and 1996............................................... II-167
Statements of Cash Flows for the Years Ended December 31, 1998, 1997 and 1996........................................... II-168
Balance Sheets at December 31, 1998 and 1997 ........................................................................... II-169
Statements of Capitalization at December 31, 1998 and 1997 ............................................................. II-171
Statements of Retained Earnings for the Years Ended December 31, 1998, 1997 and 1996.................................... II-172
Statements of Paid-In Capital for the Years Ended December 31, 1998, 1997 and 1996...................................... II-172
Notes to Financial Statements........................................................................................... II-173
SAVANNAH:
Report of Independent Public Accountants................................................................................ II-189
Statements of Income for the Years Ended December 31, 1998, 1997 and 1996............................................... II-198
Statements of Retained Earnings for the Years Ended December 31, 1998, 1997 and 1996.................................... II-198
Statements of Cash Flows for the Years Ended December 31, 1998, 1997 and 1996........................................... II-199
Balance Sheets at December 31, 1998 and 1997 ........................................................................... II-200
Statements of Capitalization at December 31, 1998 and 1997 ............................................................. II-202
Notes to Financial Statements........................................................................................... II-203
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
None.
III-4
THE SOUTHERN COMPANY
AND SUBSIDIARY COMPANIES
FINANCIAL SECTION
II-5
MANAGEMENT'S REPORT
Southern Company and Subsidiary Companies 1998 Annual Report
The management of Southern Company has prepared -- and is responsible for -- the
consolidated financial statements and related information included in this
report. These statements were prepared in accordance with generally accepted
accounting principles appropriate in the circumstances and necessarily include
amounts that are based on the best estimates and judgments of management.
Financial information throughout this annual report is consistent with the
financial statements.
The company maintains a system of internal accounting controls to provide
reasonable assurance that assets are safeguarded and that books and records
reflect only authorized transactions of the company. Limitations exist in any
system of internal controls, however, based on a recognition that the cost of
the system should not exceed its benefits. The company believes its system of
internal accounting controls maintains an appropriate cost/benefit relationship.
The company's system of internal accounting controls is evaluated on an
ongoing basis by the company's internal audit staff. The company's independent
public accountants also consider certain elements of the internal control system
in order to determine their auditing procedures for the purpose of expressing an
opinion on the financial statements.
The audit committee of the board of directors, composed of five directors who
are not employees, provides a broad overview of management's financial reporting
and control functions. Periodically, this committee meets with management, the
internal auditors, and the independent public accountants to ensure that these
groups are fulfilling their obligations and to discuss auditing, internal
controls, and financial reporting matters. The internal auditors and independent
public accountants have access to the members of the audit committee at any
time.
Management believes that its policies and procedures provide reasonable
assurance that the company's operations are conducted according to a high
standard of business ethics.
In management's opinion, the consolidated financial statements present
fairly, in all material respects, the financial position, results of operations,
and cash flows of Southern Company and its subsidiary companies in conformity
with generally accepted accounting principles.
/s/ A. W. Dahlberg
A. W. Dahlberg
Chairman, President, and Chief Executive Officer
/s/ W. L. Westbrook
W. L. Westbrook
Financial Vice President, Chief Financial Officer,
and Treasurer
February 10, 1999
II-6
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Southern Company:
We have audited the accompanying consolidated balance sheets and consolidated
statements of capitalization of Southern Company (a Delaware corporation) and
subsidiary companies as of December 31, 1998 and 1997, and the related
consolidated statements of income, comprehensive income, retained earnings,
paid-in capital, accumulated other comprehensive income, and cash flows for each
of the three years in the period ended December 31, 1998. 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 consolidated financial statements (pages II-20 through
II-44) referred to above present fairly, in all material respects, the financial
position of Southern Company and subsidiary companies as of December 31, 1998
and 1997, and the results of their operations and their cash flows for each of
the three years in the period ended December 31, 1998, in conformity with
generally accepted accounting principles.
/s/ Arthur Andersen LLP
Arthur Andersen LLP
Atlanta, Georgia
February 10, 1999
II-7
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Southern Company and Subsidiary Companies 1998 Annual Report
RESULTS OF OPERATIONS
Earnings and Dividends
Southern Company's 1998 earnings of $1.2 billion -- excluding non-recurring
items -- established a new record high. Earnings were driven by higher energy
sales and from growth in the non-traditional business. However, reported
earnings in both 1998 and 1997 reflected significant charges. Reported earnings
for 1998 were $977 million or $1.40 per share compared with $972 million or
$1.42 per share in 1997. The traditional core business of selling electricity
in the southeastern United States remained strong, while the non-traditional
business results were adversely affected by a $200 million, after tax, write
down of assets in South America in 1998 and by a $111 million windfall profits
tax assessed in the United Kingdom in 1997. Southern Company's subsidiary that
owns and manages its international and domestic non-traditional electric power
production and delivery facilities is Southern Energy, Inc. (Southern Energy).
After excluding these non-recurring charges, Southern Energy accounted for
approximately 20 percent and 10 percent of Southern Company's reported net
income in 1998 and 1997, respectively.
A reconciliation of reported earnings to earnings excluding non-recurring
items and explanations are as follows:
Consolidated Earnings
Net Income Per Share
--------------- ----------------
1998 1997 1998 1997
---------------- ----------------
(in millions)
Earnings as reported $ 977 $ 972 $1.40 $1.42
- - - - - - - ---------------------------------------------------------------
Write down of assets:
South American
investments 200 - .29 -
Rocky Mountain
plant 21 - .03 -
Windfall profits tax - 111 - .16
Work force reduction
programs 20 31 .03 .05
Other 7 16 .01 .02
- - - - - - - ---------------------------------------------------------------
Total non-recurring 248 158 .36 .23
- - - - - - - ---------------------------------------------------------------
Earnings excluding
non-recurring items $1,225 $1,130 $1.76 $1.65
===============================================================
Amount and
percent change $95 8.4% $0.11 6.7%
- - - - - - - ---------------------------------------------------------------
Southern Energy's 1998 write down is related to its investments in Argentina
and Chile not meeting financial expectations, which resulted in an announced
plan to sell these assets. In 1997, Southern Energy -- as well as other
utilities in the United Kingdom -- was assessed a one-time tax on profits. In
1998, Georgia Power resolved a long-term issue related to its investment in the
Rocky Mountain pumped storage hydroelectric plant. The write down resulted from
a settlement of Georgia Power's 1998 retail rate proceeding. Also, work force
reduction programs in the traditional core business were implemented in 1998 and
1997. These costs are expected to be recovered through future savings within
approximately two years following each program's implementation.
Dividends paid on common stock during 1998 were $1.34 per share or 33 1/2
cents per quarter. During 1997 and 1996, dividends paid per share were $1.30 and
$1.26, respectively. In January 1999, Southern Company maintained the quarterly
dividend at 33 1/2 cents per quarter or $1.34 annually. Southern Company has
modified its dividend policy from a targeted 75 percent payout ratio to a lower
ratio over time. This policy supports Southern Company's strategic goal to
become the best investment in the electric utility industry.
Revenues
Operating revenues changed in 1998 and 1997 as a result of the following
factors:
Increase (Decrease)
From Prior Year
- - - - - - - ---------------------------------------------------------------
1998 1997 1996
- - - - - - - ---------------------------------------------------------------
(in millions)
Retail --
Growth and price
change $ 258 $ 105 $ 124
Weather 178 (110) (64)
Fuel cost recovery and
other 189 (13) 2
- - - - - - - ---------------------------------------------------------------
Total retail 625 (18) 62
- - - - - - - ---------------------------------------------------------------
Sales for resale --
Within service area (2) (33) 10
Outside service area 12 81 14
- - - - - - - ---------------------------------------------------------------
Total sales for resale 10 48 24
Southern Energy (1,934) 2,154 1,040
Other operating revenues 91 69 52
- - - - - - - ---------------------------------------------------------------
Total operating revenues $(1,208) $2,253 $1,178
===============================================================
Percent change (9.6)% 21.8% 12.8%
- - - - - - - ---------------------------------------------------------------
Retail revenues of $8.3 billion increased sharply, up 8.2 percent compared
with last year. Continued growth in the traditional service area and the
II-8
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 1998 Annual Report
positive impact of weather on energy sales were the predominant factors causing
the rise in revenues. In 1997, retail revenues decreased by 0.2 percent compared
with the year 1996. Under fuel cost recovery provisions, fuel revenues generally
equal fuel expenses -- including the fuel component of purchased energy -- and
do not affect net income.
Sales for resale revenues within the service area were $374 million in 1998,
down 0.7 percent from the prior year. Revenues from sales for resale within the
service area were $376 million in 1997, down 8.1 percent from the prior year.
This sharp decline resulted primarily from supplying less electricity under
contractual agreements with certain wholesale customers in 1997.
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:
1998 1997 1996
- - - - - - - ----------------------------------------------------------------
(in millions)
Capacity $196 $203 $217
Energy 152 183 176
- - - - - - - ----------------------------------------------------------------
Total $348 $386 $393
================================================================
Capacity revenues in 1998 slightly declined as a result of adjustments and
true-ups related to contractual pricing. In 1997, capacity revenues decreased
because the amount of capacity under contract declined during 1996. Additional
declines in capacity are not scheduled until after 1999.
In 1998, Southern Energy's revenues declined because its energy trading and
marketing operations were deconsolidated on January 1, 1998, when Southern
Energy's joint venture with Vastar Resources, Inc. (Vastar) became effective.
Because of Vastar's significant participation rights in the joint venture, the
equity method of accounting is required. This results in Southern Energy's share
of the joint venture's earnings being reported in other income in 1998. In 1997,
Southern Energy reported energy trading and marketing revenues of $2.0 billion.
Southern Energy's revenues in 1998 of $1.9 billion increased $48 million
compared with comparable revenues in 1997 that exclude energy trading and
marketing. This increase results primarily from operations of assets obtained in
domestic acquisitions. In 1997, Southern Energy's revenues rose to $3.8 billion.
This increase was primarily attributable to the development and growth of energy
trading and marketing activities. In 1997, energy trading and marketing revenues
increased $1.9 billion compared with amounts recorded in 1996. However, these
revenues were substantially offset by purchased power expenses incurred in
completing these trading and marketing transactions. Energy trading and
marketing -- similar to other low-margin sales activities -- is dependent on
huge volumes for profitability.
Energy Sales
Changes in traditional core business revenues are influenced heavily by the
amount of energy sold each year. Kilowatt-hour sales for 1998 and the percent
change by year were as follows:
Amount Percent Change
(billions of --------- ------------------------------
kilowatt-hours) 1998 1998 1997 1996
- - - - - - - ------------------------------- -------------------------------
Residential 43.5 10.9% (2.2)% 2.5%
Commercial 41.7 7.2 2.5 5.7
Industrial 55.3 2.1 2.6 2.2
Other 1.0 3.1 (1.1) 5.7
-----
Total retail 141.5 6.2 1.1 3.3
Sales for resale --
Within service area 9.8 (0.4) (9.6) 15.4
Outside service area 13.0 (5.6) 27.7 17.9
-----
Total 164.3 4.7 2.2 5.0
=================================================================
The rate of growth in 1998 retail energy sales was the highest one-year
increase since 1986. Residential energy sales registered the highest annual
increase in over two decades as a result of hotter-than-normal weather and the
addition of 57,000 new customers. Commercial sales were also affected by the
warm weather. Commercial and industrial sales, both in 1998 and 1997, continued
to show slight gains in excess of the national averages. This reflects the
strength of business and economic conditions in Southern Company's traditional
service area. Energy sales to retail customers are projected to increase at an
average annual rate of 2.1 percent during the period 1999 through 2009.
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 declined by 5.6 percent in
1998 and increased by 27.7 percent in 1997 when compared with the respective
II-9
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 1998 Annual Report
prior year. The wide variances in sales were influenced by fluctuations in
prices for oil and natural gas, the primary fuel sources for utilities with
which the company has long-term contracts. When oil and gas prices fall below a
certain level, these customers can generate electricity to meet their
requirements more economically. However, these fluctuations in energy sales
under long-term contracts have minimal effects on earnings because Southern
Company is paid for dedicating specific amounts of its generating capacity to
these utilities outside the service area.
Expenses
Total operating expenses of $9.4 billion -- before write downs -- for 1998
decreased $1.2 billion compared with the prior year. Traditional core business
expenses increased $679 million. Southern Energy's expenses decreased $2.0
billion. The decline for Southern Energy corresponds to the decrease in revenues
resulting primarily from the deconsolidation of the energy trading and marketing
operations as discussed earlier. Approximately $2.0 billion of these expenses
were recorded in 1997 purchased power expenses. The costs to produce and deliver
electricity for the traditional core business in 1998 increased by $359 million
to meet higher energy demands. Non-production operation and maintenance expenses
increased $192 million in 1998. Traditional core business depreciation expenses
and taxes other than income taxes increased by $142 million as a result of
additional utility plant being placed into service and increased accelerated
depreciation of certain assets.
In 1997, operating expenses of $10.7 billion increased $2.2 billion compared
with 1996. Traditional core business expenses increased $69 million. Southern
Energy's expenses increased $2.1 billion. The large increase for Southern Energy
resulted primarily from two factors. First, the acquisition of CEPA was first
reflected in 1997 expenses. Second, $2.0 billion of energy trading and marketing
expenses were included in purchased power expenses. The costs to produce and
deliver electricity for the traditional core business in 1997 increased by $37
million to meet higher energy demands. Also, costs related to work force
reduction programs decreased in 1997 by $35 million. Traditional core business
depreciation expenses and taxes other than income taxes increased by $136
million as a result of additional utility plant being placed into service and
increased accelerated depreciation of certain assets.
Fuel costs constitute the single largest expense for Southern Company's
traditional core business. The mix of fuel sources for generation of electricity
is determined primarily by system load, the unit cost of fuel consumed, and the
availability of hydro and nuclear generating units. The amount and sources of
generation and the average cost of fuel per net kilowatt-hour generated --
within the core business service area -- were as follows:
1998 1997 1996
- - - - - - - -----------------------------------------------------------------
Total generation
(billions of kilowatt-hours) 164 160 156
Sources of generation
(percent) --
Coal 77 77 77
Nuclear 16 17 17
Hydro 4 4 4
Oil and gas 3 2 2
Average cost of fuel per net
kilowatt-hour generated
(cents) -- 1.48 1.46 1.48
- - - - - - - -----------------------------------------------------------------
Total fuel and purchased power costs of $3.6 billion in 1998 decreased $1.7
billion compared with 1997. The traditional core business increased $299 million
and Southern Energy decreased $2.0 billion. Southern Energy's reduction in fuel
and purchased power costs resulted from $2.0 billion associated with energy
trading and marketing expenses recorded in 1997 and from no energy trading costs
recorded in purchased power in 1998 as a result of the joint venture with Vastar
discussed earlier. The traditional core business's total energy sales rose by
7.4 billion kilowatt-hours more than in 1997. Fuel and purchased power expenses
of $5.3 billion in 1997 increased $2.0 billion compared with the prior year.
These expenses for traditional core business increased $32 million, and Southern
Energy's portion increased $1.9 billion. Southern Energy's increase in expenses
escalated as a result of energy trading and marketing activities discussed
earlier. The traditional core business's total energy sales went up by 3.4
billion kilowatt-hours more than in 1996. The additional cost to meet the demand
was offset slightly by a lower average cost of fuel per net kilowatt-hour
generated.
Total interest charges and other financing costs increased $91 million from
amounts reported in the previous year. These costs for the traditional core
business increased $48 million compared with the reported amounts in 1997.
Southern Energy's costs increased $47 million related primarily to financing of
acquisitions. In 1997, these same costs for traditional core business were flat,
but Southern Energy's interest charges increased $205 million as a result of
acquisitions.
II-10
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 1998 Annual Report
Effects of Inflation
Southern Company's traditional core business 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 Southern Company because of the large investment in utility plant with
long economic life. 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 securities. 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 Southern Company's future
earnings depends on numerous factors. Two major factors are: achieving energy
sales growth in a less regulated, more competitive environment; and operating
non-traditional business activities successfully.
Southern Company continues to position its business to meet the challenges of
a new competitive environment. Work force reduction programs have reduced
earnings by $20 million, $31 million, and $53 million for the years 1998, 1997,
and 1996, respectively. These actions -- in conjunction with other cost
containment programs -- will assist efforts to continue being a low-cost
provider of electricity.
The operating companies currently operate as vertically integrated companies
providing electricity to customers within the traditional service area of the
southeastern United States. Prices for electricity provided by the operating
companies to retail customers are set by state public service commissions under
cost-based regulatory principles.
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. In December 1998, Georgia Power received a new three-year
retail rate order. As a result of the rate order, Georgia Power recorded in 1998
a write down of $34 million -- $21 million after taxes -- related to its
investment in the Rocky Mountain pumped storage hydroelectric plant. This
long-standing issue is now resolved. See Note 3 to the financial statements for
additional information about these matters and other retail and wholesale
regulatory matters.
Future earnings for the operating companies in the near term will depend upon
growth in energy sales, which is subject to a number of factors. These factors
include weather, competition, changes in contracts with neighboring utilities,
energy conservation practiced by customers, the elasticity of demand, and the
rate of economic growth in the company's service area.
The electric utility industry in the United States is currently undergoing a
period of dramatic change as a result of regulatory and competitive factors.
Among the primary agents of change has been the Energy Policy Act of 1992
(Energy Act). The Energy Act allows independent power producers (IPPs) to access
a utility's transmission network in order to sell electricity to other
utilities. This enhances the incentive for IPPs to build cogeneration plants for
a utility's large industrial and commercial customers and sell energy generation
to other utilities. Also, electricity sales for resale rates are being driven
down by wholesale transmission access and numerous potential new energy
suppliers, including power marketers and brokers. Southern Company is
aggressively working to maintain and expand its share of wholesale sales in the
Southeastern power markets.
Although the Energy Act does not permit retail customer access, it was a
major catalyst for the current restructuring and consolidation taking place
within the utility industry. Numerous federal and state initiatives are in
varying stages to promote wholesale and retail competition. Among other things,
these initiatives allow customers to choose their electricity provider. As these
initiatives materialize, the structure of the utility industry could radically
change. Some states have approved initiatives that result in a separation of the
ownership and/or operation of generating facilities from the ownership and/or
operation of transmission and distribution facilities. While various
restructuring and competition initiatives have been or are being discussed in
Alabama, Florida, Georgia, and Mississippi, none have been enacted to date.
Enactment would require numerous issues to be resolved, including significant
ones relating to transmission pricing and recovery of any stranded investments.
The inability of an operating company to recover its investments, including the
regulatory assets described in Note 1 to the financial statements, could have a
material adverse effect on the financial condition of that operating company.
The operating companies are attempting to minimize or reduce their cost
exposure. See Note 3 to the financial statements for information regarding these
efforts.
II-11
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 1998 Annual Report
Continuing to be a low-cost producer could provide opportunities to increase
market share and profitability in markets that evolve with changing regulation.
Conversely, unless 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.
To adapt to a less regulated, more competitive environment, Southern Company
continues to evaluate and consider a wide array of potential business
strategies. These strategies may include business combinations, acquisitions
involving other utility or non-utility businesses or properties, internal
restructuring, disposition of certain assets, or some combination thereof.
Furthermore, Southern Company may engage in other new business ventures that
arise from competitive and regulatory changes in the utility industry. Pursuit
of any of the above strategies, or any combination thereof, may significantly
affect the business operations and financial condition of Southern Company.
The Energy Act amended the Public Utility Holding Company Act of 1935 (PUHCA)
to allow 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 existing and evolving opportunities,
Southern Energy -- founded in 1981 -- is focused on several key international
and domestic business lines, including energy distribution, integrated
utilities, stand-alone generation, and other energy-related products and
services. As the energy marketplace evolves, Southern Energy continues to
position the company to become a major competitor. At December 31, 1998,
Southern Energy's total assets amounted to $12 billion.
During 1998, Southern Energy further refined its business strategy to focus
on a few geographic regions of the world. In Asia, Southern Energy will focus
primarily on China, the Philippines, and India. In South America, the company
will pursue opportunities in Brazil. In Europe, Southern Energy will concentrate
efforts on the European Union countries. And in North America, the company will
target efforts in the Northeast, the Midwest, Texas, and California. Southern
Energy announced in 1998 plans to acquire, build, or gain access to some 20,000
megawatts of generating capacity in North America over the next several years in
order to be competitive in the country's evolving competitive energy supply
business. These assets will be closely linked with Southern Energy's energy
trading and marketing business. In January 1998, Southern Energy entered into a
joint venture with Vastar. The two companies combined their energy trading and
marketing operations to form a new full-service energy provider, Southern
Company Energy Marketing. The joint venture agreement gives Southern Company
Energy Marketing rights to market virtually all of Vastar's natural gas
production over the next 10 years.
In December 1998, Southern Energy completed its $537 million purchase of
1,267 megawatts of generating capacity from Commonwealth Electric. In addition,
Southern Energy plans to add 685 megawatts of capacity at the plants. In late
1998, Southern Energy announced the $801 million planned acquisition of 3,065
megawatts of generating capacity from Pacific Gas & Electric in northern
California. Additionally, the company announced plans to acquire from Orange and
Rockland Utilities Inc. and Consolidated Edison Inc. in New York 1,776 megawatts
of capacity for $480 million. These transactions are expected to close during
1999. Additionally, Southern Energy has announced plans to build or purchase an
additional 680 megawatts of capacity in Texas and Wisconsin. Through Southern
Company Energy Marketing, the company has also gained access to additional
capacity through marketing agreements. The company has access to almost
2,000 megawatts of capacity through marketing agreements with Sithe Energies in
New York and Brazos Electric Cooperative in Texas.
After refining its international focus and reviewing the financial
performance of existing assets, Southern Energy announced plans to sell its
holdings in EDELNOR in Chile and Alicura in Argentina. As a result, Southern
Energy recorded a write down of $200 million, after tax, in December 1998
related to these holdings. Because of regulatory and market conditions, these
assets did not meet earnings expectations.
Southern Company has filed with the Securities and Exchange Commission (SEC)
a request to invest up to nearly $8 billion in the non-traditional domestic and
international business. The current SEC authority is $3.9 billion, of which
$3.6 billion has been invested as of December 31, 1998.
Southern Company is involved in various matters being litigated. See Note 3
to the financial statements for information regarding material issues that could
possibly affect future earnings.
II-12
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 1998 Annual Report
Compliance costs related to current and future environmental laws and
regulations could affect earnings if such costs are not fully recovered. The
Clean Air Act and other important environmental items are discussed later under
"Environmental Matters."
The staff of the SEC has questioned certain of the current accounting
practices of the electric utility industry --including Southern Company's --
regarding the recognition, measurement, and classification in the financial
statements of decommissioning costs for nuclear generating facilities. In
response to these questions, the Financial Accounting Standards Board (FASB) has
decided to review the accounting for liabilities related to the retirement of
long-lived assets, including nuclear decommissioning. If the FASB issues new
accounting rules, the estimated costs of retiring Southern Company's nuclear and
other facilities may be required to be recorded as liabilities in the
Consolidated Balance Sheets. Also, the annual provisions for such costs could
change. Because of the company's current ability to recover asset retirement
costs through rates, these changes would not have a significant adverse effect
on results of operations. See Note 1 to the financial statements under
"Depreciation and Nuclear Decommissioning" for additional information.
The operating companies are subject to the provisions of FASB Statement No.
71, Accounting for the Effects of Certain Types of Regulation. In the event that
a portion of a company's operations is no longer subject to these provisions,
the company would be required to write off related regulatory assets and
liabilities that are not specifically recoverable, and determine if any other
assets have been impaired. See Note 1 to the financial statements under
"Regulatory Assets and Liabilities" for additional information.
New Accounting Standards
The FASB has issued Statement No. 133, Accounting for Derivative Instruments and
Hedging Activities, which must be adopted by the year 2000. This statement
establishes accounting and reporting standards for derivative instruments --
including certain derivative instruments embedded in other contracts -- and for
hedging activities. Southern Company has not yet quantified the impact of
adopting this statement on its financial statements; however, the adoption could
increase volatility in earnings and other comprehensive income.
In March 1998, the American Institute of Certified Public Accountants (AICPA)
issued a new Statement of Position, Accounting for the Costs of Computer
Software Developed or Obtained for Internal Use. This statement requires
capitalization of certain costs of internal-use software. Southern Company
adopted this statement in January 1999, and it is not expected to have a
material impact on the consolidated financial statements.
In April 1998, the AICPA issued a new Statement of Position, Reporting on the
Cost of Start-up Activities. This statement requires that the costs of start-up
activities and organizational costs be expensed as incurred. Any of these costs
previously capitalized by a company must be written off in the year of adoption.
Southern Company adopted this statement in January 1999, and it is not expected
to have a material impact on the consolidated financial statements.
In December 1998, the Emerging Issues Task Force (EITF) of the FASB issued
EITF No. 98-10, Accounting for Contracts Involved in Energy Trading and Risk
Management Activities. The EITF requires that energy trading contracts must be
marked to market through the income statement, with gains and losses reflected
rather than revenues and purchased power. Energy trading contracts are defined
as energy contracts entered into with the objective of generating profits on or
from exposure to shifts or changes in market prices. Southern Company adopted
the required accounting in January 1999, and it is not expected to have a
material impact on the consolidated financial statements.
Year 2000
Year 2000 Challenge
In order to save storage space, computer programmers in the 1960s and 1970s
shortened the year portion of date entries to just two digits. Computers
assumed, in effect, that all years began with "19." This practice was widely
adopted and hard-coded into computer chips and processors found in some
equipment. This approach, intended to save processing time and storage space,
was used until the mid-1990s. Unless corrected before the Year 2000, affected
software systems and devices containing a chip or microprocessor with date and
time functions could incorrectly process dates or the systems may cease to
function.
Southern Company depends on complex computer systems for many aspects of its
operations, which include generation, transmission, and distribution of
electricity, as well as other business support activities. Southern Company's
goal is to have critical devices or software that are required to maintain
operations to be Year 2000 ready by June 1999. Year 2000 ready means that a
system or application is determined suitable for continued use through the Year
II-13
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 1998 Annual Report
2000 and beyond. Critical systems include, but are not limited to, reactor
control systems, safe shutdown systems, turbine generator systems, control
center computer systems, customer service systems, energy management systems,
and telephone switches and equipment.
Year 2000 Program and Status
Southern Company's executive management recognizes the seriousness of the Year
2000 challenge and has dedicated what it believes to be adequate resources to
address the issue. The Millennium Project is a team of employees, IBM
consultants, and other contractors whose progress is reviewed on a monthly basis
by a steering committee of Southern Company executives.
Southern Company's traditional business refers to the integrated utility
services within Alabama, Florida, Georgia, and Mississippi. For this traditional
business, the work was divided into two phases. Phase I began in 1996 and
consisted of identifying and assessing corporate assets related to software
systems and devices that contain a computer chip or clock. The first phase was
completed in June 1997. Phase 2 consists of testing and remediating high
priority systems and devices. Also, contingency planning is included in this
phase. Completion of Phase 2 is targeted for June 1999. The Millennium Project
will continue to monitor the affected computer systems, devices, and
applications into the Year 2000.
For the traditional business, Southern Company has completed more than 70
percent of the activities contained in its work plan. The percentage of
completion and projected completion by function are as follows:
Work Plan
- - - - - - - ----------------------------------------------------------------------
Remediation Project
Inventory Assessment Testing Completion
- - - - - - - ----------------------------------------------------------------------
Generation 100% 100% 70% 6/99
Energy
Management 100 100 90 6/99
Transmission and
Distribution 100 100 100 1/99
Telecommunications 100 100 50 6/99
Corporate
Applications 100 100 90 3/99
- - - - - - - ----------------------------------------------------------------------
For the non-traditional business located in the United States and several
countries throughout the world, Year 2000 readiness is generally scheduled to
follow the traditional business. In a number of the business units outside the
United States, Southern Company is neither the majority owner nor the managing
concern. In these circumstances, Southern Company is providing technical
assistance but does not control the schedule or progress.
Year 2000 Costs
For the traditional business, current projected total costs for Year 2000
readiness are approximately $91 million, which includes $6 million of cost
billed to non-affiliated companies. These costs include labor necessary to
identify, test, and renovate affected devices and systems. From its inception
through December 31, 1998, the Year 2000 program costs, recognized primarily as
expense, amounted to $56 million based on Southern Company's ownership interest.
In addition to the traditional business costs, current projections for Year 2000
program costs are approximately $24 million for the non-traditional business --
based on Southern Company's ownership interest -- of which $9 million has been
spent through December 31, 1998
Year 2000 Risks
Southern Company is implementing a detailed process to minimize the possibility
of service interruptions related to the Year 2000. The company believes, based
on current tests, that the system can provide customers with electricity. These
tests increase confidence, but do not guarantee error-free operations. The
company is taking what it believes to be prudent steps to prepare for the Year
2000, and it expects any interruptions in service that may occur within the
traditional business service territory to be isolated and short in duration.
Southern Company expects the risks associated with Year 2000 to be no more
severe than the scenarios that its electric system is routinely prepared to
handle. The most likely worst case scenario consists of the service loss of one
of the largest generating units and/or the service loss of any single bulk
transmission element in its traditional business service territory. The company
has followed a proven methodology for identifying and assessing software and
devices containing potential Year 2000 challenges. Remediation and testing of
those devices are in progress. Following risk assessment, Southern Company is
preparing contingency plans as appropriate and is participating in North
American Electric Reliability Council-coordinated national drills during 1999.
Southern Company is currently reviewing the Year 2000 readiness of material
third parties that provide goods and services crucial to Southern Company's
operations. Among such critical third parties are fuel, transportation,
telecommunications, water, chemical, and other suppliers. Contingency plans
based on the assessment of each third party's ability to continue supplying
critical goods and services to Southern Company are being developed.
II-14
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 1998 Annual Report
There is a potential for some earnings erosion caused by reduced electrical
demand by customers because of their own Year 2000 issues. The risk associated
with the progress of some operations outside the United States is a function of
the local regulatory environment and the priorities of the entities with
management control. Year 2000 issues are included in the list of due diligence
activities associated with acquisitions; there is some risk associated with the
subsequent validation of any given seller's representations.
Year 2000 Contingency Plans
Because of experience with hurricanes and other storms, the traditional business
is skilled at developing and using contingency plans in unusual circumstances.
As part of Year 2000 business continuity and contingency planning, Southern
Company is drawing on that experience to make risk assessments and is developing
additional plans to deal specifically with situations that could arise relative
to Year 2000 challenges. Southern Company is identifying critical operational
locations, and key employees will be on duty at those locations during the Year
2000 transition. In September 1999, drills are scheduled to be conducted to test
contingency plans. Because of the level of detail of the contingency planning
process, management feels that the contingency plans will keep any service
interruptions that may occur within the traditional business service territory
isolated and short in duration.
Contingency planning efforts for the non-traditional business are generally
in the initial phase.
FINANCIAL CONDITION
Overview
Southern Company's financial condition continues to remain strong. The company's
common stock closed 1998 with the highest year-end closing price in history.
Consolidated net income of $1.2 billion -- excluding non-recurring charges -- in
1998 increased $95 million compared with the prior year. In January 1999,
Southern Company modified its dividend policy to lower, over time, the
previously targeted payout ratio of approximately 75 percent. The quarterly
dividend declared was maintained at 33 1/2 cents per share or $1.34 annually.
This action allows more internally generated funds to be reinvested in the
company, which is expected to increase long-term shareholder value.
Gross property additions to utility plant were $2.0 billion in 1998. The
majority of funds needed for gross property additions since 1995 has been
provided from operating activities. Southern Energy acquired $670 million of
generating assets in 1998 and sold an additional 26 percent interest in its
United Kingdom subsidiary for $170 million. The Consolidated Statements of Cash
Flows provide additional details.
Derivative Financial Instruments
Southern Company is exposed to market risks, including changes in interest
rates, currency exchange rates, and certain commodity prices. To manage the
volatility attributable to these exposures, the company nets the exposures to
take advantage of natural offsets and enters into various derivative
transactions for the remaining exposures pursuant to the company's policies in
areas such as counterparty exposure and hedging practices. Generally, company
policy is that derivatives are to be used only for hedging purposes. Derivative
positions are monitored using techniques that include market value and
sensitivity analysis.
The company's market risk exposures relative to interest rate changes and
currency exchange fluctuations, as discussed later, have not changed materially
versus the previous reporting period. In addition, the company is not aware of
any facts or circumstances that would significantly impact such exposures in the
near-term.
Interest rate swaps are used to hedge underlying debt obligations. These
swaps hedge specific debt issuances and qualify for hedge accounting. The
interest rate differential is reflected as an adjustment to interest expense
over the life of the instruments. Additionally, the company has interest rate
swaps in foreign currencies. These swaps are designated as hedges of the
company's related debt issuance in the same currency.
If the company sustained a 100 basis point change in interest rates for all
variable rate debt in all currencies, the change would affect annualized
interest expense by approximately $35 million at December 31, 1998. Based on the
company's overall interest rate exposure at December 31, 1998, including
derivative and other interest rate sensitive instruments, a near-term 100 basis
point change in interest rates would not materially affect the consolidated
financial statements.
The company has investments in the United Kingdom and Germany. For these
investments, the company uses long-term cross-currency agreements to reduce a
substantial portion of its exposure to fluctuations in the British pound
sterling and German Deutschemark. These instruments are used to hedge the net
investments in these countries. As a result of these swaps, a 10 percent
11-15
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 1998 Annual Report
sustained decline of the British pound sterling and German Deutschemark versus
the U.S. dollar would not materially affect the consolidated financial
statements.
The company also has investments in various emerging market countries where
the net investments are not hedged, including Argentina, Brazil, Chile,
Trinidad, Bahamas, Philippines, and China. The company relies on either currency
pegs or contractual or regulatory links to the U.S. dollar to mitigate currency
risk attributable to these investments. The company does not believe it has a
material exposure to changes in exchange rates between the U.S. dollar and the
currencies of these countries.
Based on availability and economics, the company also uses currency swaps and
forward agreements to hedge dollar-denominated debt issued by subsidiaries
with a functional currency other than the U.S. dollar. These swaps offset the
dollar cash flows, thereby effectively converting debt to the respective
company's reporting currency. Gains and losses related to qualified hedges of
foreign currency firm commitments are deferred and included in the basis of the
underlying transactions. To the extent that a qualifying hedge is terminated or
ceases to be effective as a hedge, any deferred gains and losses to that point
continue to be deferred and are included in the basis of the underlying
transaction.
In addition to the non-trading activities, the company is exposed to market
risks through its electricity and natural gas commodity trading business, which
is primarily conducted through the company's joint venture relationship with
Vastar. While this joint venture relationship is accounted for under the equity
method of accounting, Southern Company -- through guarantees it has made jointly
with Vastar -- is exposed to market risk. Southern Company and Vastar have
agreed to indemnify each other against losses under such guarantees in
proportion to their respective ownership shares of the joint venture. At
December 31, 1998, outstanding guarantees related to the estimated fair value
of net contractual commitments were approximately $152 million. Based upon the
joint venture's statistical analysis of its credit risk, Southern Company's
potential exposure under these contractual commitments would not materially
differ from the estimated fair value. The joint venture's gross revenues and
cost of sales for 1998 were $9.2 billion and $9.1 billion, respectively.
To estimate and manage the market risk of its trading and marketing
portfolio, the joint venture employs a daily Value at Risk (VAR) methodology.
VAR is used to describe a probabilistic approach to measuring the exposure to
market risk. VAR models are relatively sophisticated. However, the quantitative
risk information is limited by the parameters established in creating the model.
The instruments being evaluated may have features that may trigger a potential
loss in excess of calculated amounts if the changes in commodity prices exceed
the confidence level of the model used. The calculation utilizes the standard
deviation of seasonally adjusted historical changes in the value of the market
risk sensitive commodity-based financial instruments to estimate the amount of
change (i.e., volatility) in the current value of these instruments that could
occur at a specified confidence level over a specified holding interval. The
parameters used in the calculation include holding intervals ranging from five
to 20 days, depending upon the type of instrument, the term of the instrument,
the liquidity of the underlying market, and other factors. The models employ a
95 percent confidence level based on historical price movement. Based on the
joint venture's VAR analysis of its overall commodity price risk exposure at
December 31, 1998, management does not anticipate a materially adverse effect on
the company's consolidated financial statements as a result of market
fluctuations.
In the United Kingdom, the company utilizes contracts to mitigate its
exposure to volatility in the prices of electricity purchased through the
wholesale electricity market. These contracts allow the company to effectively
convert the majority of its anticipated wholesale electricity purchases from
market prices to fixed prices. The gains and losses on these contracts are
deferred and recognized as electricity is purchased. Recently, a market has
developed for trading these contracts in the United Kingdom. However, due to the
immaturity of this market and the complexity of the company's existing
contracts, it is not practicable to estimate the fair value of these contracts.
Due to cost-based rate regulations, the operating companies have limited
exposure to market volatility in interest rates, commodity fuel prices, and
prices of electricity. To mitigate residual risks relative to movements in
electricity prices, the operating companies enter into fixed price contracts for
the purchase and sale of electricity through the wholesale electricity market.
Realized gains and losses are recognized in the income statement as incurred. At
December 31, 1998, exposure from these activities was not material to the
consolidated financial statements.
For additional information, see Note 1 to the financial statements under
"Financial Instruments for Non-Trading and Trading Activities."
II-16
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 1998 Annual Report
Capital Structure
Southern Company achieved a ratio of common equity to total capitalization --
including short-term debt -- of 37.4 percent in 1998, compared with 38.6 percent
in 1997, and 45.1 percent in 1996.
During 1998, the subsidiary companies sold, through public authorities, $210
million of pollution control revenue bonds. In addition, preferred stock of
$200 million and capital and preferred securities of $435 million were issued in
1998. The companies continued to reduce financing costs by retiring higher-cost
bonds and preferred stock. Retirements, including maturities, of bonds totaled
$1.7 billion during 1998, $507 million during 1997, and $600 million during
1996. As a result, the composite interest rate on long-term debt decreased from
7.1 percent at December 31, 1995 to 6.42 percent at December 31, 1998.
Retirements of preferred stock totaled $239 million during 1998, $660 million
during 1997, and $179 million during 1996.
In 1998, Southern Company raised net proceeds of $109 million from the
issuance of common stock under the company's various stock plans. At the close
of 1998, the company's common stock had a market value of 29 1/16 per share,
compared with a book value of $14.04 per share. The market-to-book value ratio
was 207 percent at the end of 1998, compared with 186 percent at year-end 1997,
and 166 percent at year-end 1996.
Capital Requirements for Construction
The construction program of Southern Company is budgeted at $2.6 billion for
1999, $2.1 billion for 2000, and $2.1 billion for 2001. Actual construction
costs may vary from this estimate because of changes in such factors as:
business conditions; environmental regulations; nuclear plant regulations; load
projections; the cost and efficiency of construction labor, equipment, and
materials; and the cost of capital. In addition, there can be no assurance that
costs related to capital expenditures will be fully recovered.
The operating companies have approximately 2,700 megawatts of combined cycle
generation scheduled to be placed in service by 2001. Southern Energy has under
construction some 1,300 megawatts of owned capacity. Significant construction of
transmission and distribution facilities and upgrading of generating plants will
be continuing for the core business in the Southeast.
Other Capital Requirements
In addition to the funds needed for the construction program, approximately $2.6
billion will be required by the end of 2001 for present improvement fund
requirements and maturities of long-term debt. Also, the subsidiaries will
continue to retire higher-cost debt and preferred stock and replace these
obligations with lower-cost capital if market conditions permit.
In late 1998, Southern Energy announced plans to acquire $801 million and
$480 million of generating assets in California and New York, respectively.
These transactions are expected to close in 1999.
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 -- significantly
affected Southern Company. Specific reductions in sulfur dioxide and nitrogen
oxide emissions from fossil-fired generating plants are required in two phases.
Phase I compliance began in 1995 and initially affected 28 generating units of
Southern Company. As a result of the company's compliance strategy, an
additional 22 generating units were brought into compliance with Phase I
requirements. Phase II compliance is required in 2000, and all fossil-fired
generating plants will be affected.
Southern Company achieved Phase I sulfur dioxide compliance at the affected
plants by switching to low-sulfur coal, which required some equipment upgrades.
Construction expenditures for Phase I compliance totaled approximately $300
million.
For Phase II sulfur dioxide compliance, Southern Company could use emission
allowances, increase fuel switching, and/or install flue gas desulfurization
equipment at selected plants. Also, equipment to control nitrogen oxide
emissions will be installed on additional system fossil-fired units as necessary
to meet Phase II limits and ozone non-attainment requirements for metropolitan
Atlanta through 2000. Current compliance strategy for Phase II and ozone
non-attainment could require total estimated construction expenditures of
approximately $70 million, of which $16 million remains to be spent.
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.
11-17
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 1998 Annual Report
In July 1997, the Environmental Protection Agency (EPA) revised the national
ambient air quality standards for ozone and particulate matter. This revision
makes the standards significantly more stringent. In September 1998, the EPA
issued the final regional nitrogen oxide rules to the states for implementation.
The states have one year to adopt and implement the new rules. The final rules
affect 22 states including Alabama and Georgia. The EPA rules are being
challenged in the courts by several states and industry groups. Implementation
of the final state rules could require substantial further reductions in
nitrogen oxide emissions from fossil-fired generating facilities and other
industry in these states. Implementation of the standards could result in
significant additional compliance costs and capital expenditures that cannot be
determined until the results of legal challenges are known and the states have
adopted their final rules.
The EPA and state environmental regulatory agencies are reviewing and
evaluating various other matters including: nitrogen oxide emission control
strategies for ozone non-attainment areas; additional controls for hazardous air
pollutant emissions; control strategies to reduce regional haze; and hazardous
waste disposal requirements. The impact of new standards will depend on the
development and implementation of applicable regulations.
Southern Company must comply with other environmental laws and regulations
that cover the handling and disposal of hazardous waste. Under these various
laws and regulations, the subsidiaries could incur substantial costs to clean up
properties. The subsidiaries conduct studies to determine the extent of any
required cleanup costs and have recognized in their respective financial
statements costs to clean up known sites. These costs for Southern Company
amounted to $6 million in 1998 and $4 million in 1997. In 1996, the company was
reimbursed $6 million for amounts previously expensed. 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 Air Act; the
Clean Water Act; the Comprehensive Environmental Response, Compensation, and
Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances
Control Act; and the Endangered Species Act. Changes to these laws could affect
many areas of Southern Company's operations. The full impact of any such changes
cannot be determined at this time.
Compliance with possible additional legislation related to global climate
change, electromagnetic fields, and other environmental and health concerns
could significantly affect Southern Company. The impact of new legislation -- if
any -- will depend on the subsequent development and implementation of
applicable regulations. In addition, the potential exists for liability as the
result of lawsuits alleging damages caused by electromagnetic fields.
Sources of Capital
The amount and timing of additional equity capital to be raised in 1999 -- as
well as in subsequent years -- will be contingent on 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 1999 for the company's stock plans that is
not provided from the issuance of new stock will be acquired on the open market
in accordance with the terms of such plans.
The operating companies plan to obtain the funds required for construction
and other purposes from sources similar to those used in the past, which were
primarily from internal sources. However, the type and timing of any financings
- - - - - - - -- if needed -- will depend on market conditions and regulatory approval.
The operating companies historically have relied on issuances of first
mortgage bonds and preferred stock, in addition to pollution control revenue
bonds issued for their benefit by public authorities, to meet their long-term
external financing requirements. Recently, the operating companies' financings
have consisted of unsecured debt and trust preferred securities. In this regard,
the operating companies sought and obtained stockholder approval in 1997 or 1998
to amend their respective corporate charters eliminating restrictions on the
amounts of unsecured indebtedness they may incur.
To meet short-term cash needs and contingencies, Southern Company had
approximately $872 million of cash and cash equivalents and $4.6 billion of
unused credit arrangements with banks at the beginning of 1999.
Cautionary Statement Regarding Forward-Looking
Information
Southern Company's 1998 Annual Report contains forward-looking and historical
information. The company cautions that there are various important factors that
could cause actual results to differ materially from those indicated in the
forward-looking information; accordingly, there can be no assurance that such
II-18
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 1998 Annual Report
indicated results will be realized. These factors include legislative and
regulatory initiatives regarding deregulation and restructuring of the electric
utility industry; the extent and timing of the entry of additional competition
in the markets of the subsidiary companies; potential business strategies
- - - - - - - --including acquisitions or dispositions of assets or internal restructuring --
that may be pursued by the company; state and federal rate regulation in the
United States; Year 2000 issues; changes in or application of environmental and
other laws and regulations to which the company and its subsidiaries are
subject; political, legal and economic conditions and developments in the United
States and in foreign countries in which the subsidiaries operate; financial
market conditions and the results of financing efforts; changes in commodity
prices and interest rates; weather and other natural phenomena; the performance
of projects undertaken by the non-traditional business and the success of
efforts to invest in and develop new opportunities; and other factors discussed
in the reports -- including Form 10-K -- filed from time to time by the company
with the SEC.
II-19
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 1998, 1997, and 1996
Southern Company and Subsidiary Companies 1998 Annual Report
1998 1997 1996
============================================================================================================================
(in millions)
Operating Revenues $11,403 $12,611 $10,358
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
Fuel 2,371 2,281 2,245
Purchased power 1,243 3,033 1,103
Other 2,112 1,930 1,860
Maintenance 887 763 782
Depreciation and amortization 1,539 1,367 1,133
Taxes other than income taxes 599 572 634
Income taxes 678 725 747
Write down of South American assets (Note 5) 308 - -
Write down of Rocky Mountain plant (Note 3) 34 - -
Income tax benefit for write down of assets (121) - -
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Total operating expenses 9,650 10,671 8,504
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Operating Income 1,753 1,940 1,854
Other Income:
Interest income 243 152 54
Equity in earnings of unconsolidated subsidiaries 123 35 6
Other, net 57 24 40
Income tax benefits (expenses) applicable to other income 8 34 (10)
Windfall profits tax assessed in United Kingdom (Note 8) - (148) -
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Income Before Interest Charges 2,184 2,037 1,944
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Interest Charges and Other:
Interest on long-term debt 712 678 530
Interest on notes payable 108 112 107
Amortization of debt discount, premium, and expense, net 65 34 33
Other interest charges 68 49 27
Minority interests in subsidiaries 80 29 13
Distributions on capital and preferred securities of subsidiary companies 149 120 22
Preferred dividends of subsidiary companies 25 43 85
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Interest charges and other, net 1,207 1,065 817
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Consolidated Net Income $ 977 $ 972 $ 1,127
=============================================================================================================================
Common Stock Data: (Note 9)
Average number of shares of common stock outstanding (in millions) 697 685 673
Basic and diluted earnings per share of common stock $1.40 $1.42 $1.68
Cash dividends paid per share of common stock $1.34 $1.30 $1.26
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
II-20
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1998, 1997, and 1996
Southern Company and Subsidiary Companies 1998 Annual Report
1998 1997 1996
=============================================================================================================================
(in millions)
Operating Activities:
Consolidated net income $ 977 $ 972 $ 1,127
Adjustments to reconcile consolidated net income
to net cash provided from operating activities --
Depreciation and amortization 1,773 1,592 1,338
Deferred income taxes and investment tax credits (22) (5) 57
Gain on asset sales (61) (25) (59)
Write down of South American assets 308 - -
Write down of Rocky Mountain plant 34 - -
Other, net (199) (64) 50
Changes in certain current assets and liabilities
excluding effects from acquisitions --
Receivables, net 151 (229) (25)
Fossil fuel stock (35) 53 57
Materials and supplies (10) 21 47
Accounts payable (17) 138 19
Other (151) 172 (210)
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities 2,748 2,625 2,401
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (2,005) (1,859) (1,229)
Southern Energy business acquisitions, net of cash acquired (998) (2,925) -
Sales of property 281 32 211
Other 86 (13) (275)
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities (2,636) (4,765) (1,293)
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Financing Activities:
Proceeds --
Common stock 234 360 171
Preferred stock 200 - -
Capital and preferred securities 435 1,321 322
First mortgage bonds - - 85
Other long-term debt 2,973 2,499 1,570
Redemptions --
Common stock repurchased (125) - -
Preferred stock (239) (660) (179)
First mortgage bonds (1,487) (168) (426)
Other long-term debt (599) (802) (1,754)
Increase (decrease) in notes payable, net (353) 509 (268)
Payment of common stock dividends (933) (889) (846)
Miscellaneous 53 126 (110)
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Net cash provided from (used for) financing activities 159 2,296 (1,435)
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents 271 156 (327)
Cash and Cash Equivalents at Beginning of Year 601 445 772
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 872 $ 601 $ 445
=============================================================================================================================
Supplemental Cash Flow Information:
Cash paid during the year for --
Interest (net of amount capitalized) $998 $876 $677
Income taxes $839 $823 $706
Southern Energy business acquisitions --
Fair value of assets acquired $1,072 $4,768 $-
Less cash paid for common stock 998 2,925 -
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Liabilities assumed $ 74 $1,843 $-
=============================================================================================================================
The accompanying notes are an integral part of these statements.
11-21
CONSOLIDATED BALANCE SHEETS
At December 31, 1998 and 1997
Southern Company and Subsidiary Companies 1998 Annual Report
==============================================================================================================================
Assets 1998 1997
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------
(in millions)
Utility Plant:
Plant in service (Note 1) $35,364 $34,044
Less accumulated provision for depreciation 13,239 11,934
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
22,125 22,110
Nuclear fuel, at amortized cost 217 230
Construction work in progress (Note 4) 1,782 1,312
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Total 24,124 23,652
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Other Property and Investments:
Goodwill, net of accumulated amortization of
$106 million in 1998 and $55 million in 1997 (Note 13) 2,067 1,888
Property rights, net of accumulated amortization of
$169 million in 1998 and $108 million in 1997 1,185 1,389
Equity investments in unconsolidated subsidiaries 1,560 1,168
Nuclear decommissioning trusts 516 387
Miscellaneous 644 742
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Total 5,972 5,574
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Current Assets:
Cash and cash equivalents 872 601
Special deposits 87 103
Receivables, less accumulated provisions for uncollectible accounts
of $113 million in 1998 and $77 million in 1997 1,797 2,007
Fossil fuel stock, at average cost 252 218
Materials and supplies, at average cost 515 493
Prepayments 102 98
Vacation pay deferred 81 79
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Total 3,706 3,599
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets:
Deferred charges related to income taxes (Note 8) 1,036 1,142
Prepaid pension costs 491 383
Debt expense, being amortized 129 101
Premium on reacquired debt, being amortized 294 285
Miscellaneous 440 519
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Total 2,390 2,430
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Total Assets $36,192 $35,255
=============================================================================================================================
The accompanying notes are an integral part of these balance sheets.
11-22
CONSOLIDATED BALANCE SHEETS (continued)
At December 31, 1998 and 1997
Southern Company and Subsidiary Companies 1998 Annual Report
=============================================================================================================================
Capitalization and Liabilities 1998 1997
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
(in millions)
Capitalization (See accompanying statements):
Common stock equity $ 9,797 $ 9,647
Preferred stock of subsidiaries 369 493
Company or subsidiary obligated mandatorily redeemable
capital and preferred securities 2,179 1,744
Long-term debt 10,472 10,274
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Total 22,817 22,158
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Current Liabilities:
Amount of securities due within one year 1,526 784
Notes payable 1,828 2,064
Accounts payable 1,027 1,049
Customer deposits 125 133
Taxes accrued --
Federal and state income 50 120
Other 299 259
Interest accrued 233 262
Vacation pay accrued 112 108
Miscellaneous 542 608
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Total 5,742 5,387
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes (Note 8) 4,481 4,650
Deferred credits related to income taxes (Note 8) 715 746
Accumulated deferred investment tax credits 723 754
Employee benefits provisions 474 431
Minority interests in subsidiaries 535 435
Prepaid capacity revenues 96 110
Department of Energy assessments 64 72
Disallowed Plant Vogtle capacity buyback costs 54 56
Storm damage reserves 24 38
Miscellaneous 467 418
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Total 7,633 7,710
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Commitments and Contingent Matters (Notes 1, 2, 3, 4, 5, 7, 12, and 13)
Total Capitalization and Liabilities $36,192 $35,255
=============================================================================================================================
The accompanying notes are an integral part of these balance sheets.
11-23
CONSOLIDATED STATEMENTS OF CAPITALIZATION
At December 31, 1998 and 1997
Southern Company and Subsidiary Companies 1998 Annual Report
=================================================================================================================================
1998 1997 1998 1997
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------------
(in millions) (percent of total)
Common Stock Equity:
Common stock, par value $5 per share --
Authorized -- 1 billion shares
Issued -- 1998: 700 million shares
-- 1997: 693 million shares
Par value $ 3,499 $ 3,467
Paid-in capital 2,463 2,331
Treasury, at cost (Note 9) (58) -
Retained earnings (Note 9) 3,878 3,842
Accumulated other comprehensive income 15 7
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------------
Total common stock equity 9,797 9,647 42.9% 43.5%
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------------
Cumulative Preferred Stock of Subsidiaries:
$100 par or stated value --
4.20% to 7.00% 135 136
$25 par or stated value --
5.20% to 6.80% 200 131
Adjustable and auction rates -- at 1/1/99:
4.00% to 4.30% 120 226
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------------
Total (annual dividend requirement -- $23 million) 455 493
Less amount due within one year 86 -
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------------
Total excluding amount due within one year 369 493 1.6 2.2
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------------
Company or Subsidiary Obligated Mandatorily
Redeemable Capital and Preferred Securities (Note 10):
$25 liquidation value --
6.85% to 7.00% 235 -
7.13% to 7.38% 297 97
7.60% to 7.63% 415 415
7.75% 649 649
8.14% to 9.00% 583 583
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------------
Total (annual distribution requirement -- $168 million) 2,179 1,744 9.6 7.9
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------------
Long-Term Debt of Subsidiaries:
First mortgage bonds --
Maturity Interest Rates
-------- --------------
1998 5.00% to 8.67% - 238
1999 6.13% to 8.67% 373 373
2000 6.00% to 8.67% 209 349
2001 8.67% 9 9
2002 6.85% to 8.67% 10 260
2003 6.13% to 8.67% 635 635
2004 through 2008 6.07% to 8.67% 197 372
2009 through 2013 8.67% 75 75
2014 through 2018 8.67% 56 56
2019 through 2023 7.30% to 8.75% 614 1,298
2024 through 2028 6.88% to 9.00% 287 287
11-24
CONSOLIDATED STATEMENTS OF CAPITALIZATION (continued)
At December 31, 1998 and 1997
Southern Company and Subsidiary Companies 1998 Annual Report
===========================================================================================================================
1998 1997 1998 1997
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
(in millions) (percent of total)
Other long-term debt --
Pollution control revenue bonds --
Collateralized:
4.38% to 6.75% due 2000-2026 954 1,154
Variable rates (3.10% to 5.25% at 1/1/99)
due 2011-2025 639 639
Non-collateralized:
6.75% to 7.25% due 2003-2020 110 110
5.80% due 2022 - 10
Variable rates (3.15% to 5.33% at 1/1/99)
due 2021-2037 880 670
Long-term notes payable --
5.21% to 11.00% due 1998-2002 - 481
6.13% to 11.00% due 1999-2002 437 -
5.35% to 10.00% due 2003-2004 361 47
5.49% to 10.50% due 2005 551 73
6.80% to 8.14% due 2006 582 578
7.16% to 10.25% due 2007 447 475
3.66% to 10.56% due 2008-2015 959 362
6.38% to 8.12% due 2018-2038 803 20
6.88% to 7.13% due 2047-2048 729 194
Adjustable rates (5.23% to 7.10% at 1/1/99)
due 1998-2001 397 710
Adjustable rates (6.58% at 1/1/99)
due 2002 793 847
Adjustable rates (3.96% at 1/1/99)
due 2004 516 478
Adjustable rates (6.93% to 7.57% at 1/1/99)
due 2005-2007 252 201
Capitalized lease obligations 135 142
Unamortized debt premium (discount), net (98) (85)
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
requirement -- $771 million) 11,912 11,058
Less amount due within one year (Note 11) 1,440 784
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Long-term debt excluding amount due within one year 10,472 10,274 45.9 46.4
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Total Capitalization $22,817 $22,158 100.0% 100.0%
===========================================================================================================================
The accompanying notes are an integral part of these statements.
11-25
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 1998, 1997, and 1996
Southern Company and Subsidiary Companies 1998 Annual Report
=================================================================================================================================
1998 1997 1996
- - - - - - - ----------------------------------------------------------------------------------------------------------------------------------
(in millions)
Consolidated Net Income $977 $972 $1,127
Other comprehensive income:
Foreign currency translation adjustments 12 (10) 31
Gain on investments realized in net income - - (42)
Less applicable income taxes (benefits) 4 (3) (4)
- - - - - - - ----------------------------------------------------------------------------------------------------------------------------------
Consolidated Comprehensive Income $985 $965 $1,120
==================================================================================================================================
CONSOLIDATED STATEMENTS OF PAID-IN CAPITAL
For the Years Ended December 31, 1998, 1997, and 1996
=================================================================================================================================
1998 1997 1996
- - - - - - - ----------------------------------------------------------------------------------------------------------------------------------
(in millions)
Balance at Beginning of Year $2,331 $2,053 $1,920
Proceeds from sales of common stock over the par value -- 6.3 million,
16.4 million, and 7.5 million shares in 1998, 1997, and 1996, respectively 132 278 133
- - - - - - - ----------------------------------------------------------------------------------------------------------------------------------
Balance at End of Year $2,463 $2,331 $2,053
==================================================================================================================================
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
For the Years Ended December 31, 1998, 1997, and 1996
==================================================================================================================================
1998 1997 1996
- - - - - - - ----------------------------------------------------------------------------------------------------------------------------------
(in millions)
Balance at Beginning of Year $3,842 $3,764 $3,483
Consolidated net income 977 972 1,127
- - - - - - - ----------------------------------------------------------------------------------------------------------------------------------
4,819 4,736 4,610
Cash dividends on common stock 933 889 846
Capital and preferred stock transactions, net 8 5 -
- - - - - - - ----------------------------------------------------------------------------------------------------------------------------------
Balance at End of Year (Note 9) $3,878 $3,842 $3,764
==================================================================================================================================
CONSOLIDATED STATEMENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME
For the Years Ended December 31, 1998, 1997, and 1996
===================================================================================================================================
1998 1997 1996
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------------
(in millions)
Balance at Beginning of Year $ 7 $14 $21
Change during the year 8 (7) (7)
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------------
Balance at End of Year $15 $ 7 $14
====================================================================================================================================
The accompanying notes are an integral part of these statements.
11-26
NOTES TO FINANCIAL STATEMENTS
Southern Company and Subsidiary Companies 1998 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING
POLICIES
General
Southern Company is the parent company of five operating companies, a system
service company, Southern Communications Services (Southern LINC), Southern
Company Energy Solutions, Southern Energy, Inc. (Southern Energy), Southern
Nuclear Operating Company (Southern Nuclear), and other direct and indirect
subsidiaries. The operating companies -- Alabama Power, Georgia Power, Gulf
Power, Mississippi Power, and Savannah Electric -- provide electric service in
four southeastern states. Contracts among the operating 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) and/or the Securities and Exchange Commission
(SEC). The system service company provides, at cost, specialized services to
Southern Company and subsidiary companies. Southern LINC provides digital
wireless communications services to the operating companies and also markets
these services to the public within the Southeast. Southern Company Energy
Solutions develops new business opportunities related to energy products and
services. Worldwide, Southern Energy develops and manages electricity and other
energy related projects, including domestic energy trading and marketing.
Southern Nuclear provides services to Southern Company's nuclear power plants.
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 public service
commissions. The companies follow generally accepted accounting principles and
comply with the accounting policies and practices prescribed by their respective
commissions. The preparation of financial statements in conformity with
generally accepted accounting principles requires the use of estimates, and the
actual results may differ from those estimates. All material intercompany items
have been eliminated in consolidation.
The consolidated financial statements reflect investments in controlled
subsidiaries on a consolidated basis and other investments on an equity basis.
Certain prior years' data presented in the consolidated financial statements
have been reclassified to conform with the current year presentation.
Regulatory Assets and Liabilities
The operating companies are subject to the provisions of Financial Accounting
Standards Board (FASB) Statement No. 71, Accounting for the Effects of Certain
Types of Regulation. Regulatory assets represent probable future revenues to the
operating companies associated with certain costs that are expected to be
recovered from customers through the ratemaking process. Regulatory liabilities
represent probable future reductions in revenues associated with amounts that
are expected to be credited to customers through the ratemaking process.
Regulatory assets and (liabilities) reflected in the Consolidated Balance Sheets
at December 31 relate to the following:
1998 1997
- - - - - - - ---------------------------------------------------------------
(in millions)
Deferred income taxes $1,036 $1,142
Deferred Plant Vogtle costs - 50
Premium on reacquired debt 294 285
Demand-side programs - 11
Department of Energy assessments 57 63
Vacation pay 81 79
Deferred fuel charges - 4
Postretirement benefits 36 38
Work force reduction costs 17 37
Deferred income tax credits (715) (746)
Storm damage reserves (24) (36)
Other, net 145 152
- - - - - - - ---------------------------------------------------------------
Total $ 927 $1,079
===============================================================
In the event that a portion of an operating company's operations is no longer
subject to the provisions of FASB Statement No. 71, the company would be
required to write off related net regulatory assets and liabilities that are not
specifically recoverable through regulated rates. In addition, the company would
be required to determine if any impairment to other assets exists, including
plant, and write down the assets, if impaired, to their fair value.
Revenues and Fuel Costs
The operating companies accrue revenues for service rendered but unbilled at the
end of each fiscal period. Fuel costs are expensed as the fuel is used. The
operating companies' electric rates include provisions to adjust billings for
fluctuations in fuel costs, the energy component of purchased power costs, and
11-27
NOTES (continued)
Southern Company and Subsidiary Companies 1998 Annual Report
certain other costs. Revenues are adjusted for differences between recoverable
fuel costs and amounts actually recovered in current rates.
Southern Company has a diversified base of customers. No single customer or
industry comprises 10 percent or more of revenues. For all periods presented,
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 $133
million in 1998, $144 million in 1997, and $142 million in 1996. Alabama Power
and Georgia Power have contracts with the U.S. Department of Energy (DOE) that
provide for the permanent disposal of spent nuclear fuel. Although disposal was
scheduled to begin in 1998, the actual year this service will begin is
uncertain. The DOE failed to begin disposing of spent fuel in January 1998, as
required by the contracts, and the companies are pursuing legal remedies against
the government for breach of contract. Sufficient storage capacity currently is
available to permit operation into 2003 at Plant Hatch, into 2017 at Plant
Vogtle, and into 2009 and 2013 at Plant Farley units 1 and 2, respectively.
Plant Vogtle's spent fuel storage capacity includes the installation in 1998 of
additional rack capacity. Activities for adding dry cask storage capacity at
Plant Hatch by as early as 1999 are in progress.
Also, the Energy Policy Act of 1992 required the establishment in 1993 of a
Uranium Enrichment Decontamination and Decommissioning Fund, which is funded in
part by a special assessment on utilities with nuclear plants. This assessment
is being paid over a 15-year period, which began in 1993. This fund will be used
by the DOE for the decontamination and decommissioning of its nuclear fuel
enrichment facilities. The law provides that utilities will recover these
payments in the same manner as any other fuel expense. Alabama Power and Georgia
Power -- based on its ownership interests -- estimate their respective remaining
liability at December 31, 1998, under this law to be approximately $31 million
and $24 million. 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
3.4 percent in 1998, 3.4 percent in 1997, and 3.3 percent in 1996. When property
subject to depreciation is retired or otherwise disposed of in the normal course
of business, its cost -- together with the cost of removal, less salvage -- is
charged to the accumulated provision for depreciation. Minor items of property
included in the original cost of the plant are retired when the related property
unit is retired. Depreciation expense includes an amount for the expected costs
of decommissioning nuclear facilities and removal of other facilities.
Georgia Power recorded additional depreciation of electric plant amounting to
$316 million in 1998, $159 million in 1997, and $24 million in 1996. The
accumulated depreciation related to these charges is $505 million at December
31, 1998. See Note 3 under "Georgia Power 1998 Retail Rate Order" for additional
information.
The Nuclear Regulatory Commission (NRC) requires 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 periods approved by the respective state public service commissions.
The NRC's minimum external funding requirements are based on a generic estimate
of the cost to decommission the radioactive portions of a nuclear unit based on
the size and type of reactor. Alabama Power and Georgia Power have filed plans
with the NRC to ensure that -- over time -- the deposits and earnings of the
external trust funds will provide the minimum funding amounts prescribed by the
NRC.
Site study cost is the estimate to decommission a specific facility as of the
site study year, and ultimate cost is the estimate to decommission a specific
facility as of its retirement date. The estimated costs of decommissioning --
both site study costs and ultimate costs -- based on the most current study as
11-28
NOTES (continued)
Southern Company and Subsidiary Companies 1998 Annual Report
of December 31, 1998, 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) 1998 1997 1997
Decommissioning periods:
Beginning year 2017 2014 2027
Completion year 2031 2027 2038
- - - - - - - ---------------------------------------------------------------
(in millions)
Site study costs:
Radiated structures $629 $372 $317
Non-radiated structures 60 33 44
- - - - - - - ---------------------------------------------------------------
Total $689 $405 $361
===============================================================
(in millions)
Ultimate costs:
Radiated structures $1,868 $722 $ 922
Non-radiated structures 178 65 129
- - - - - - - ----------------------------------------------------------------
Total $2,046 $787 $1,051
================================================================
Significant assumptions:
Inflation rate 4.5% 3.6% 3.6%
Trust earning rate 7.0 6.5 6.5
- - - - - - - ----------------------------------------------------------------
The decommissioning cost estimates are based on prompt dismantlement and
removal of the plant from service. The actual decommissioning costs may vary
from the above estimates because of changes in the assumed date of
decommissioning, changes in NRC requirements, or changes in the assumptions used
in making these estimates.
Annual provisions for nuclear decommissioning are based on an annuity method
as approved by the respective state public service commissions. The amount
expensed in 1998 and fund balances were as follows:
Plant Plant Plant
Farley Hatch Vogtle
- - - - - - - ---------------------------------------------------------------
(in millions)
Amount expensed in 1998 $ 18 $ 11 $ 9
Accumulated provisions:
Balance in external trust
funds $232 $172 $112
Balance in internal reserves 42 19 12
- - - - - - - ---------------------------------------------------------------
Total $274 $191 $124
===============================================================
Alabama Power's decommissioning costs for ratemaking are based on the site
study. For Georgia Power effective January 1, 1999, the GPSC increased the
annual provision for decommissioning expenses to $26 million. This amount is
based on the NRC generic estimate to decommission the radioactive portion of the
facilities as of 1997. The estimates are $526 million and $438 million for
plants Hatch and Vogtle, respectively. The ultimate costs associated with the
1997 NRC minimum funding requirements are $1.1 billion and $1.3 billion for
plants Hatch and Vogtle, respectively. Significant assumptions include an
estimated inflation rate of 3.6 percent and an estimated trust earnings rate of
6.5 percent. Alabama Power and Georgia Power expect their respective state
public service commissions to periodically review and adjust, if necessary, the
amounts collected in rates for the anticipated cost of decommissioning.
Income Taxes
Southern Company uses the liability method of accounting for deferred income
taxes and provides deferred income taxes for all significant income tax
temporary differences. Investment tax credits utilized are deferred and
amortized to income over the average lives of the related property.
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.
Property Rights
Included in property rights are leasehold interests in Southern Energy's power
generation facilities that are developed under build, operate, and transfer
agreements with foreign governments. Southern Energy's construction costs are
initially recorded as construction work in progress, and -- after completion --
these costs are recorded as leasehold interests. These costs are amortized over
the length of time the facility is operated before transferring ownership to the
local government. Also included in property rights is a concession agreement
assigned in 1993 by the Argentine government to Southern Energy for the
operation of a hydroelectric plant.
Cash and Cash Equivalents
For purposes of the consolidated financial statements, temporary cash
investments are considered cash equivalents. Temporary cash investments are
securities with original maturities of 90 days or less.
11-29
NOTES (continued)
Southern Company and Subsidiary Companies 1998 Annual Report
Materials and Supplies
Generally, materials and supplies include the costs 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.
Foreign Currency Translation
Assets and liabilities of Southern Company's international operations, where the
local currency is the functional currency, have been translated at year-end
exchange rates, and revenues and expenses have been translated using average
exchange rates prevailing during the year. Adjustments resulting from
translation have been recorded in other comprehensive income. The financial
statements of international operations, where the U.S. dollar is the functional
currency, reflect certain transactions denominated in the local currency that
have been remeasured in U.S. dollars. The remeasurement of local currencies into
U.S. dollars creates gains and losses from foreign currency transactions that
are included in consolidated net income. Foreign exchange gains and losses are
not material for all periods presented.
Comprehensive Income
In 1998, Southern Company adopted FASB Statement No. 130, Reporting
Comprehensive Income. This statement establishes rules for the reporting and
display of comprehensive income and its components. Comprehensive income
consists of net income and foreign currency translation adjustments and is
presented in the consolidated financial statements. The objective of the
statement is to report a measure of all changes in common stock equity of an
enterprise that result from transactions and other economic events of the
period other than transactions with owners.
Financial Instruments for Non-Trading Activities
Non-trading derivative financial instruments are used to hedge exposures to
fluctuations in interest rates, foreign currency exchange rates, and certain
commodity prices. Gains and losses on qualifying hedges are deferred and
recognized either in income or as an adjustment to the carrying amount when the
hedged transaction occurs.
The company utilizes interest rate swaps and cross currency interest rate
swaps to minimize borrowing costs by changing the interest rate and currency of
the original borrowing. For qualifying hedges, the interest rate differential is
reflected as an adjustment to interest expense over the life of the swaps.
Southern Company's international operations are exposed to the effects of
foreign currency exchange rate fluctuations. To protect against this exposure,
the company utilizes currency swaps to hedge its net investment in certain
foreign subsidiaries, which has the effect of converting foreign currency cash
inflows into U.S. dollars at fixed exchange rates. Gains or losses on these
currency swaps, designated as hedges of net investments, are offset against the
translation effects reflected in other comprehensive income, net of tax.
Non-trading financial derivative instruments held at December 31, 1998, were
as follows:
Year of Unrecognized
Maturity or Notional Gain
Type Termination Amount (Loss)
- - - - - - - ------------------------------- ----------------------------
(in millions)
Interest rate
swaps: 2002-2016 $928 $(69)
2001-2012 (pound)600 $(130)
2002-2007 DM691 $(30)
Cross currency
swaps 2001-2007 (pound)429 $11
Cross currency
swaption 2003 DM555 $(18)
- - - - - - - ----------------------------------------------------------------
(pound) - Denotes British pound sterling.
DM - Denotes Deutschemark.
The company is exposed to losses related to financial instruments in the
event of counterparties' nonperformance. The company has established controls to
determine and monitor the creditworthiness of counterparties in order to
mitigate the company's exposure to counterparty credit risk. The company is
unaware of any counterparties that will fail to meet their obligations.
In the United Kingdom, the company utilizes contracts to mitigate its
exposure to volatility in the prices of electricity purchased through the
wholesale electricity market. These contracts allow the company to effectively
convert the majority of its anticipated wholesale electricity purchases from
market prices to fixed prices. The gains and losses on these contracts are
deferred and recognized as electricity is purchased. Recently, a market has
developed for trading these contracts in the United Kingdom. However, due to the
immaturity of this market and the complexity of the company's existing
contracts, it is not practicable to estimate the fair value of these contracts.
11-30
NOTES (continued)
Southern Company and Subsidiary Companies 1998 Annual Report
Other Southern Company financial instruments for which the carrying amount
did not equal fair value at December 31 were as follows:
Carrying Fair
Amount Value
- - - - - - - ----------------------------------------------------------------
(in millions)
Long-term debt:
At December 31, 1998 $11,777 $11,626
At December 31, 1997 10,916 11,160
Capital and preferred securities:
At December 31, 1998 2,179 2,288
At December 31, 1997 1,744 1,826
- - - - - - - ----------------------------------------------------------------
The fair values for long-term debt and capital and preferred securities were
based on either closing market price or closing price of comparable instruments.
Financial Instruments for Trading Activities
Effective in January 1998, Southern Energy and Vastar Resources, Inc. (Vastar)
combined their energy trading and marketing activities to form a joint venture.
Southern Energy's investment in the joint venture is accounted for under the
equity method of accounting. See Note 5 under "Energy Trading and Marketing
Commitments" for additional information. Financial statement disclosure related
to Southern Energy's energy trading and marketing activities for 1997 -- prior
to the formation of the joint venture was presented as follows:
Derivative financial instruments used for trading purposes primarily relate
to commodities associated with the energy sector, such as electricity, natural
gas, and crude oil. These instruments were recorded at fair value for balance
sheet purposes. The determination of fair value considers various factors, such
as closing exchange prices, broker price quotations, and model pricing. Model
pricing considers time value and volatility factors underlying any options and
contractual commitments. These transactions were accounted for using the
mark-to-market method of accounting in which the unrealized gains or losses
resulting from the impact of price movements are recognized as net gains or
losses in the consolidated statements of income. If the company has a master
netting agreement with counterparties, net positions were recognized for
consolidated balance sheet and income statement purposes.
In 1997, the company provided price risk management services by entering into
a variety of contractual commitments such as price cap and floor agreements,
futures contracts, forward purchase and sale agreements, and option contracts.
These contracts generally require future settlement, and are either executed on
an exchange or traded as over-the-counter (OTC) instruments. Contractual
commitments had widely varying terms and durations that ranged from a few hours
to a number of years depending on the instrument. The majority of the company's
transactions at December 31, 1997, were short-term in duration, with a weighted
average maturity of approximately 1.3 years.
All contractual commitments used for trading purposes were recorded at fair
value. Contracts in a net receivable position, as well as options held, were
reported as assets. Similarly, contractual commitments in a net payable
position, as well as options written, were reported as liabilities. The net
unrealized gain from risk management services amounted to $8 million at December
31, 1997. Contractual commitments reflected in the Consolidated Balance Sheets
at December 31, 1997 were as follows:
Net
Notional Fair Value
Amounts --------------------
1997 (Kilowatt-Hours) Assets Liabilities
- - - - - - - ----- -------------------------------------------
(in millions)
Exchange-issued
products:
Futures
contracts 904 $14 $15
Other 958 1 1
- - - - - - - ---------------------------------------------------------------
Total 1,862 15 16
- - - - - - - ---------------------------------------------------------------
OTC products:
Forward
contracts 2,643 69 62
Swaps (473) 1 -
Other 639 9 8
- - - - - - - ---------------------------------------------------------------
Total 2,809 79 70
- - - - - - - ---------------------------------------------------------------
Total 4,671 $94 $86
===============================================================
Notional amounts -- stated in equivalent millions of kilowatt-hours -- are
indicative only of the volume of activity and are not a measure of market risk.
Notional amounts of natural gas and crude oil positions are reflected in
equivalent kilowatt-hours based on standard conversion rates.
11-31
NOTES (continued)
Southern Company and Subsidiary Companies 1998 Annual Report
The annual average gross balances of the company's options and contractual
commitments used for trading purposes, based on month-end balances were as
follows:
Average Fair Value
-----------------------------
1997 Assets Liabilities
- - - - - - - ---- -----------------------------
(in millions)
Commodity instruments:
Electricity $97 $94
Gas 6 6
Other 7 6
- - - - - - - -----------------------------------------------------------------
2. RETIREMENT BENEFITS
Southern Company has defined benefit, trusteed, pension plans that cover
substantially all employees. In the United States, Southern Company provides
certain medical care and life insurance benefits for retired employees.
Substantially all these employees may become eligible for such benefits when
they retire. The operating companies fund trusts to the extent deductible under
federal income tax regulations or to the extent required by their respective
regulatory commissions. In 1998, Southern Company adopted FASB Statement No.
132 Employers' Disclosure about Pensions and Other Postretirement Benefits. The
measurement date is September 30 for each year.
Pension Plans
Changes during the year in the projected benefit obligations and in the fair
value of plan assets were as follows:
Projected
Benefit Obligations
---------------------
1998 1997
- - - - - - - ----------------------------------------------------------------
(in millions)
Balance at beginning of year $3,701 $3,624
Service cost 99 94
Interest cost 273 271
Benefits paid (201) (163)
Actuarial (gain) loss 298 (125)
- - - - - - - ----------------------------------------------------------------
Balance at end of year $4,170 $3,701
================================================================
Plan Assets
--------------------
1998 1997
- - - - - - - ---------------------------------------------------------------
(in millions)
Balance at beginning of year $5,931 $5,212
Actual return on plan assets 223 911
Employer contributions 4 9
Benefits paid (180) (201)
- - - - - - - ---------------------------------------------------------------
Balance at end of year $5,978 $5,931
===============================================================
The accrued pension costs recognized in the Consolidated Balance Sheet were
as follows:
1998 1997
- - - - - - - ----------------------------------------------------------------
(in millions)
Funded status $ 1,808 $ 2,230
Unrecognized transition obligation (89) (101)
Unrecognized prior service cost 119 126
Unrecognized net gain (1,347) (1,874)
Fourth quarter contributions - 2
- - - - - - - ----------------------------------------------------------------
Prepaid asset recognized in the
Consolidated Balance Sheets $ 491 $ 383
================================================================
Components of the plans' net periodic cost were as follows:
1998 1997 1996
- - - - - - - ----------------------------------------------------------------
(in millions)
Service cost $ 99 $ 94 $ 99
Interest cost 273 271 267
Expected return on
plan assets (425) (394) (378)
Recognized net gain (47) (42) (29)
Net amortization (9) (9) (12)
- - - - - - - ----------------------------------------------------------------
Net pension cost (income) $(109) $ (80) $ (53)
================================================================
The weighted average rates assumed in the actuarial calculations for both
the pension plans and postretirement benefits were:
1998 1997
- - - - - - - -----------------------------------------------------------------
Discount 6.75% 7.50%
Annual salary increase 4.25 5.00
Long-term return on plan assets 8.50 8.50
- - - - - - - -----------------------------------------------------------------
Postretirement Benefits
Changes during the year in the projected benefit obligations and in the fair
value of plan assets were as follows:
Projected
Benefit Obligations
------------------
1998 1997
- - - - - - - ----------------------------------------------------------------
(in millions)
Balance at beginning of year $ 935 $870
Service cost 18 18
Interest cost 69 67
Benefits paid (35) (27)
Actuarial (gain) loss 50 7
- - - - - - - ----------------------------------------------------------------
Balance at end of year $1,037 $935
================================================================
11-32
NOTES (continued)
Southern Company and Subsidiary Companies 1998 Annual Report
Plan Assets
---------------------
1998 1997
- - - - - - - ----------------------------------------------------------------
(in millions)
Balance at beginning of year $294 $260
Actual return on plan assets 8 32
Employer contributions 69 29
Benefits paid (35) (27)
- - - - - - - ----------------------------------------------------------------
Balance at end of year $336 $294
=================================================================
The accrued postretirement costs recognized in the Consolidated
Balance Sheet were as follows:
1998 1997
- - - - - - - -----------------------------------------------------------------
(in millions)
Funded status $(701) $(641)
Unrecognized transition obligation 219 233
Unrecognized prior service cost - (4)
Unrecognized net loss (gain) 117 68
Fourth quarter contributions 30 41
- - - - - - - -----------------------------------------------------------------
Accrued liability recognized in the
Consolidated Balance Sheets $(335) $(303)
=================================================================
Components of the plans' net periodic cost were as follows:
1998 1997 1996
- - - - - - - -----------------------------------------------------------------
(in millions)
Service cost $ 18 $ 18 $ 20
Interest cost 69 66 60
Expected return on
plan assets (21) (18) (14)
Recognized net gain 2 3 3
Net amortization 14 17 15
- - - - - - - --------------------------------------------------------------
Net postretirement cost $ 82 $ 86 $ 84
==============================================================
An additional assumption used in measuring the accumulated postretirement
benefit obligation was a weighted average medical care cost trend rate of
8.30 percent for 1998, decreasing gradually to 4.75 percent through the year
2005, and remaining at that level thereafter. An annual increase or decrease
in the assumed medical care cost trend rate of 1 percent would affect the
accumulated benefit obligation and the service and interest cost components at
December 31, 1998 as follows:
1 Percent 1 Percent
Increase Decrease
- - - - - - - ----------------------------------------------------------------
(in millions)
Benefit obligation $75 $(63)
Service and interest costs 7 (6)
- - - - - - - ----------------------------------------------------------------
Work Force Reduction Programs
Southern Company has incurred additional costs for work force reduction
programs. The costs related to these programs were $32 million, $50 million, and
$85 million, for the years 1998, 1997, and 1996, respectively. In addition,
certain costs of these programs were deferred and are being amortized in
accordance with regulatory treatment. The unamortized balance of these costs was
$17 million at December 31, 1998.
3. LITIGATION AND REGULATORY MATTERS
Alabama Power Appliance Warranty Litigation
In 1996, a class action against Alabama Power was filed charging Alabama Power
with fraud and non-compliance with regulatory statutes relating to the offer,
sale, and financing of "extended service contracts" in connection with the sale
of electric appliances. The plaintiffs seek damages in an unspecified amount.
Alabama Power has offered extended service agreements to its customers since
January 1984, and approximately 175,000 extended service agreements could be
involved in these proceedings. The trial court has granted partial summary
judgment in favor of the plaintiffs. Alabama Power has appealed this decision to
the Supreme Court of Alabama. The final outcome of this case cannot now be
determined.
Alabama Power Environmental Litigation
On November 30, 1998, total judgments of nearly $53 million were entered in
favor of five plaintiffs against Alabama Power and two large textile
manufacturers. The plaintiffs alleged that the manufacturers had discharged
certain polluting substances into a stream that empties into Lake Martin, a
hydroelectric reservoir owned by Alabama Power, and that such discharges had
reduced the value of the plaintiffs' residential lots on Lake Martin. Of the
total amount of the judgments, $155 thousand was compensatory damages and the
remainder was punitive damages. The damages were assessed against all three
defendants jointly. Post-trial motions have been filed, and, if relief is not
granted at the trial court level, Alabama Power will appeal these judgments to
the Supreme Court of Alabama. While Alabama Power believes that these judgments
should be reversed or set aside, the final outcome of this matter cannot now be
determined.
11-33
NOTES (continued)
Southern Company and Subsidiary Companies 1998 Annual Report
Georgia Power Potentially Responsible Party Status
In January 1995, Georgia Power and four other unrelated entities were notified
by the Environmental Protection Agency (EPA) that they have been designated as
potentially responsible parties under the Comprehensive Environmental Response,
Compensation, and Liability Act with respect to a site in Brunswick, Georgia. As
of December 31, 1998, Georgia Power had recorded approximately $5 million in
cumulative expenses associated with the site. This represents Georgia Power's
agreed-upon share of the removal and remedial investigation and feasibility
study costs.
The final outcome of this matter cannot now be determined. However, based on
the nature and extent of Georgia Power's activities relating to the site,
management believes that the company's portion of any remaining remediation
costs should not be material to the financial statements.
FERC Review of Equity Returns
On September 21, 1998, the FERC entered separate orders affirming the outcome
of the administrative law judge's opinions in two proceedings in which the
return on common equity component of formula rates contained in substantially
all of the operating companies' wholesale power contracts was being challenged
as unreasonably high. These orders resulted in no change in the wholesale power
contracts that were the subject of such proceedings. The FERC also dismissed a
complaint filed by three customers under long-term power sales agreements
seeking to lower the equity return component in such agreements. These customers
have filed applications for rehearing regarding each FERC order. In response to
a requirement of the September 1998 FERC orders, Southern Company filed a new
equity return component on the long-term power sales contracts, to be effective
January 5, 1999. The proposed equity return was lowered from 13.75 percent to
12.50 percent. If the filed equity return is approved, the estimated impact on
Southern Company's revenues will be approximately $7 million annually. The FERC
placed the new rates into effect subject to refund. Also, this filing was
consolidated with the new proceeding discussed below.
On December 28, 1998, the FERC staff filed a motion asking the FERC to
initiate a new proceeding regarding the equity return and other issues involving
the operating companies' formula rate contracts. The motion was submitted
pursuant to review procedures applicable to these contracts, and would be
applicable to billings under such contracts on and after January 1, 1999.
Southern Company Tax Litigation
In August 1997, Southern Company and the Internal Revenue Service (IRS) entered
into a settlement agreement related to tax issues for the years 1984 through
1987. The agreement received final approval by the Joint Congressional Committee
on Taxation in June 1998 and as a result, Alabama Power and Georgia Power
recognized interest income in 1998 of $14 million and $69 million, respectively.
The refund by the IRS has been received and this matter is now concluded.
Mobile Energy Services Petition for Bankruptcy
On January 14, 1999, Mobile Energy Services Company, LLC (MESC) -- an indirect
subsidiary of Southern Company -- filed a petition for Chapter 11 bankruptcy
relief in the U.S. Bankruptcy Court for the Southern District of Alabama. MESC
is the owner and operator of a facility that generates electricity, produces
steam, and processes black liquor as part of a pulp and paper complex in Mobile,
Alabama. This action is in response to Kimberly-Clark Tissue Company's
announcement in May 1998 of plans to close its pulp mill, effective September 1,
1999. As a part of the filing, MESC also is seeking payment for damages from
Kimberly-Clark Tissue Company. MESC will continue to operate the facility as
debtors-in possession, subject to the supervision and orders of the bankruptcy
court. A reorganization plan has not yet been filed by MESC.
Southern Company's equity investment in MESC was $20 million and MESC's total
assets were $392 million at December 31, 1998. MESC contributed $4 million and
$6 million to consolidated net income in 1998 and 1997, respectively. At
December 31, 1998, MESC had senior debt outstanding of $234 million of first
mortgage bonds and $85 million related to tax-exempt bonds. MESC paid in
January 1999 its regular semi-annual payment of $17 million to its bondholders.
The final outcome of this matter cannot now be determined.
Alabama Power Rate Adjustment Procedures
In November 1982, the Alabama Public Service Commission (APSC) adopted rates
that provide for periodic adjustments based upon Alabama Power's earned return
on end-of-period retail common equity. The rates also provide for adjustments to
recognize the placing of new generating facilities in retail service. Both
increases and decreases have been placed into effect since the adoption of these
rates. The rate adjustment procedures allow a return on common equity range of
13 percent to 14.5 percent and limit increases or decreases in rates to 4
percent in any calendar year.
11-34
NOTES (continued)
Southern Company and Subsidiary Companies 1998 Annual Report
In June 1995, the APSC issued a rate order granting Alabama Power's request
for gradual adjustments to move toward parity among customer classes. This order
also calls for a moratorium on any periodic retail rate increases (but not
decreases) until July 2001.
In December 1995, the APSC issued an order authorizing Alabama Power to
reduce balance sheet items -- such as plant and deferred charges -- at any time
the company's actual base rate revenues exceed the budgeted revenues. In April
1997, the APSC issued an additional order authorizing Alabama Power to reduce
balance sheet asset items. This order authorizes the reduction of such items up
to an amount equal to five times the total estimated annual revenue reduction
resulting from future rate reductions initiated by Alabama Power. In 1998,
Alabama Power -- in accordance with the 1995 rate order -- recorded $33 million
of additional amortization of premium on reacquired debt.
The ratemaking procedures will remain in effect until the APSC votes to
modify or discontinue them.
Georgia Power Investment in Rocky Mountain
In its 1985 financing order, the GPSC concluded that completion of the Rocky
Mountain pumped storage hydroelectric plant in 1991 as then planned was not
economically justifiable and reasonable and withheld authorization for Georgia
Power to spend funds from approved securities issuances on that plant. In 1988,
Georgia Power and Oglethorpe Power Corporation (OPC) entered into a joint
ownership agreement for OPC to assume responsibility for the construction and
operation of the plant. The plant went into commercial operation in 1995.
In June 1996, the GPSC initiated a review of this plant. On January 14, 1998,
the GPSC ordered that Georgia Power be allowed to include approximately $108
million of its $142 million investment in rate base as of December 31, 1998. In
December 1998, Georgia Power recorded a write down of $34 million -- $21 million
after taxes -- on its investment in Rocky Mountain as a result of the GPSC's
1998 retail rate order discussed later. This matter is now concluded.
Georgia Power 1998 Retail Rate Order
As required by the GPSC, Georgia Power filed a general rate case in 1998. On
December 18, 1998, the GPSC approved a new three-year rate order for Georgia
Power. Under the terms of the order, Georgia Power's earnings will continue to
be evaluated against a retail return on common equity range of 10 percent to
12.5 percent. Georgia Power's annual retail rates will be decreased by
$262 million effective January 1, 1999, and by an additional $24 million
effective January 1, 2000. The order further provides for $85 million each year,
and up to an additional $50 million annually in 2000 and 2001 of any earnings in
excess of the 12.5 percent return, to be applied to accelerated amortization or
depreciation of assets. Two-thirds of any additional earnings in excess of the
12.5 percent return in any year will be applied to rate reductions and the
remaining one-third retained by Georgia Power. During the term of the order,
Georgia Power will not file for a general base rate increase unless its
projected retail return on common equity falls below 10 percent. Georgia Power
is required to file a general rate case on July 1, 2001. At that time, the GPSC
would be expected to determine whether the rate order should be continued,
modified, or discontinued.
4. CONSTRUCTION PROGRAM
Southern Company is engaged in continuous construction programs, currently
estimated to total some $2.6 billion in 1999, $2.1 billion in 2000, and
$2.1 billion in 2001. 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; acquisition of additional generating assets; 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, 1998, significant
purchase commitments were outstanding in connection with the construction
program. The operating companies have approximately 2,700 megawatts of combined
cycle generation scheduled to be placed in service by 2001. Southern Energy has
under construction some 1,300 megawatts of owned capacity. In addition,
significant construction will continue related to transmission and distribution
facilities and the upgrading 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. INVESTMENTS, FINANCING, AND
COMMITMENTS
Investments
In December 1998, Southern Energy designed and implemented a plan to dispose of
its Argentinean and Chilean investments by December 31, 1999. As a result,
11-35
NOTES (continued)
Southern Company and Subsidiary Companies 1998 Annual Report
Southern Energy recorded an after-tax write down of approximately $200 million
in 1998 to reflect the difference between the carrying value of these assets
and the estimated fair value of the businesses. Southern Energy estimated the
fair value of the businesses held for sale based upon bids received from
prospective buyers, if available, or the discounted expected future cash flows
to be generated by the assets. The adjusted carrying value of these assets held
for disposal at December 31, 1998 was $90 million. These assets impacted the
Consolidated Statements of Income as follows:
Operating Operating Consolidated
Year Revenues Income Net Income
- - - - - - - ---- ---------------------------------------------
1998 $180 $39 $ 5
1997 180 38 5
1996 157 20 (5)
Depreciation expense was suspended beginning January 1999, and the after-tax
amount of depreciation recorded in 1998 was $16 million. Southern Energy is
actively pursuing and/or negotiating with potential buyers. However at this
time, a definitive agreement has not been entered into.
Southern Energy acquired $670 million of generating assets in 1998 and sold
an additional 26 percent interest in its United Kingdom subsidiary for $170
million. In late 1998, Southern Energy announced plans to acquire $801 million
and $480 million of generating assets in California and New York, respectively.
These transactions are expected to close in 1999. At December 31, 1998, Southern
Energy's total assets amounted to $12 billion.
Financing
The amount and timing of additional equity capital to be raised in 1999 -- as
well as in subsequent years -- will be contingent on Southern Company's
investment opportunities. Equity capital can be provided from any combination of
public offerings, private placements, or the company's stock plans.
The operating companies' construction programs are expected to be financed
primarily from internal sources. Short-term debt is often utilized and the
amounts available are discussed below. The companies may issue additional
long-term debt and preferred securities primarily for debt maturities and for
redeeming higher-cost securities if market conditions permit.
Bank Credit Arrangements
At the beginning of 1999, unused credit arrangements with banks totaled $4.6
billion, of which $2.7 billion expires during 1999, $304 million during 2000 to
2001, $1.0 billion during 2002, and $593 million during 2003 and 2004. The
following table outlines the credit arrangements by company:
Amount of Credit
-----------------------------------------
Expires
--------------------
2000 &
Company Total Unused 1999 beyond
- - - - - - - -------- -----------------------------------------
(in millions)
Alabama Power $ 758 $ 758 $ 678 $ 80
Georgia Power 1,252 1,252 722 530
Gulf Power 103 97 97 -
Mississippi Power 96 76 56 20
Savannah Electric 61 61 41 20
Southern Company 2,000 2,000 1,000 1,000
Southern Energy 907 340 71 269
Other 70 54 54 -
- - - - - - - -----------------------------------------------------------------
Total $5,247 $4,638 $2,719 $1,919
=================================================================
Approximately $2.0 billion of the credit facilities allows for term loans
ranging from one to three years. Most of the agreements include stated borrowing
rates but also allow for competitive bid loans.
All of the credit arrangements require payment of commitment fees based on
the unused portion of the commitments or the maintenance of compensating
balances with the banks. These balances are not legally restricted from
withdrawal. Of the total $4.6 billion in unused credit, $1.7 billion and $1.0
billion are syndicated credit arrangements of Southern Company and Georgia
Power, respectively. These facilities also require the payment of agent fees.
A portion of the $4.6 billion unused credit with banks is allocated to
provide liquidity support to the companies' variable rate pollution control
bonds. At December 31, 1998, the amount of the credit lines allocated for this
purpose was $1.4 billion.
In addition, the companies from time to time borrow under uncommitted lines
of credit with banks. Also, Southern Company, Alabama Power, Georgia Power, and
Southern Energy borrow through commercial paper programs that have the liquidity
support of committed bank credit arrangements.
11-36
NOTES (continued)
Southern Company and Subsidiary Companies 1998 Annual Report
Fuel and Purchased Power Commitments
To supply a portion of the fuel requirements of the generating plants, Southern
Company has entered into various long-term commitments for the procurement of
fossil and nuclear fuel. In most cases, these contracts contain provisions for
price escalations, minimum purchase levels, and other financial commitments.
Also, Southern Company has entered into various long-term commitments for the
purchase of electricity. Total estimated long-term obligations at December 31,
1998, were as follows:
Purchased
Year Fuel Power
- - - - - - - ----- ----------------------------
(in millions)
1999 $1,674 $ 161
2000 1,248 168
2001 1,048 170
2002 860 173
2003 824 177
2004 and thereafter 3,464 1,522
- - - - - - - ----------------------------------------------------------------
Total commitments $9,118 $2,371
================================================================
Operating Leases
Southern Company has operating lease agreements with various terms and
expiration dates. These expenses totaled $50 million, $33 million, and $25
million for 1998, 1997, and 1996, respectively. At December 31, 1998, estimated
minimum rental commitments for noncancelable operating leases were as follows:
Year Amounts
- - - - - - - ----- ---------
(in millions)
1999 $ 46
2000 39
2001 31
2002 30
2003 29
2004 and thereafter 304
- - - - - - - ---------------------------------------------------------------
Total minimum payments $479
===============================================================
Energy Trading and Marketing Commitments
In January 1998, Southern Energy and Vastar combined their energy trading and
marketing activities to form a joint venture, Southern Company Energy Marketing
(SCEM). Southern Company and Vastar have separately made guarantees to certain
counterparties regarding performance of contractual commitments by the joint
venture. Southern Company and Vastar have agreed to indemnify each other against
losses under such guarantees in proportion to their respective ownership shares
of SCEM. Southern Company's ownership interest is 60 percent. At December 31,
1998, outstanding guarantees related to the estimated fair value of net
contractual commitments were approximately $152 million. Based upon the SCEM's
statistical analysis of its credit risk, Southern Company's potential exposure
under these contractual commitments would not materially differ from the
estimated fair value. SCEM's gross revenues and cost of sales for 1998 were $9.2
billion and $9.1 billion, respectively.
Southern Energy has guaranteed certain minimum annual cash distributions,
subject to exclusions, payable by SCEM to Vastar. These distributions before
adjustments total $105 million for the period 1999-2002.
Vastar has the right -- exercisable in the period from December 1, 2002
through the first business day of 2003 -- to sell its remaining interest in SCEM
to Southern Energy. The price will range from $130 million to $210 million
depending on the interest owned by Vastar at that time, plus certain other
contractual considerations.
Assets Subject to Lien
Each of Southern Company's subsidiaries is organized as a legal entity,
separate, and apart from Southern Company and its other subsidiaries. The
subsidiary companies' mortgages, which secure the first mortgage bonds issued by
the companies, constitute a direct first lien on substantially all of the
companies' respective fixed property and franchises. There are no agreements or
other arrangements among the subsidiary companies under which the assets of one
company have been pledged or otherwise made available to satisfy obligations of
Southern Company or any of its other subsidiaries.
6. FACILITY SALES AND JOINT OWNERSHIP
AGREEMENTS
Alabama Power owns an undivided interest in units 1 and 2 of Plant Miller and
related facilities jointly with Alabama Electric Cooperative, Inc.
Georgia Power owns undivided interests in plants Vogtle, Hatch, Scherer, and
Wansley in varying amounts, together with transmission facilities, jointly with
OPC, the Municipal Electric Authority of Georgia, and the city of Dalton,
Georgia. In addition, Georgia Power has joint ownership agreements with OPC for
11-37
NOTES (continued)
Southern Company and Subsidiary Companies 1998 Annual Report
the Rocky Mountain project and with Florida Power Corporation (FPC) for a
combustion turbine unit at Intercession City, Florida.
At December 31, 1998, Alabama Power's and Georgia Power's ownership and
investment (exclusive of nuclear fuel) in jointly owned facilities with the
above entities were as follows:
Jointly Owned Facilities
------------------------------------------
Percent Amount of Accumulated
Ownership Investment Depreciation
--------- ------------ ----------------
(in millions)
Plant Vogtle
(nuclear) 45.7% $3,296 $1,514
Plant Hatch
(nuclear) 50.1 840 538
Plant Miller
(coal)
Units 1 and 2 91.8 717 330
Plant Scherer
(coal)
Units 1 and 2 8.4 112 48
Plant Wansley
(coal) 53.5 298 141
Rocky Mountain
(pumped storage) 25.4 169 61
Intercession City
(combustion turbine) 33.3 12 *
- - - - - - - -----------------------------------------------------------------
*Less than $1 million.
Alabama Power and Georgia Power have contracted to operate and maintain the
jointly owned facilities -- except for the Rocky Mountain project and
Intercession City -- as agents for their respective co-owners. The companies'
proportionate share of their plant operating expenses is included in the
corresponding operating expenses in the Consolidated Statements of Income.
7. LONG-TERM POWER SALES AGREEMENTS
The operating companies have long-term contractual agreements for the sale of
capacity and energy to certain non-affiliated utilities located outside the
system's service area. These 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,
profitability is primarily affected by revenues from capacity sales. The
capacity revenues amounted to $196 million in 1998, $203 million in 1997, and
$217 million in 1996.
Unit power from specific generating plants is currently being sold to Florida
Power & Light Company (FP&L), FPC, Jacksonville Electric Authority (JEA), and
the city of Tallahassee, Florida. Under these agreements, approximately 1,600
megawatts of capacity is scheduled to be sold in 1999. Thereafter, these sales
will decline to some 1,500 megawatts and remain at that approximate level --
unless reduced by FP&L, FPC, and JEA for the periods after 1999 with a minimum
of three years notice -- until the expiration of the contracts in 2010.
8. INCOME TAXES
At December 31, 1998, the tax-related regulatory assets and liabilities were
$1.0 billion and $715 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 income tax provisions are as follows:
1998 1997 1996
- - - - - - - ---------------------------------------------------------------
(in millions)
Total provision for income taxes:
Federal --
Currently payable $ 451 $ 547 $569
Deferred -- current year 195 188 116
-- reversal of
prior years (208) (160) (74)
- - - - - - - ---------------------------------------------------------------
438 575 611
- - - - - - - ---------------------------------------------------------------
State --
Currently payable 106 104 82
Deferred -- current year 28 15 23
-- reversal of
prior years (31) (19) (9)
- - - - - - - ---------------------------------------------------------------
103 100 96
- - - - - - - ---------------------------------------------------------------
International --
Windfall profits tax
assessed in United Kingdom - 148 -
Other 8 16 50
- - - - - - - ---------------------------------------------------------------
Total 549 839 757
Less income taxes charged
(credited) to other income (8) 114 10
- - - - - - - ---------------------------------------------------------------
Total income taxes charged
to operations $ 557 $ 725 $747
===============================================================
The first half of the windfall profits tax assessed in the United Kingdom was
paid in December 1997, and the remainder in December 1998.
11-38
NOTES (continued)
Southern Company and Subsidiary Companies 1998 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:
1998 1997
- - - - - - - ---------------------------------------------------------------
(in millions)
Deferred tax liabilities:
Accelerated depreciation $3,315 $3,345
Property basis differences 1,667 1,756
Other 403 269
- - - - - - - ---------------------------------------------------------------
Total 5,385 5,370
- - - - - - - ---------------------------------------------------------------
Deferred tax assets:
Federal effect of state deferred taxes 104 108
Other property basis differences 239 245
Deferred costs 132 116
Pension and other benefits 79 72
Other 293 197
- - - - - - - ---------------------------------------------------------------
Total 847 738
- - - - - - - ---------------------------------------------------------------
Net deferred tax liabilities 4,538 4,632
Portion included in current assets, net (57) 18
- - - - - - - ---------------------------------------------------------------
Accumulated deferred income taxes
in the Consolidated Balance Sheets $4,481 $4,650
===============================================================
Deferred investment tax credits are amortized over the life of the related
property with such amortization normally applied as a credit to reduce
depreciation in the Consolidated Statements of Income. Credits amortized in this
manner amounted to $38 million in 1998, $30 million in 1997, and $33 million in
1996. At December 31, 1998, 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:
1998 1997 1996
- - - - - - - ----------------------------------------------------------------
Federal statutory rate 35.0% 35.0% 35.0%
State income tax,
net of federal deduction 4.1 3.4 3.2
Non-deductible book
depreciation 4.1 2.3 1.8
International tax credits (6.4) - -
Windfall profits tax - 8.0 -
Difference in prior years'
deferred and current tax rate (1.3) (1.5) (1.0)
Other (1.8) (1.9) (0.5)
- - - - - - - ----------------------------------------------------------------
Effective income tax rate 33.7% 45.3% 38.5%
================================================================
Southern Company files a consolidated federal income tax return. Under a
joint consolidated income tax agreement, each subsidiary's current and deferred
tax expense is computed on a stand-alone basis. Tax benefits from losses of the
parent company are allocated to each subsidiary based on the ratio of taxable
income to total consolidated taxable income.
The undistributed earnings of certain foreign subsidiaries aggregated $251
million as of December 31, 1998, which, under existing tax law, will not be
subject to U.S. income tax until distributed. Because the earnings have been or
are intended to be indefinitely reinvested, no provision has been made for any
taxes that may be applicable. It is not practicable to estimate the amount of
unrecognized deferred U.S. income taxes on undistributed earnings.
9. COMMON STOCK
Treasury Stock
In July 1998, Southern Company's Board of Directors authorized the company to
make open market purchases of its common stock in an aggregate amount not to
exceed $300 million through March 31, 1999. The purpose of the program is to
provide shares of common stock for the purchase requirements of Southern
Company's various stockholder, employee, and outside director stock purchase
plans. Under the program, 4.4 million shares have been repurchased and 2.4
million shares were reissued through December 31, 1998.
Shares Reserved
At December 31, 1998, a total of 45 million shares was reserved for issuance
pursuant to the Southern Investment Plan, the Employee Savings Plan, the Outside
Directors Stock Plan, and the Performance Stock Plan.
Performance Stock Plan
As of December 31, 1998, 302 current and former employees participated in the
Performance Stock Plan. The maximum number of shares of common stock that may be
issued under the new plan may not exceed 40 million. The prices of options
granted to date have been at the fair market value of the shares on the dates of
grant. Options granted to date become exercisable pro rata over a maximum period
of four years from the date of grant. Options outstanding will expire no later
than 10 years after the date of grant, unless terminated earlier by the Southern
11-39
NOTES (continued)
Southern Company and Subsidiary Companies 1998 Annual Report
Company Board of Directors in accordance with the plan. Stock option activity in
1997 and 1998 for the plan is summarized below:
Shares Average
Subject Option Price
To Option Per Share
- - - - - - - --------------------------------------------------------------
Balance at December 31, 1996 3,825,164 $21.11
Options granted 1,776,094 21.25
Options canceled (64,326) 22.10
Options exercised (137,426) 19.72
- - - - - - - --------------------------------------------------------------
Balance at December 31, 1997 5,399,506 21.15
Options granted 1,659,519 27.03
Options canceled (23,495) 23.18
Options exercised (603,195) 20.92
- - - - - - - --------------------------------------------------------------
Balance at December 31, 1998 6,432,335 $23.92
==============================================================
Shares reserved for future grants:
At December 31, 1996 668,062
At December 31, 1997 38,241,376
At December 31, 1998 36,598,001
- - - - - - - --------------------------------------------------------------
Options exercisable:
At December 31, 1997 2,006,511
At December 31, 1998 2,653,591
- - - - - - - --------------------------------------------------------------
Southern Company accounts for its stock-based compensation plans in
accordance with Accounting Principles Board Opinion No. 25. Accordingly, no
compensation expense has been recognized.
The pro forma impact on earnings of fair-value accounting for options granted
- - - - - - - -- as required by FASB Statement No. 123, Accounting for Stock-Based
Compensation -- is less than 1 cent per share and is not significant to the
consolidated financial statements.
Earnings Per Share
FASB Statement No. 128, Earnings per Share simplifies the methodology for
computing both basic and diluted earnings per share. The only difference in the
two methods for computing Southern Company's per share amounts is attributable
to outstanding options under the Performance Stock Plan. The effect of the stock
options was determined using the treasury stock method. Consolidated net income
as reported was not affected. Shares used to compute diluted earnings per share
are as follows:
Average Common Stock Shares
--------------------------------
1998 1997 1996
- - - - - - - ---------------------------------------------------------------
(in thousands)
As reported shares 696,944 685,033 672,590
Effect of options 739 201 200
- - - - - - - ---------------------------------------------------------------
Diluted shares 697,683 685,234 672,790
===============================================================
Common Stock Dividend Restrictions
The income of Southern Company is derived primarily from equity in earnings of
its subsidiaries. At December 31, 1998, consolidated retained earnings included
$3.4 billion of undistributed retained earnings of the subsidiaries. Of this
amount, $2.0 billion was restricted against the payment by the subsidiary
companies of cash dividends on common stock under terms of bond indentures.
10. CAPITAL AND PREFERRED SECURITIES
Company or subsidiary obligated mandatorily redeemable capital and preferred
securities have been issued by special purpose financing entities of Southern
Company and its subsidiaries. Substantially all the assets of these special
financing entities are junior subordinated notes issued by the related company
seeking financing. Each of these companies considers that the mechanisms and
obligations relating to the capital or preferred securities issued for its
benefit, taken together, constitute a full and unconditional guarantee by it of
the respective special financing entities' payment obligations with respect to
the capital or preferred securities. At December 31, 1998, capital securities of
$950 million and preferred securities of $1.2 billion were outstanding. Southern
Company guarantees the notes related to $950 million of capital securities
issued on its behalf.
11. LONG-TERM DEBT DUE WITHIN ONE YEAR
A summary of the improvement fund requirements and scheduled maturities and
redemptions of long-term debt due within one year at December 31 is as follows:
1998 1997
- - - - - - - ---------------------------------------------------------------
(in millions)
Bond improvement fund requirements $ 23 $ 38
Less:
Portion to be satisfied by certifying
property additions 14 3
- - - - - - - ---------------------------------------------------------------
Cash requirements 9 35
First mortgage bond maturities
and redemptions 868 349
Other long-term debt maturities 563 400
- - - - - - - ---------------------------------------------------------------
Total $1,440 $784
===============================================================
The first mortgage bond improvement fund requirements amount to 1 percent of
each outstanding series of bonds authenticated under the indentures prior to
11-40
NOTES (continued)
Southern Company and Subsidiary Companies 1998 Annual Report
January 1 of each year, other than those issued to collateralize pollution
control revenue bonds 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.
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.
Improvement fund requirements and/or serial maturities through 2003
applicable to other long-term debt are as follows: $563 million in 1999; $385
million in 2000; $433 million in 2001; $1,035 million in 2002; and $387 million
in 2003.
12. 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
$9.7 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 $88 million per incident for each licensed reactor it operates, but not more
than an aggregate of $10 million per incident to be paid in a calendar year for
each reactor. Such maximum assessment, excluding any applicable state premium
taxes, for Alabama Power and Georgia Power -- based on its ownership and buyback
interests -- is $176 million and $178 million, respectively, per incident, but
not more than an aggregate of $20 million per company to be paid for each
incident in any one year.
Alabama Power and Georgia Power are members of Nuclear Electric Insurance
Limited (NEIL), a mutual insurer established to provide property damage
insurance in an amount up to $500 million for members' nuclear generating
facilities.
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 primary
coverage. This excess insurance is also provided by NEIL.
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 17 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 current maximum annual assessments for Alabama Power and Georgia
Power under the three NEIL policies would be $21 million and $25 million,
respectively.
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.
All retrospective assessments -- whether generated for liability, property,
or replacement power -- may be subject to applicable state premium taxes.
13. PURCHASE METHOD ACQUISITION
Southern Energy completed in 1997 the acquisition of a 100 percent interest in
Consolidated Electric Power Asia (CEPA) for a total net investment of some $2.1
billion. CEPA is the largest independent power producer in Asia. The CEPA
11-41
NOTES (continued)
Southern Company and Subsidiary Companies 1998 Annual Report
acquisition has been accounted for under the purchase method of accounting. The
acquisition cost exceeded the fair market value of net assets by approximately
$1.6 billion. This amount is considered goodwill and is being amortized on a
straight-line basis over 40 years.
CEPA has been included in the consolidated financial statements since January
29, 1997. The following unaudited pro forma results of operations have been
prepared assuming the acquisition of CEPA, effective January 1, 1996. The pro
forma results assume acquisition financing of $716 million of short-term
borrowings, $792 million of long-term notes, and $600 million of capital
securities. Southern Company's assumed effective composite interest rate on
these obligations for each period was 6.82 percent.
These unaudited pro forma results are not necessarily indicative of the
actual results that would have been realized had the acquisition occurred on the
assumed dates, nor are they necessarily indicative of future results. Pro forma
operating results are for information purposes only and are as follows:
1997 1996
----------------------------------------------------------
As Pro As Pro
Reported Forma Reported Forma
- - - - - - - -----------------------------------------------------------------------------------------------------
Operating revenues (in millions) $12,611 $12,632 $10,358 $10,506
Consolidated net income (in millions) $972 $977 $1,127 $1,109
Earnings per share $1.42 $1.43 $1.68 $1.65
14. SEGMENT AND RELATED INFORMATION
Effective December 31, 1997, Southern Company adopted FASB Statement No. 131,
Disclosure About Segments of an Enterprise and Related Information. Southern
Company's principal business segment -- or its traditional core business -- is
the five regulated electric utility operating companies that provide electric
service in four southeastern states. The other reportable business segment is
non-traditional energy services to retail and wholesale customers provided by
Southern Energy, which develops and manages electricity and other energy-related
projects both in the United States and abroad including domestic energy trading
and marketing for 1997 and 1996. Intersegment revenues are not material.
Financial data for business segments, products and services, and geographic
areas are as follows:
Business Segments
Regulated Southern Energy
Domestic Non-Traditional Services All
Electric ------------------------------------------ Other Reconciling
Year Utilities International Domestic Total (Note) Eliminations Consolidated
- - - - - - - ---- ------------- -----------------------------------------------------------------------------------
(in millions)
1998
- - - - - - - -----
Operating revenues $ 9,363 $1,766 $ 137 $ 1,903 $ 166 $ (29) $11,403
Depreciation and amortization 1,289 216 18 234 16 - 1,539
Interest income 150 86 61 147 57 (111) 243
Net interest charges 654 318 91 409 97 (58) 1,102
Income taxes from operations 721 (123) (4) (127) (18) (19) 557
Writedown of generating assets 34 308 - 308 - - 342
Net income from equity
method subsidiaries 2 126 (5) 121 - - 123
Segment net income (loss) 1,083 23 16 39 (110) (35) 977
Total assets 24,476 9,578 2,869 12,447 1,428 (2,159) 36,192
Investments in equity
method subsidiaries 10 1,363 176 1,539 - 11 1,560
Gross property additions 1,298 586 63 649 58 - 2,005
Increase in goodwill - 30 200 230 - - 230
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------------
11-42
NOTES (continued)
Southern Company and Subsidiary Companies 1998 Annual Report
Regulated Southern Energy
Domestic Non-Traditional Services All
Electric ---------------------------------------- Other Reconciling
Year Utilities International Domestic Total (Note) Eliminations Consolidated
- - - - - - - ----- ---------------------------------------------------------------------------------------------------
(in millions)
1997
- - - - - - - ----
Operating revenues $ 8,688 $1,748 $2,089 $ 3,837 $ 98 $ (12) $12,611
Depreciation and amortization 1,156 179 15 194 17 - 1,367
Interest income 51 96 42 138 21 (58) 152
Net interest charges 588 289 73 362 84 (41) 993
Income taxes from operations 735 24 (11) 13 (17) (6) 725
Windfall profits tax - 148 - 148 - - 148
Net income from equity
method subsidiaries 1 41 7 48 - (14) 35
Segment net income (loss) 1,105 (4) 5 1 (123) (11) 972
Total assets 24,555 9,225 1,832 11,057 1,224 (1,581) 35,255
Investments in equity
method subsidiaries 10 1,023 135 1,158 - - 1,168
Gross property additions 1,080 720 1 721 58 - 1,859
Increase in goodwill - 1,649 - 1,649 - - 1,649
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------------
Regulated Southern Energy
Domestic Non-Traditional Services All
Electric ---------------------------------------- Other Reconciling
Year Utilities International Domestic Total (Note) Eliminations Consolidated
- - - - - - - ----- ---------------------------------------------------------------------------------------------------
(in millions)
1996
- - - - - - - ----
Operating revenues $ 8,639 $1,506 $177 $1,683 $ 50 $(14) $10,358
Depreciation and amortization 1,019 95 13 108 6 - 1,133
Interest income 36 15 2 17 20 (19) 54
Net interest charges 546 126 31 157 18 (2) 719
Income taxes from operations 755 16 (4) 12 (14) (6) 747
Net income from equity
method subsidiaries 1 11 - 11 - (6) 6
Segment net income (loss) 1,086 88 4 92 (40) (11) 1,127
Total assets 24,899 4,320 604 4,924 450 (87) 30,186
Investments in equity
method subsidiaries 8 227 - 227 - (8) 227
Gross property additions 1,033 157 8 165 31 - 1,229
Increase in goodwill - - - - - - -
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------------
(Note) The all other category includes parent Southern Company, which does not allocate operating expenses to business segments.
Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include a wireless
communication company and a developmental company for energy products and services. Non-traditional services exclude interest
expense to parent Southern Company.
11-43
NOTES (continued)
Southern Company and Subsidiary Companies 1998 Annual Report
Products and Services
Revenues
-------------------------------------------------------------------------------------------------------------
Regulated Domestic Southern Energy
Electric Utilities Non-Traditional Energy Services
----------------------------------- ----------------------------------------------------------------------
Energy
Trading
Year Retail Wholesale Other Total Generation Distribution Marketing Other Total
- - - - - - - ---- -------------------------------------------------------------------------------------------------------------------------
(in millions)
1998 $8,272 $896 $195 $9,363 $578 $1,273 $ - $52 $1,903
1997 7,647 886 155 8,688 513 1,282 1,982 60 3,837
1996 7,665 838 136 8,639 242 1,309 77 55 1,683
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------------
Geographic Areas
Revenues
-----------------------------------------------------------------------------------------------------
International
-------------------------------------------------------------
United Southeast All
Year Domestic Kingdom Asia Other Total Consolidated
- - - - - - - ---- -----------------------------------------------------------------------------------------------------
(in millions)
1998 $9,637 $1,273 $273 $220 $1,766 $11,403
1997 10,863 1,282 247 219 1,748 12,611
1996 8,852 1,309 - 197 1,506 10,358
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------------
Long-Lived Assets
------------------------------------------------------------------------------------
International
-------------------------------------------------------------
United Southeast All
Year Domestic Kingdom Asia Other Total Consolidated
- - - - - - - ---- -----------------------------------------------------------------------------------------------------
(in millions)
1998 $22,005 $2,463 $3,772 $1,856 $8,091 $30,096
1997 21,282 2,428 3,628 1,888 7,944 29,226
1996 21,190 2,473 108 999 3,580 24,770
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------------
15. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Summarized quarterly financial data for 1998 and 1997 are as follows:
Per Common Share
---------------------------------------------------
Price Range
Operating Operating Consolidated --------------------
Quarter Ended Revenues Income Net Income Earnings Dividends High Low
- - - - - - - -------------- ------------------------------------ -----------------------------------------------------
(in millions)
March 1998 $2,495 $437 $242 $0.35 $0.335 28 11/16 23 15/16
June 1998 2,913 490 270 0.39 0.335 29 25 1/16
September 1998 3,457 752 517 0.74 0.335 29 13/16 25 1/4
December 1998 2,538 74 (52) (0.08) 0.335 31 9/16 27 3/16
March 1997 $2,585 $397 $187 $0.28 $0.325 23 3/8 20 3/4
June 1997 2,717 429 215 0.31 0.325 22 1/4 19 7/8
September 1997 4,071 720 375 0.55 0.325 23 20 13/16
December 1997 3,238 394 195 0.28 0.325 26 1/4 22
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------------
Southern Company's business is influenced by seasonal weather conditions.
Earnings for the fourth quarter 1998 declined by $221 million, or 32 cents per share, as a result of write downs in certain
generating assets as discussed in Notes 3 and 5.
Earnings for the third quarter 1997 declined by $111 million, or 16 cents per share, as a result of a windfall profits tax being
assessed in the United Kingdom.
11-44
SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA 1988-1998
Southern Company and Subsidiary 1998 Annual Report
1998 1997 1996
- - - - - - - -----------------------------------------------------------------------------------------------------------------
Operating Revenues (in millions) $11,403 $12,611 $10,358
Consolidated Net Income (in millions) $977 $972 $1,127
Basic and Diluted Earnings Per Share of Common Stock $1.40 $1.42 $1.68
Cash Dividends Paid Per Share of Common Stock $1.34 $1.30 $1.26
Return on Average Common Equity (percent) 10.04 10.30 12.53
Total Assets (in millions) $36,192 $35,255 $30,230
Gross Property Additions (in millions) $2,005 $1,859 $1,229
- - - - - - - -----------------------------------------------------------------------------------------------------------------
Capitalization (in millions):
Common stock equity $ 9,797 $ 9,647 $ 9,216
Preferred stock and securities 2,548 2,237 1,402
Long-term debt 10,472 10,274 7,938
- - - - - - - -----------------------------------------------------------------------------------------------------------------
Total excluding amounts due within one year $22,817 $22,158 $18,556
=================================================================================================================
Capitalization Ratios (percent):
Common stock equity 42.9 43.5 49.7
Preferred stock and securities 11.2 10.1 7.6
Long-term debt 45.9 46.4 42.7
- - - - - - - -----------------------------------------------------------------------------------------------------------------
Total excluding amounts due within one year 100.0 100.0 100.0
=================================================================================================================
Other Common Stock Data:
Book value per share (year-end) $14.04 $13.91 $13.61
Market price per share:
High 31 9/16 26 1/4 25 7/8
Low 23 15/16 19 7/8 21 1/8
Close 29 1/16 25 7/8 22 5/8
Market-to-book ratio (year-end) (percent) 207.0 186.0 166.2
Price-earnings ratio (year-end) (times) 20.8 18.2 13.5
Dividends paid (in millions) $933 $889 $846
Dividend yield (year-end) (percent) 4.6 5.0 5.6
Dividend payout ratio (percent) 95.6 91.5 75.1
Cash coverage of dividends (year-end) (times) 3.2 2.8 2.9
Proceeds from sales of stock (in millions) $234 $360 $171
Shares outstanding (in thousands):
Average 696,944 685,033 672,590
Year-end 697,805 693,423 677,036
Stockholders of record (year-end) 187,053 200,508 215,246
- - - - - - - -----------------------------------------------------------------------------------------------------------------
First Mortgage Bonds (in millions):
Issued $ - $- $85
Retired 1,487 168 426
Preferred Stock and Capital and Preferred Securities (in millions):
Issued $635 $1,321 $322
Retired 239 660 179
- - - - - - - -----------------------------------------------------------------------------------------------------------------
Traditional Core Business Customers (year-end) (in thousands):
Residential 3,277 3,220 3,157
Commercial 497 479 464
Industrial 15 16 17
Other 5 5 5
- - - - - - - -----------------------------------------------------------------------------------------------------------------
Total 3,794 3,720 3,643
=================================================================================================================
Employees (year-end):
Traditional core business 25,206 24,682 25,034
Southern Energy 6,642 5,620 3,743
- - - - - - - -----------------------------------------------------------------------------------------------------------------
Total 31,848 30,302 28,777
=================================================================================================================
11-45
SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA 1988-1998 (continued)
Southern Company and Subsidiary Companies 1998 Annual Report
1995 1994 1993 1992
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in millions) $9,180 $8,297 $8,489 $8,073
Consolidated Net Income (in millions) $1,103 $989 $1,002 $953
Basic and Diluted Earnings Per Share of Common Stock $1.66 $1.52 $1.57 $1.51
Cash Dividends Paid Per Share of Common Stock $1.22 $1.18 $1.14 $1.10
Return on Average Common Equity (percent) 13.01 12.47 13.43 13.42
Total Assets (in millions) $30,522 $27,042 $25,911 $20,038
Gross Property Additions (in millions) $1,401 $1,536 $1,441 $1,105
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------
Capitalization (in millions):
Common stock equity $ 8,772 $ 8,186 $ 7,684 $ 7,234
Preferred stock and securities 1,432 1,432 1,333 1,359
Long-term debt 8,274 7,593 7,412 7,241
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------
Total excluding amounts due within one year $18,478 $17,211 $16,429 $15,834
==============================================================================================================================
Capitalization Ratios (percent):
Common stock equity 47.5 47.6 46.8 45.7
Preferred stock and securities 7.7 8.3 8.1 8.6
Long-term debt 44.8 44.1 45.1 45.7
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------
Total excluding amounts due within one year 100.0 100.0 100.0 100.0
==============================================================================================================================
Other Common Stock Data:
Book value per share (year-end) $13.10 $12.47 $11.96 $11.43
Market price per share:
High 25 22 23 5/8 19 1/2
Low 19 3/8 17 18 3/8 15 1/8
Close 24 5/8 20 22 19 1/4
Market-to-book ratio (year-end) (percent) 188.0 160.4 183.9 168.4
Price-earnings ratio (year-end) (times) 14.8 13.2 14.0 12.7
Dividends paid (in millions) $811 $766 $726 $695
Dividend yield (year-end) (percent) 5.0 5.9 5.2 5.7
Dividend payout ratio (percent) 73.5 77.5 72.4 72.9
Cash coverage of dividends (year-end) (times) 2.9 2.7 2.9 2.8
Proceeds from sales of stock (in millions) $277 $279 $204 $30
Shares outstanding (in thousands):
Average 665,064 649,927 637,319 631,844
Year-end 669,543 656,528 642,662 632,917
Stockholders of record (year-end) 225,739 234,927 237,105 247,378
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
First Mortgage Bonds (in millions):
Issued $375 $185 $2,185 $1,815
Retired 538 241 2,178 2,575
Preferred Stock and Capital and Preferred Securities (in millions):
Issued $- $100 $426 $410
Retired 1 1 516 326
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Traditional Core Business Customers (year-end) (in thousands):
Residential 3,100 3,046 2,996 2,950
Commercial 450 439 427 414
Industrial 17 17 18 18
Other 5 5 4 4
- - - - - - - -------------------------------------------------------------------------------------------------------------------------------
Total 3,572 3,507 3,445 3,386
===============================================================================================================================
Employees (year-end):
Traditional core business 26,452 27,480 28,516 28,872
Southern Energy 5,430 1,400 745 213
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------
31,882 28,880 29,261 29,085
==============================================================================================================================
11-46A
SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA 1988-1998
Southern Company and Subsidiary Companies 1998 Annual Report
1991 1990 1989 1988
- - - - - - - ----------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in millions) $8,050 $8,053 $7,620 $7,287
Consolidated Net Income (in millions) $876 $604 $846 $846
Basic and Diluted Earnings Per Share of Common Stock $1.39 $0.96 $1.34 $1.36
Cash Dividends Paid Per Share of Common Stock $1.07 $1.07 $1.07 $1.07
Return on Average Common Equity (percent) 12.74 8.85 12.49 13.03
Total Assets (in millions) $19,863 $19,955 $20,092 $19,731
Gross Property Additions (in millions) $1,123 $1,185 $1,346 $1,754
- - - - - - - ----------------------------------------------------------------------------------------------------------------------------------
Capitalization (in millions):
Common stock equity $ 6,976 $ 6,783 $ 6,861 $ 6,686
Preferred stock and securities 1,333 1,358 1,400 1,465
Long-term debt 7,992 8,458 8,575 8,433
- - - - - - - ----------------------------------------------------------------------------------------------------------------------------------
Total excluding amounts due within one year $16,301 $16,599 $16,836 $16,584
==================================================================================================================================
Capitalization Ratios (percent):
Common stock equity 42.8 40.9 40.8 40.3
Preferred stock and securities 8.2 8.2 8.3 8.8
Long-term debt 49.0 50.9 50.9 50.9
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Total excluding amounts due within one year 100.0 100.0 100.0 100.0
==================================================================================================================================
Other Common Stock Data:
Book value per share (year-end) $11.05 $10.74 $10.87 $10.60
Market price per share:
High 17 3/8 14 5/8 14 7/8 12 1/8
Low 12 7/8 11 1/2 11 10 1/8
Close 17 1/8 13 7/8 14 1/2 11 1/8
Market-to-book ratio (year-end) (percent) 155.5 129.7 134.0 105.5
Price-earnings ratio (year-end) (times) 12.4 14.6 10.9 8.2
Dividends paid (in millions) $676 $676 $675 $661
Dividend yield (year-end) (percent) 6.2 7.7 7.3 9.6
Dividend payout ratio (percent) 77.1 111.8 79.8 78.1
Cash coverage of dividends (year-end) (times) 2.5 2.8 2.6 2.3
Proceeds from sales of stock (in millions) $- $- $4 $194
Shares outstanding (in thousands):
Average 631,307 631,307 631,303 622,292
Year-end 631,307 631,307 631,307 630,898
Stockholders of record (year-end) 254,568 263,046 273,751 290,725
- - - - - - - ----------------------------------------------------------------------------------------------------------------------------------
First Mortgage Bonds (in millions):
Issued $380 $300 $280 $335
Retired 881 146 201 273
Preferred Stock and Capital and Preferred Securities (in millions):
Issued $100 $- $- $120
Retired 125 96 21 10
- - - - - - - ----------------------------------------------------------------------------------------------------------------------------------
Traditional Core Business Customers (year-end) (in thousands):
Residential 2,903 2,865 2,824 2,781
Commercial 403 396 392 384
Industrial 18 18 18 18
Other 4 4 4 4
- - - - - - - ----------------------------------------------------------------------------------------------------------------------------------
Total 3,328 3,283 3,238 3,187
==================================================================================================================================
Employees (year-end):
Traditional core business 30,144 30,087 30,368 32,366
Southern Energy 258 176 162 157
- - - - - - - ----------------------------------------------------------------------------------------------------------------------------------
Total 30,402 30,263 30,530 32,523
==================================================================================================================================
11-46B
SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA 1988-1998
Southern Company and Subsidiary Companies 1998 Annual Report
1998 1997 1996
- - - - - - - --------------------------------------------------------------------------------------------------------
Operating Revenues (in millions):
Residential $ 3,163 $ 2,837 $ 2,894
Commercial 2,763 2,595 2,559
Industrial 2,267 2,139 2,136
Other 79 76 76
- - - - - - - --------------------------------------------------------------------------------------------------------
Total retail 8,272 7,647 7,665
Sales for resale within service area 374 376 409
Sales for resale outside service area 522 510 429
- - - - - - - --------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 9,168 8,533 8,503
Southern Energy 1,903 3,837 1,683
Other revenues 332 241 172
- - - - - - - --------------------------------------------------------------------------------------------------------
Total $11,403 $12,611 $10,358
========================================================================================================
Kilowatt-Hour Sales (in millions):
Residential 43,503 39,217 40,117
Commercial 41,737 38,926 37,993
Industrial 55,331 54,196 52,798
Other 929 903 911
- - - - - - - --------------------------------------------------------------------------------------------------------
Total retail 141,500 133,242 131,819
Sales for resale within service area 9,847 9,884 10,935
Sales for resale outside service area 12,988 13,761 10,777
- - - - - - - --------------------------------------------------------------------------------------------------------
Total 164,335 156,887 153,531
========================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 7.27 7.23 7.21
Commercial 6.62 6.67 6.74
Industrial 4.10 3.95 4.04
Total retail 5.85 5.74 5.81
Sales for resale 3.92 3.75 3.86
Total sales 5.58 5.44 5.54
Average Annual Kilowatt-Hour Use Per Residential Customer 13,379 12,296 12,824
Average Annual Revenue Per Residential Customer $972.89 $889.50 $925.12
Plant Nameplate Capacity Owned (year-end) (megawatts) 31,161 31,146 31,076
Maximum Peak-Hour Demand (megawatts):
Winter 21,108 22,969 22,631
Summer 28,934 27,334 27,190
System Reserve Margin (at peak) (percent) 12.8 15.0 14.0
Annual Load Factor (percent) 60.0 59.4 62.3
Plant Availability (percent):
Fossil-steam 85.2 88.2 86.4
Nuclear 87.8 88.8 89.7
- - - - - - - --------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 72.8 74.7 73.3
Nuclear 15.4 16.5 16.7
Hydro 3.9 4.3 4.1
Oil and gas 3.3 1.7 1.5
Purchased power 4.6 2.8 4.4
- - - - - - - --------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0
========================================================================================================
Total Fuel Economy Data:
BTU per net kilowatt-hour generated 9,690 10,035 10,257
Cost of fuel per million BTU(cents) 152.89 145.81 144.02
Average cost of fuel per net kilowatt-hour generated (cents) 1.48 1.46 1.48
- - - - - - - --------------------------------------------------------------------------------------------------------
II-47
SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA 1988-1998
Southern Company and Subsidiary Companies 1998 Annual Report
1995 1994 1993 1992
- - - - - - - ---------------------------------------------------------------------------------------------------------------------
Operating Revenues (in millions):
Residential $2,840 $2,560 $2,696 $2,402
Commercial 2,485 2,357 2,313 2,181
Industrial 2,206 2,162 2,200 2,126
Other 72 70 68 64
- - - - - - - ---------------------------------------------------------------------------------------------------------------------
Total retail 7,603 7,149 7,277 6,773
Sales for resale within service area 399 360 447 409
Sales for resale outside service area 415 505 613 797
- - - - - - - ---------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 8,417 8,014 8,337 7,979
Southern Energy 643 185 54 -
Other revenues 120 98 98 94
- - - - - - - ---------------------------------------------------------------------------------------------------------------------
Total $9,180 $8,297 $8,489 $8,073
=====================================================================================================================
Kilowatt-Hour Sales (in millions):
Residential 39,147 35,836 36,807 33,627
Commercial 35,938 34,080 32,847 31,025
Industrial 51,644 50,311 48,738 47,816
Other 863 844 814 777
- - - - - - - ---------------------------------------------------------------------------------------------------------------------
Total retail 127,592 121,071 119,206 113,245
Sales for resale within service area 9,472 8,151 13,258 12,107
Sales for resale outside service area 9,143 10,769 12,445 16,632
- - - - - - - ---------------------------------------------------------------------------------------------------------------------
Total 146,207 139,991 144,909 141,984
=====================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 7.25 7.14 7.32 7.14
Commercial 6.91 6.92 7.04 7.03
Industrial 4.27 4.30 4.51 4.45
Total retail 5.96 5.90 6.10 5.98
Sales for resale 4.38 4.57 4.12 4.20
Total sales 5.76 5.72 5.75 5.62
Average Annual Kilowatt-Hour Use Per Residential Customer 12,722 11,851 12,378 11,490
Average Annual Revenue Per Residential Customer $922.83 $846.48 $906.60 $820.67
Plant Nameplate Capacity Owned (year-end) (megawatts) 30,733 29,932 29,513 29,830
Maximum Peak-Hour Demand (megawatts):
Winter 21,422 22,254 19,432 19,121
Summer 27,420 24,546 25,937 24,146
System Reserve Margin (at peak) (percent) 9.4 19.3 13.2 14.3
Annual Load Factor (percent) 59.5 63.5 59.4 60.3
Plant Availability (percent):
Fossil-steam 86.7 85.2 87.9 88.6
Nuclear 88.3 89.8 85.9 85.2
- - - - - - - ---------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 72.5 70.8 73.0 71.7
Nuclear 16.4 17.9 16.3 16.2
Hydro 4.1 4.7 3.9 4.6
Oil and gas 1.7 0.9 0.9 0.5
Purchased power 5.3 5.7 5.9 7.0
- - - - - - - ---------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0 100.0
=====================================================================================================================
Total Fuel Economy Data:
BTU per net kilowatt-hour generated 10,099 10,010 9,994 9,976
Cost of fuel per million BTU(cents) 151.70 155.81 166.85 162.58
Average cost of fuel per net kilowatt-hour generated (cents) 1.53 1.56 1.67 1.62
- - - - - - - ---------------------------------------------------------------------------------------------------------------------
11-48A
SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA 1988-1998
Southern Company and Subsidiary Companies 1998 Annual Report
1991 1990 1989 1988
- - - - - - - ------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in millions):
Residential $2,391 $2,342 $2,194 $2,103
Commercial 2,122 2,062 1,965 1,835
Industrial 2,088 2,085 2,011 1,945
Other 65 64 60 56
- - - - - - - ------------------------------------------------------------------------------------------------------------------------
Total retail 6,666 6,553 6,230 5,939
Sales for resale within service area 417 412 401 480
Sales for resale outside service area 884 977 928 777
- - - - - - - -------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 7,967 7,942 7,559 7,196
Southern Energy - - - -
Other revenues 83 111 61 91
- - - - - - - -------------------------------------------------------------------------------------------------------------------------
Total $8,050 $8,053 $7,620 $7,287
=========================================================================================================================
Kilowatt-Hour Sales (in millions):
Residential 33,622 33,118 31,627 31,041
Commercial 30,379 29,658 28,454 27,005
Industrial 46,050 45,974 45,022 43,675
Other 817 806 787 763
- - - - - - - ------------------------------------------------------------------------------------------------------------------------
Total retail 110,868 109,556 105,890 102,484
Sales for resale within service area 12,320 11,134 11,419 14,806
Sales for resale outside service area 19,839 24,402 24,228 15,860
- - - - - - - -------------------------------------------------------------------------------------------------------------------------
Total 143,027 145,092 141,537 133,150
=========================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 7.11 7.07 6.94 6.77
Commercial 6.99 6.96 6.91 6.79
Industrial 4.53 4.53 4.47 4.45
Total retail 6.01 5.98 5.88 5.80
Sales for resale 4.05 3.91 3.73 4.10
Total sales 5.57 5.47 5.34 5.40
Average Annual Kilowatt-Hour Use Per Residential Customer 11,659 11,637 11,287 11,255
Average Annual Revenue Per Residential Customer $829.18 $822.93 $782.90 $762.42
Plant Nameplate Capacity Owned (year-end) (megawatts) 29,915 29,532 29,532 27,552
Maximum Peak-Hour Demand (megawatts):
Winter 19,166 17,629 20,772 18,685
Summer 25,261 25,981 24,399 23,641
System Reserve Margin (at peak) (percent) 16.5 14.0 21.0 15.0
Annual Load Factor (percent) 58.3 56.6 58.6 59.8
Plant Availability (percent):
Fossil-steam 91.3 91.9 92.2 91.3
Nuclear 83.4 83.0 87.0 78.4
- - - - - - - ------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 72.6 72.1 71.5 77.7
Nuclear 16.2 15.6 15.7 14.5
Hydro 4.4 4.4 5.2 2.3
Oil and gas 0.6 1.3 1.1 0.7
Purchased power 6.2 6.6 6.5 4.8
- - - - - - - -------------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0 100.0
========================================================================================================================
Total Fuel Economy Data:
BTU per net kilowatt-hour generated 10,022 10,065 10,086 10,094
Cost of fuel per million BTU(cents) 168.28 172.81 171.00 170.36
Average cost of fuel per net kilowatt-hour generated (cents) 1.69 1.74 1.72 1.72
- - - - - - - ------------------------------------------------------------------------------------------------------------------------
11-48B
ALABAMA POWER COMPANY
FINANCIAL SECTION
II-49
MANAGEMENT'S REPORT
Alabama Power Company 1998 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,
Chief Financial Officer, and Treasurer
February 10, 1999
II-50
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Alabama Power Company:
We have audited the accompanying balance sheets and statements of capitalization
of Alabama Power Company (an Alabama corporation and a wholly owned subsidiary
of Southern Company) as of December 31, 1998 and 1997, 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, 1998. 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 ade by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements (pages II-61 through II-79)
referred to above present fairly, in all material respects, the financial
position of Alabama Power Company as of December 31, 1998 and 1997, and the
results of its operations and its cash flows for each of the three years in
the period ended December 31, 1998, in conformity with generally accepted
accounting principles.
/s/ Arthur Andersen LLP
Arthur Andersen LLP
Birmingham, Alabama
February 10, 1999
II-51
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Alabama Power Company 1998 Annual Report
RESULTS OF OPERATIONS
Earnings
Alabama Power Company's 1998 net income after dividends on preferred stock was
$377 million, representing a $1.3 million (0.3 percent) increase from the prior
year. This improvement can be attributed primarily to increased retail energy
sales as a result of hot weather in the second quarter of 1998, compared to very
mild weather for the same period in 1997 and a strong economy in the Company's
service territory. However, earnings were offset by an increase in non-fuel
operation and maintenance expenses and an increase in the amortization of debt
discount, premium, and expense, net pursuant to an Alabama Public Service
Commission (APSC) order. See Note 3 to the financial statements under "Retail
Rate Adjustment Procedures" for additional details.
In 1997, earnings were $376 million, representing a 1.2 percent increase
from the prior year. This increase was due to lower non-fuel related
operating expenses. Despite the mild weather experienced during 1997, retail
kilowatt-hour (KWH) sales increased approximately 2 percent. However,
the expected net income effect was offset by the effect of reductions in
certain industrial and commercial prices.
The return on average common equity for 1998 was 13.63 percent compared to
13.76 percent in 1997, and 13.75 percent in 1996.
Revenues
Operating revenues for 1998 were $3.4 billion, reflecting a 7.5 percent increase
from 1997. The following table summarizes the principal factors that affected
operating revenues for the past three years:
Increase (Decrease)
From Prior Year
-----------------------------------------
1998 1997 1996
-----------------------------------------
(in thousands)
Retail --
Growth and price
change $ 75,642 $ 33,813 $ 42,385
Weather 55,282 (22,973) (29,660)
Fuel cost recovery
and other 138,944 31,353 (30,846)
- - - - - - - -------------------------------------------------------------------
Total retail 269,868 42,193 (18,121)
------------------------------------------------------------------
Sales for resale --
Non-affiliates 17,950 39,354 21,529
Affiliates (58,233) (54,825) 88,890
------------------------------------------------------------------
Total sales for resale (40,283) (15,471) 110,419
Other operating
revenues 7,677 1,614 3,703
- - - - - - - -------------------------------------------------------------------
Total operating
revenues $237,262 $ 28,336 $ 96,001
----------------------------------------------------------------
Percent change 7.5% 0.9% 3.2%
===================================================================
Retail revenues of $2.8 billion in 1998 increased $270 million (10.7
percent) from the prior year, compared with an increase of $42 million
(1.7 percent) in 1997. The predominant factors causing the rise in revenues
in 1998 were the positive impact of weather on energy sales, continued
growth throughout the state, and increased fuel revenues. Fuel revenues were
higher in the current year due to higher fuel costs and an increase in purchased
power.
Retail revenues in 1997 increased $42 million (1.7 percent) over 1996. The
primary reason for this increase was an increase in fuel revenues due to
slightly higher generation and higher fuel costs in 1997 as compared to 1996.
Fuel revenues generally represent the direct recovery of fuel expense, including
the fuel component of purchased energy, and therefore have no effect on net
income.
II-52
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 1998 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 were:
1998 1997 1996
-------------------------------------------
(in thousands)
Capacity $141,814 $136,248 $150,797
Energy 118,252 134,498 107,996
------------------------------------------------------------
Total $260,066 $270,746 $258,793
=============================================================
Capacity revenues from non-affiliates increased 4.1 percent in 1998 compared
to the prior year. Capacity revenues from non-affiliates in 1997 decreased 9.6
percent compared to 1996 primarily due to a one-time unit power sales adjustment
in 1997.
Revenues from sales to affiliated companies within the Southern electric
system, as well as purchases of energy, will vary from year to year depending on
demand and the availability and cost of generating resources at each company.
These transactions do not have a significant impact on earnings.
KWH sales for 1998 and the percent change by year were as follows:
KWH Percent Change
-------------------------------------------
1998 1998 1997 1996
-------------------------------------------
(millions)
Residential 15,795 10.2% (1.8)% 1.5%
Commercial* 11,905 5.1 3.9 8.6
Industrial* 21,585 4.2 3.6 0.7
Other 196 8.3 (6.3) 3.1
-----------
Total retail 49,481 6.2 1.9 2.7
Sales for resale -
Non-affiliates 11,841 (3.2) 29.9 18.0
Affiliates 5,976 (33.5) (12.6) 53.5
-----------
Total 67,298 (0.9)% 3.7% 10.5%
==================================================================
*The KWH sales for 1996 reflect a reclassification of approximately 200
customers from industrial to commercial, which resulted in a shift of 473
million KWH. Absent the reclassification, the percentage change in KWH sales for
commercial and industrial would have been 3.9% and 3.1%, respectively.
The increases in 1998 and 1997 retail energy sales were primarily due to the
strength of business and economic conditions in the Company's service area. In
1998, residential energy sales experienced a 10.2 percent increase over the
prior year primarily as a result of hot weather in the second quarter, compared
to very mild weather in the second quarter of 1997. Assuming normal weather,
sales to retail customers are projected to grow approximately 2.3 percent
annually on average during 1999 through 2003.
Expenses
Total operating expenses of $2.7 billion for 1998 were up $207 million or 8.2
percent compared with 1997. This increase was mainly due to a $107 million
increase in purchased power expenses, accompanied by a $58 million increase in
maintenance expense.
Total operating expenses of $2.5 billion for 1997 were up $18 million or 0.7
percent compared with 1996. This increase was primarily due to a $19 million
increase in fuel costs and a $10 million increase in epreciation and
amortization expense. These increases were somewhat offset by a $16 million
decrease in maintenance 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 KWH generated were as follows:
--------------------------
1998 1997 1996
--------------------------
Total generation
(billions of KWHs) 63 65 65
Sources of generation
(percent) --
Coal 72 72 72
Nuclear 18 20 20
Hydro 8 8 8
Oil & Gas 2 * *
Average cost of fuel per net
KWH generated
(cents) -- 1.54 1.49 1.46
==============================================================
* Not meaningful because of minimal generation from fuel source.
II-53
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 1998 Annual Report
Total fuel and purchased power costs of $1.1 billion in 1998 increased $111
million (11 percent) over 1997 primarily due to lower levels of nuclear and
hydro generation, which were replaced by the use of peaking units and purchased
power.
Fuel and purchased power costs in 1997 increased $27 million (3 percent)
over 1996 due primarily to slightly higher generation and fuel costs in 1997.
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. Total KWH purchases increased 24.5 percent from the prior year.
The 23.8 percent increase in maintenance expense in 1998 as compared to 1997
is attributable to (i) an increase in the maintenance of overhead lines, (ii)
the write-off of obsolete steam and nuclear generating plant inventory, and
(iii) additional accruals to partially replenish the natural disaster reserve.
The 6.1 percent decrease in maintenance expenses in 1997 is attributable
primarily to a decrease in distribution expenses.
Depreciation and amortization expense increased 2.6 percent in 1998 and 3.2
percent in 1997. These increases reflect additions to utility plant.
Total net interest and other charges increased $55.7 million (22 percent) in
1998. This increase results primarily from an increase in the amortization of
debt discount, premium, and expense, net pursuant to an APSC order. See Note 3
to the financial statements under "Retail Rate Adjustment Procedures" for
additional details. Total net interest and other charges increased $25.4 million
(11.2 percent) in 1997 primarily due to an increase in company obligated
mandatorily redeemable preferred securities outstanding. This increase was
offset by a $12 million (45.2 percent) decrease in dividends on preferred stock.
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 utility plants with long economic life. 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 securities. Any
recognition of inflation by regulatory authorities is reflected in the rate of
return allowed.
Future Earnings Potential
The results of operations for the past three years are not necessarily
indicative of future earnings potential. The level of future earnings depends on
numerous factors ranging from energy sales growth to a less regulated more
competitive environment.
The Company currently operates as a vertically integrated utility providing
electricity to customers within its traditional service area located in the
state of Alabama. Prices for electricity provided by the Company to retail
customers are set by the APSC under cost-based regulatory principles.
Future earnings in the near term will depend upon growth in electric sales,
which are subject to a number of factors. Traditionally, these factors have
included weather, competition, changes in contracts with neighboring utilities,
energy conservation practiced by customers, the elasticity of demand, and the
rate of economic growth in the Company's service area.
The electric utility industry in the United States is currently undergoing a
period of dramatic change as a result of regulatory and competitive factors.
Among the primary agents of change has been the Energy Policy Act of 1992
(Energy Act). The Energy Act allows independent power producers (IPPs) to access
a utility's transmission network in order to sell electricity to other
utilities. This enhances the incentive for IPPs to build cogeneration plants for
a utility's large industrial and commercial customers and sell excess energy
generation to other utilities. Also, electricity sales for resale rates are
being driven down by wholesale transmission access and numerous potential new
energy suppliers, including power marketers and brokers. The Company is
aggressively working to maintain and expand its share of wholesale business in
the Southeastern power markets.
II-54
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 1998 Annual Report
Although the Energy Act does not permit retail customer access, it was a
major catalyst for the current restructuring and consolidation taking place
within the utility industry. Numerous federal and state initiatives are in
varying stages to promote wholesale and retail competition. Among other things,
these initiatives allow customers to choose their electricity provider. As these
initiatives materialize, the structure of the utility industry could radically
change. Some states have approved initiatives that result in a separation of the
ownership and/or operation of generating facilities from the ownership and/or
operation of transmission and distribution facilities. While various
restructuring and competition initiatives have been or are being discussed in
Alabama, Florida, Georgia, and Mississippi, none have been enacted to date.
Enactment would require numerous issues to be resolved, including significant
ones relating to transmission pricing and recovery of any stranded investments.
The inability of the Company to recover its investments, including the
regulatory assets described in Note 1 to the financial statements, could have a
material adverse effect on the financial condition of the Company. The Company
is attempting to minimize or reduce stranded cost exposure.
Continuing to be a low-cost producer could provide opportunities to increase
market share and profitability in markets that evolve with changing regulation.
Conversely, 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.
Rates to retail customers served by the Company are regulated by the APSC.
Rates for the Company can be adjusted periodically within certain limitations
based on earned retail rate of return compared with an allowed return. In June
1995, the APSC issued an order granting the Company's request for gradual
adjustments to move toward parity among customer classes. This order also calls
for a moratorium on any periodic retail rate increases (but not decreases) until
2001.
In December 1995, the APSC issued an order authorizing the Company to reduce
balance sheet items -- such as plant and deferred charges -- at any time the
Company's actual base rate revenues exceed the budgeted revenues. In April
1997, the APSC issued an additional order authorizing the Company to reduce
balance sheet asset items. This order authorizes the reduction of such items
up to an amount equal to five times the total estimated annual revenue
reduction resulting from future rate reductions initiated by the Company. See
Note 3 to the financial statements for information about this and other matters.
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 current and future environmental laws and
regulations could affect earnings if such costs are not fully recovered. The
Clean Air Act and other important environmental items are discussed later under
"Environmental Matters."
The 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 in the financial statements of decommissioning costs for nuclear
generating facilities. In response to these questions, the Financial Accounting
Standards Board (FASB) has decided to review the accounting for liabilities
related to the retirement of long-lived assets, including nuclear
decommissioning. If the FASB issues new accounting rules, the estimated costs of
retiring the Company's nuclear and other facilities may be required to be
recorded as liabilities in the Balance Sheets. Also, the annual provisions for
such costs could change. Because of the Company's current ability to recover
asset retirement costs through rates, these changes would not have a significant
adverse effect on results of operations. See Note 1 to the financial statements
under "Depreciation and Nuclear Decommissioning" for additional information.
The Company is subject to the provisions of FASB Statement No. 71,
Accounting for the Effects of Certain Types of Regulation. In the event that a
portion of the Company's operations is no longer subject to these provisions,
the Company would be required to write off related regulatory assets and
liabilities that are not specifically recoverable, and determine if any other
assets have been impaired. See Note 1 to the financial statements under
"Regulatory Assets and Liabilities" for additional information.
II-55
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 1998 Annual Report
Year 2000
Year 2000 Challenge
In order to save storage space, computer programmers in the 1960s and 1970s
shortened the year portion of date entries to just two digits. Computers
assumed, in effect, that all years began with "19." This practice was widely
adopted and hard-coded into computer chips and processors found in some
equipment. This approach, intended to save processing time and storage space,
was used until the mid-1990s. Unless corrected before the Year 2000, affected
software systems and devices containing a chip or microprocessor with date and
time functions could incorrectly process dates or the systems may cease to
function.
The Company depends on complex computer systems for many aspects of its
operations, which include generation, transmission, and distribution of
electricity, as well as other business support activities. The Company's goal is
to have critical devices or software that are required to maintain operations to
be Year 2000 ready by June 1999. Year 2000 ready means that a system or
application is determined suitable for continued use through the Year 2000 and
beyond. Critical systems include, but are not limited to, reactor control
systems, safe shutdown systems, turbine generator systems, control center
computer systems, customer service systems, energy management systems, and
telephone switches and equipment.
Year 2000 Program and Status
The Company's executive management recognizes the seriousness of the Year 2000
challenge and has dedicated what it believes to be adequate resources to address
the issue. The Millennium Project is a team of employees, IBM consultants, and
other contractors whose progress is reviewed on a monthly basis by a steering
committee of Southern Company executives.
The Company's Year 2000 program was divided into two phases. Phase I began
in 1996 and consisted of identifying and assessing corporate assets related to
software systems and devices that contain a computer chip or clock. The first
phase was completed in June 1997. Phase 2 consists of testing and remediating
high priority systems and devices. Also, contingency planning is included in
this phase. Completion of Phase 2 is targeted for June 1999. The Millennium
Project will continue to monitor the affected computer systems, devices, and
applications into the Year 2000.
The Southern Company has completed more than 70 percent of the activities
contained in its work plan. The percentage of completion and projected
completion by function are as follows:
- - - - - - - ------------------------------------------------------------------------------
Work Plan
------------------------------------------------------
Remediation Project
Inventory Assessment Testing Completion
- - - - - - - ------------------------------------------------------------------------------
Generation 100% 100% 70% 6/99
- - - - - - - ------------------------------------------------------------------------------
Energy Management 100 100 90 6/99
- - - - - - - ------------------------------------------------------------------------------
Transmission and
Distribution 100 100 100 1/99
- - - - - - - ------------------------------------------------------------------------------
Telecommunications 100 100 50 6/99
- - - - - - - ------------------------------------------------------------------------------
Corporate Applications 100 100 90 3/99
- - - - - - - ------------------------------------------------------------------------------
Year 2000 Costs
Current projected total costs for Year 2000 readiness, including the Company's
share of costs of Southern Nuclear Operating Company, are approximately $36
million. These costs include labor necessary to identify, test, and renovate
affected devices and systems. From its inception through December 31, 1998, the
Year 2000 program costs, recognized primarily as expense, amounted to $21
million.
Year 2000 Risks
The Company is implementing a detailed process to minimize the possibility of
service interruptions related to the Year 2000. The Company believes, based on
current tests, that the system can provide customers with electricity. These
tests increase confidence, but do not guarantee error-free operation. The
Company is taking what it believes to be prudent steps to prepare for the Year
2000, and it expects any interruptions in service that may occur within the
service territory to be isolated and short in duration.
The Company expects the risks associated with Year 2000 to be no more severe
than the scenarios that its electric system is routinely prepared to handle. The
most likely worst case scenario consists of the service loss of one of the
largest generating units and/or the service loss of any single bulk transmission
II-56
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 1998 Annual Report
element in its service territory. The Company has followed a proven methodology
for identifying and assessing software and devices containing potential
Year 2000 challenges. Remediation and testing of those devices are in
progress. Following risk assessment, the Company is preparing contingency
plans as appropriate and is participating in North American Electric
Reliability Council-coordinated national drills during 1999.
The Company is currently reviewing the Year 2000 readiness of material third
parties that provide goods and services crucial to the Company's operations.
Among such critical third parties are fuel, transportation, telecommunications,
water, chemical, and other suppliers. Contingency plans based on the assessment
of each third party's ability to continue supplying critical goods and services
to the Company are being developed.
There is a potential for some earnings erosion caused by reduced electrical
demand by customers because of their Year 2000 issues.
Year 2000 Contingency Plans
Because of experience with hurricanes and other storms, the Company is skilled
at developing and using contingency plans in unusual circumstances. As part of
Year 2000 business continuity and contingency planning, the Company is drawing
on that experience to make risk assessments and is developing additional plans
to deal specifically with situations that could arise relative to Year 2000
challenges. The Company is identifying critical operational locations, and key
employees will be on duty at those locations during the Year 2000 transition. In
September 1999, drills are scheduled to be conducted to test contingency plans.
Because of the level of detail of the contingency planning process, management
feels that the contingency plans will keep any service interruptions that may
occur within the service territory isolated and short in duration.
Exposure to Market Risk
Due to cost-based rate regulation, the Company has limited exposure to market
volatility in interest rates and prices of electricity. To mitigate residual
risks relative to movements in electricity prices, the Company enters into fixed
price contracts for the purchase and sale of electricity through the wholesale
electricity market. Realized gains and losses are recognized in the income
statement as incurred. At December 31, 1998, exposure from these activities was
not material to the Company's financial position, results of operations, or cash
flows. Also, based on the Company's overall interest rate exposure at December
31, 1998, a near-term 100 basis point change in interest rates would not
materially affect the financial statements.
New Accounting Standards
The FASB has issued Statement No. 133, Accounting for Derivative Instruments and
Hedging Activities, which must be adopted by the year 2000. This statement
establishes accounting and reporting standards for derivative instruments -
including certain derivative instruments embedded in other contracts - and for
hedging activities. The Company has not yet quantified the impact of adopting
this statement on its financial statements; however, the adoption could increase
volatility in earnings.
In March 1998, the American Institute of Certified Public Accountants (AICPA)
issued a new Statement of Position, Accounting for the Costs of Computer
Software Developed or Obtained for Internal Use. This statement requires
capitalization of certain costs of internal-use software. The Company adopted
this statement in January 1999, and it is not expected to have a material impact
on the financial statements.
In April 1998, the AICPA issued a new Statement of Position, Reporting on the
Costs of Start-up Activities. This statement requires that the costs of start-up
activities and organizational costs be expensed as incurred. Any of these costs
previously capitalized by a company must be written off in the year of adoption.
The Company adopted this statement in January 1999, and it is not expected to
have a material impact on the financial statements.
In December 1998, the Emerging Issues Task Force (EITF) of the FASB issued
EITF No. 98-10, Accounting for Contracts Involved in Energy Trading and Risk
Management Activities. The EITF requires that energy trading contracts must be
marked to market through the income statement, with gains and losses reflected
rather than revenues and purchased power. Energy trading contracts are defined
as energy contracts entered into with the objective of generating profits on or
from exposure to
II-57
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 1998 Annual Report
shifts or changes in market prices. The Company adopted the required accounting
in January 1999, and it is not expected to have a material impact on the
financial statements.
FINANCIAL CONDITION
Overview
The Company's financial condition remained stable in 1998. This stability is the
continuation over recent years of growth in retail 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 $610 million in 1998. The
majority of funds needed for gross property additions for the last several years
has been provided from operating activities, principally from earnings and
non-cash charges to income such as depreciation and deferred income taxes. The
Statements of Cash Flows provide additional details.
Capital Structure
The Company's ratio of common equity to total capitalization -- including
short-term debt -- was 42.4 percent in 1998, compared with 44.7 percent in 1997,
and 45.3 percent in 1996.
During 1998, the Company issued $1.4 billion of senior notes, the proceeds
of which were used primarily to redeem first mortgage bonds and repay short-term
indebtedness. Additionally in 1998, the Company redeemed $8 million of
preferred stock and issued an additional $200 million.
Capital Requirements
Capital expenditures are estimated to be $875 million for 1999, $653 million for
2000, and $668 million for 2001. The total is $2.2 billion for the three years.
Included in these estimates are the following: the Company will replace all six
steam generators at Plant Farley at a total cost of approximately $234 million.
Additionally, the Company plans to construct and install 1,075 megawatts of new
generating capacity and associated substation facilities at Plant Barry. The
projected capital expenditures for this project amount to approximately $384
million.
Actual capital costs may vary from estimates because of factors such as
changes in business conditions; revised load growth projections; changes in
environmental regulations; changes in the existing nuclear plant to meet new
regulatory requirements; increasing costs of labor, equipment, and materials;
and cost of capital. In addition, there can be no assurance that costs related
to capital expenditures will be fully recovered.
Other Capital Requirements
In addition to the funds needed for the capital budget, approximately $270
million will be required by the end of 2000 for maturities of first mortgage
bonds. Also, the Company will continue to retire higher-cost debt and preferred
stock and replace these obligations with lower-cost capital if market conditions
permit.
Environmental Matters
In November 1990, the Clean Air Act was signed into law. Title IV of the Clean
Air Act -- the acid rain compliance provision of the law - significantly
impacted the operating companies of Southern Company, including Alabama Power.
Specific reductions in sulfur dioxide and nitrogen oxide emissions from
fossil-fired generating plants are required in two phases. Phase I compliance
began in 1995 and initially affected 28 generating units of Southern Company. As
a result of Southern Company's compliance strategy, an additional 22 generating
units were brought into compliance with Phase I requirements. Phase II
compliance is required in 2000, and all fossil-fired generating plants will be
affected.
Southern Company achieved Phase I sulfur dioxide compliance at the affected
plants by switching to low-sulfur coal, which required some equipment upgrades.
Construction expenditures for Phase I compliance totaled approximately $25
million for the Company.
For Phase II sulfur dioxide compliance, the Company could use emission
allowances, increase fuel switching, and/or install flue gas
desulfurization equipment at selected plants. Also equipment to
control nitrogen oxide emissions will be installed on additional system
fossil-fired units as necessary to meet Phase II limits. Current
II-58
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 1998 Annual Report
compliance strategy for Phase II could require total estimated construction
expenditures of approximately $38 million, of which $19 million remains to be
spent.
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.
In July 1997, the Environmental Protection Agency (EPA) revised the national
ambient air quality standards for ozone and particulate matter. This revision
makes the standards significantly more stringent. In September 1998, the EPA
issued the final regional nitrogen oxide rules to the states for implementation.
The states have one year to adopt and implement the new rules. The final rules
affect 22 states including Alabama. The EPA rules are being challenged in the
courts by several states and industry groups. Implementation of the final state
rules could require substantial further reductions in nitrogen oxide emissions
from fossil-fired generating facilities and other industry in these states.
Implementation of the standards could result in significant additional
compliance costs and capital expenditures that cannot be determined until the
results of legal challenges are known and the states have adopted their final
rules.
The EPA and state environmental regulatory agencies are reviewing and
evaluating various other matters including: nitrogen oxide emission control
strategies for ozone nonattainment areas; additional controls for hazardous air
pollutant emissions; control strategies to reduce regional haze; and hazardous
waste disposal requirements. The impact of new standards will depend on the
development and implementation of applicable regulations.
The Company must comply with other environmental laws and regulations that
cover the handling and disposal of hazardous waste. Under these various laws and
regulations, the Company could incur costs to clean up properties. The Company
conducts studies to determine the extent of any required cleanup costs and has
recognized in the financial statements costs to clean up known sites.
Several major pieces of environmental legislation are being considered for
reauthorization or amendment by Congress. These include: the Clean Air Act;
the Clean Water Act; the Comprehensive Environmental Response, Compensation,
and Liability Act; the Resource Conservation and Recovery Act; the Toxic
Substances Control Act; and the Endangered Species Act. Changes to these laws
could affect many areas of the Company's operations. The full impact of any
such changes cannot be determined at this time.
Compliance with possible additional legislation related to global climate
change, electromagnetic fields, and other environmental and health concerns
could significantly affect Southern Company. The impact of new legislation -- if
any -- will depend on the subsequent development and implementation of
applicable regulations. In addition, the potential exists for liability as the
result of lawsuits alleging damages caused by electromagnetic fields.
Sources of Capital
The Company historically has relied on issuances of first mortgage bonds and
preferred stock, in addition to pollution control revenue bonds issued for its
benefit by public authorities, to meet its long-term external financing
requirements. Recently, the Company's financings have consisted of unsecured
debt and trust preferred securities. In this regard, the Company sought and
obtained stockholder approval in 1997 to amend its corporate charter eliminating
restrictions on the amounts of unsecured indebtedness it may incur. To issue
additional debt and equity securities, the Company must comply with certain
earnings coverage requirements designated in its mortgage indenture and
corporate charter. The Company's coverages are at a level that would permit any
necessary amount of security sales at current interest and dividend rates.
As required by the Nuclear Regulatory Commission and as ordered by the APSC,
the Company has established external trust funds for nuclear decommissioning
costs. In 1994, the Company also established an external trust fund for
postretirement benefits as ordered by the APSC. The cumulative effect of funding
these items over a long period will diminish internally funded capital and may
require capital from other sources. For additional information concerning
nuclear decommissioning costs, see Note 1 to the financial statements under
"Depreciation and Nuclear Decommissioning."
II-59
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 1998 Annual Report
Cautionary Statement Regarding Forward-Looking Information
The Company's 1998 Annual Report contains forward-looking and historical
information. The Company cautions that there are various important factors that
could cause actual results to differ materially from those indicated in the
forward-looking information; accordingly, there can be no assurance that such
indicated results will be realized. These factors include legislative and
regulatory initiatives regarding deregulation and restructuring of the electric
utility industry; the extent and timing of the entry of additional competition
in the Company's markets; potential business strategies -- including
acquisitions or dispositions of assets or internal restructuring -- that may be
pursued by Southern Company; state and federal rate regulation; Year 2000
issues; changes in or application of environmental and other laws and
regulations to which the Company is subject; political, legal and economic
conditions and developments; financial market conditions and the results of
financing efforts; changes in commodity prices and interest rates; weather and
other natural phenomena; and other factors discussed in the reports--including
Form 10-K--filed from time to time by the Company with the Securities and
Exchange Commission.
II-60
STATEMENTS OF INCOME
For the Years Ended December 31, 1998, 1997, and 1996
Alabama Power Company 1998 Annual Report
================================================================================================================================
1998 1997 1996
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Revenues:
Revenues (Notes 1, 3, and 7) $ 3,282,811 $ 2,987,316 $ 2,904,155
Revenues from affiliates 103,562 161,795 216,620
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Total operating revenues 3,386,373 3,149,111 3,120,775
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
Fuel 900,309 896,014 877,076
Purchased power from non-affiliates 92,998 41,795 36,813
Purchased power from affiliates 150,897 95,538 91,500
Other 527,954 510,203 505,884
Maintenance 300,383 242,691 258,482
Depreciation and amortization 338,822 330,377 320,102
Taxes other than income taxes 193,049 185,062 186,172
Federal and state income taxes (Note 8) 224,922 220,228 228,108
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Total operating expenses 2,729,334 2,521,908 2,504,137
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Operating Income 657,039 627,203 616,638
Other Income (Expense):
Allowance for equity funds used during construction (Note 1) 3,811 - -
Equity in earnings of subsidiaries (Note 6) 5,271 5,250 4,676
Charitable foundation - - (6,800)
Interest income 68,553 37,844 28,318
Other, net (40,861) (39,506) (39,878)
Income taxes applicable to other income 6,347 12,351 22,400
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Income Before Interest Charges and Other 700,160 643,142 625,354
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Interest Charges and Other:
Interest on long-term debt 192,426 167,172 169,390
Allowance for debt funds used during construction (Note 1) (4,664) (4,787) (6,480)
Interest on interim obligations 11,012 22,787 20,617
Amortization of debt discount, premium, and expense, net (Note 3) 42,494 9,645 9,508
Other interest charges 44,672 36,037 27,510
Distributions on preferred securities of
Alabama Power Capital Trust I & II (Note 9) 22,354 21,763 6,717
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Interest charges and other, net 308,294 252,617 227,262
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Net Income 391,866 390,525 398,092
Dividends on Preferred Stock 14,643 14,586 26,602
-------------------------------------------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred Stock $ 377,223 $ 375,939 $ 371,490
================================================================================================================================
The accompanying notes are an integral part of these statements.
II-61
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1998, 1997, and 1996
Alabama Power Company 1998 Annual Report
===============================================================================================================================
1998 1997 1996
- - - - - - - -------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Activities:
Net income $ 391,866 $ 390,525 $ 398,092
Adjustments to reconcile net income to net
cash provided from operating activities--
Depreciation and amortization 425,167 394,572 383,438
Deferred income taxes and investment tax credits, net 79,430 (12,429) 16,585
Allowance for equity funds used during construction (3,811) - -
Other, net (62,928) (11,353) 6,247
Changes in certain current assets and liabilities --
Receivables, net 49,747 (30,268) 3,958
Inventories 2,880 13,709 36,234
Payables 26,583 (9,745) 1,006
Taxes accrued 4,570 6,191 (5,756)
Energy cost recovery, retail (95,427) 7,108 25,771
Other (14,373) 7,127 8,205
- - - - - - - -------------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities 803,704 755,437 873,780
- - - - - - - -------------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (610,132) (451,167) (425,024)
Other (52,940) (51,791) (61,119)
- - - - - - - -------------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities (663,072) (502,958) (486,143)
- - - - - - - -------------------------------------------------------------------------------------------------------------------------------
Financing Activities:
Proceeds:
Company obligated mandatorily redeemable preferred securities - 200,000 97,000
Capital contributions 30,000 - -
Preferred stock 200,000 - -
Other long-term debt 1,462,990 258,800 21,000
Retirements:
Preferred stock (88,000) (184,888) -
First mortgage bonds (771,108) (74,951) (83,797)
Other long-term debt (107,776) (951) (21,907)
Interim obligations, net (306,882) (57,971) (25,163)
Payment of preferred stock dividends (15,596) (22,524) (26,665)
Payment of common stock dividends (367,100) (339,600) (347,500)
Miscellaneous (66,869) (16,024) (3,634)
- - - - - - - -------------------------------------------------------------------------------------------------------------------------------
Net cash used for financing activities (30,341) (238,109) (390,666)
- - - - - - - -------------------------------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents 110,291 14,370 (3,029)
Cash and Cash Equivalents at Beginning of Year 23,957 9,587 12,616
- - - - - - - -------------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 134,248 $ 23,957 $ 9,587
===============================================================================================================================
Supplemental Cash Flow Information:
Cash paid during the year for --
Interest (net of amount capitalized) $ 234,360 $ 209,919 $ 193,871
Income taxes (net of refunds) 188,942 207,653 195,214
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
( ) Denotes use of cash.
The accompanying notes are an integral part of these statements.
II-62
BALANCE SHEETS
At December 31, 1998 and 1997
Alabama Power Company 1998 Annual Report
================================================================================================================================
ASSETS 1998 1997
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Utility Plant:
Plant in service, at original cost (Note 1) $11,352,838 $11,070,323
Less accumulated provision for depreciation 4,666,513 4,384,180
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
6,686,325 6,686,143
Nuclear fuel, at amortized cost 95,575 103,272
Construction work in progress 525,359 311,223
-------------------------------------------------------------------------------------------------------------------------------
Total 7,307,259 7,100,638
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Other Property and Investments:
Equity investments in subsidiaries (Note 6) 34,298 34,373
Nuclear decommissioning trusts, at market (Note 1) 232,183 193,008
Miscellaneous 12,915 12,832
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Total 279,396 240,213
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Current Assets:
Cash and cash equivalents 134,248 23,957
Receivables-
Customer accounts receivable 343,630 368,255
Other accounts and notes receivable 32,394 28,921
Affiliated companies 39,981 50,353
Accumulated provision for uncollectible accounts (1,855) (2,272)
Refundable income taxes 52,117 -
Fossil fuel stock, at average cost 83,238 74,186
Materials and supplies, at average cost 149,669 161,601
Prepayments 17,160 20,453
Vacation pay deferred 28,390 28,783
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Total 878,972 754,237
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets:
Deferred charges related to income taxes (Note 8) 362,953 384,549
Debt expense, being amortized 8,602 7,276
Premium on reacquired debt, being amortized 83,440 81,417
Prepaid pension costs 169,393 130,733
Department of Energy assessments (Note 1) 31,088 34,416
Miscellaneous 104,595 79,388
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Total 760,071 717,779
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Total Assets $9,225,698 $8,812,867
================================================================================================================================
The accompanying notes are an integral part of these balance sheets.
II-63
BALANCE SHEETS
At December 31, 1998 and 1997
Alabama Power Company 1998 Annual Report
================================================================================================================================
CAPITALIZATION AND LIABILITIES 1998 1997
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Capitalization (See accompanying statements):
Common stock equity $2,784,067 $2,750,569
Preferred stock 317,512 255,512
Company obligated mandatorily redeemable preferred securities of
subsidiary trusts holding Company Junior Subordinated Notes (Note 9) 297,000 297,000
Long-term debt 2,646,566 2,473,202
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Total 6,045,145 5,776,283
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Current Liabilities:
Preferred stock due within one year (Note 11) 50,000 -
Long-term debt due within one year (Note 11) 471,209 75,336
Commercial paper - 306,882
Accounts payable-
Affiliated companies 79,844 79,822
Other 188,074 159,146
Customer deposits 29,235 34,968
Taxes accrued-
Federal and state income 82,219 21,177
Other 17,559 15,309
Interest accrued 38,166 50,722
Vacation pay accrued 28,390 28,783
Miscellaneous 79,095 103,602
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Total 1,063,791 875,747
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes (Note 8) 1,202,971 1,192,265
Accumulated deferred investment tax credits 271,611 282,873
Prepaid capacity revenues, net (Note 7) 96,080 109,982
Department of Energy assessments (Note 1) 27,202 30,592
Deferred credits related to income taxes (Note 8) 315,735 327,328
Natural disaster reserve (Note 1) 19,385 22,416
Miscellaneous 183,778 195,381
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Total 2,116,762 2,160,837
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Commitments and Contingent Matters (Notes 1 through 7, and 12)
Total Capitalization and Liabilities $9,225,698 $8,812,867
=================================================================================================================================
The accompanying notes are an integral part of these balance sheets.
II-64
STATEMENTS OF CAPITALIZATION
At December 31, 1998 and 1997
Alabama Power Company 1998 Annual Report
====================================================================================================================================
1998 1997 1998 1997
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------------
(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 1998 and 1997 $ 224,358 $ 224,358
Paid-in capital 1,334,645 1,304,645
Premium on preferred stock 99 99
Retained earnings (Note 13) 1,224,965 1,221,467
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------------
Total common stock equity 2,784,067 2,750,569 46.1 % 47.6 %
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------------
Cumulative Preferred Stock:
$1 par value --
Authorized -- 27,500,000 shares
Outstanding -- 1998: 10,500,200 shares
-- 1997: 6,020,200 shares
$25 stated capital --
5.20% 162,000 -
5.83% 38,000 -
6.40% - 50,000
6.80% - 38,000
Adjustable rate
4.00% - at January 1, 1999 50,000 50,000
$100 stated capital --
Auction rate - 4.30% at January 1, 1999 50,000 50,000
$100,000 stated capital --
Auction rate - 4.08% at January 1, 1999 20,000 20,000
$100 par value --
Authorized -- 3,850,000 shares
Outstanding -- 475,115 shares in 1998 and 1997
4.20% to 4.52% 18,512 18,512
4.60% to 4.92% 29,000 29,000
- - - - - - - -------------------------------------------------------------------------------------------------------------
Total cumulative preferred stock (annual dividend
requirement -- $17,767,000) 367,512 255,512
Less amount due within one year (Note 11) 50,000 -
- - - - - - - ----------------------------------------------------------------------------------------------------------------------------------
Cumulative preferred stock excluding amount due within one year 317,512 255,512 5.2 4.4
- - - - - - - ----------------------------------------------------------------------------------------------------------------------------------
Company Obligated Mandatorily
Redeemable Preferred Securities (Note 9):
$25 liquidation value -- 7.375% 97,000 97,000
$25 liquidation value -- 7.60% 200,000 200,000
- - - - - - - ----------------------------------------------------------------------------------------------------------------------------------
Total (annual distribution requirement -- $22,354,000) 297,000 297,000 4.9 5.2
- - - - - - - ----------------------------------------------------------------------------------------------------------------------------------
Long-Term Debt:
First mortgage bonds --
Maturity Interest Rates
February 1, 1998 5 1/2% - 50,000
August 1, 1999 6 3/8% 170,000 170,000
March 1, 2000 6% 100,000 100,000
August 1, 2002 6.85% - 100,000
January 1, 2003 7% 125,000 125,000
February 1, 2003 6 3/4% 175,000 175,000
August 1, 2007 7 1/4% - 175,000
2023 through 2024 7.30% to 9% 500,000 946,108
- - - - - - - -------------------------------------------------------------------------------------------------------------
Total first mortgage bonds 1,070,000 1,841,108
- - - - - - - -------------------------------------------------------------------------------------------------------------
Other long-term debt (Note 10) --
Pollution control obligations --
Collateralized -
5.5% to 6.5% due
2023-2024 126,050 223,040
Variable rates (3.80%
to 5.00% at 1/1/99)
due 2015-2017 89,800 89,800
II-65
STATEMENTS OF CAPITALIZATION (continued)
At December 31, 1998 and 1997
Alabama Power Company 1998 Annual Report
====================================================================================================================================
1998 1997 1998 1997
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
Pollution control obligations -- (continued)
Non-collateralized -
7.25% due 2003 1,000 1,000
5.8% due 2022 - 9,800
Variable rates (4.80%
to 5.33% at 1/1/99)
due 2021-2028 324,290 217,500
- - - - - - - -------------------------------------------------------------------------------------------------------------
Total pollution control obligations 541,140 541,140
- - - - - - - -------------------------------------------------------------------------------------------------------------
Senior notes --
Maturity Interest Rates
-------- --------------
November 15, 2003 5.35% 156,200 -
November 1, 2005 5.49% 225,000 -
October 1, 2008 5 3/8% 160,000 -
September 30, 2010 6.25% 100,000 -
September 30, 2018 6.375% 100,000 -
September 30, 2018 6.5% 225,000 -
December 1, 2047 7 1/8% 193,800 193,800
December 31, 2047 7% 200,000 -
March 31, 2048 7% 190,000 -
- - - - - - - -------------------------------------------------------------------------------------------------------------
Total senior notes 1,550,000 193,800
- - - - - - - -------------------------------------------------------------------------------------------------------------
Capitalized lease obligations 6,119 7,105
Unamortized debt premium (discount), net (49,484) (34,615)
- - - - - - - -------------------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
requirement -- $204,003,000) 3,117,775 2,548,538
Less amount due within one year (Note 11) 471,209 75,336
- - - - - - - ----------------------------------------------------------------------------------------------------------------------------------
Long-term debt excluding amount due within one year 2,646,566 2,473,202 43.8 42.8
- - - - - - - ----------------------------------------------------------------------------------------------------------------------------------
Total Capitalization $ 6,045,145 $ 5,776,283 100.0 % 100.0 %
==================================================================================================================================
The accompanying notes are an integral part of these statements.
II-66
STATEMENTS OF RETAINED EARNINGS
For the Years Ended December 31, 1998, 1997, and 1996
Alabama Power Company 1998 Annual Report
================================================================================================================================
1998 1997 1996
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Balance at Beginning of Year $ 1,221,467 $ 1,185,128 $ 1,161,225
Net income after dividends on preferred stock 377,223 375,939 371,490
Cash dividends on common stock (367,100) (339,600) (347,500)
Preferred stock transactions, net (6,137) (45) (7)
Other adjustments to retained earnings (488) 45 (80)
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Balance at End of Year (Note 13) $ 1,224,965 $ 1,221,467 $ 1,185,128
================================================================================================================================
STATEMENTS OF PAID-IN CAPITAL
For the Years Ended December 31, 1998, 1997, and 1996
Alabama Power Company 1998 Annual Report
===============================================================================================================================-
1998 1997 1996
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Balance at Beginning of Period $ 1,304,645 $ 1,304,645 $ 1,304,645
Capital contributions from parent company 30,000 - -
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Balance at End of Period $ 1,334,645 $ 1,304,645 $ 1,304,645
================================================================================================================================
The accompanying notes are an integral part of these statements.
II-67
NOTES TO FINANCIAL STATEMENTS
Alabama Power Company 1998 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING
POLICIES
General
Alabama Power Company (the Company) is a wholly owned subsidiary of Southern
Company, which is the parent company of five operating companies, Southern
Company Services (SCS), a system service company, Southern Communications
Services (Southern LINC), Southern Energy, Inc. (Southern Energy), Southern
Nuclear Operating Company (Southern Nuclear), Southern Company Energy Solutions,
and other direct and indirect subsidiaries. The operating companies (Alabama
Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power
Company, and Savannah Electric and Power Company) provide electric service in
four southeastern states. Contracts among the companies--dealing with
jointly-owned generating facilities, interconnecting transmission lines, and the
exchange of electric power--are regulated by the Federal Energy Regulatory
Commission (FERC) or the Securities and Exchange Commission (SEC). The system
service company provides, at cost, specialized services to Southern Company and
subsidiary companies. Southern LINC provides digital wireless communications
services to the operating companies and also markets these services to the
public within the Southeast. Southern Energy designs, builds, owns and operates
power production and delivery facilities and provides a broad range of energy
related services in the United States and international markets. Southern
Nuclear provides services to Southern Company's nuclear power plants. Southern
Company Energy Solutions develops new business opportunities related to energy
products and services.
Southern Company is registered as a holding company under the Public Utility
Holding Company Act of 1935 (PUHCA). Both Southern Company and its subsidiaries
are subject to the regulatory provisions of the PUHCA. The Company is also
subject to regulation by the FERC and the Alabama Public Service Commission
(APSC). The Company follows generally accepted accounting principles (GAAP) and
complies with the accounting policies and practices prescribed by the respective
regulatory commissions. The preparation of financial statements in conformity
with GAAP requires the use of estimates, and the actual results may differ from
those estimates.
Certain prior years' data presented in the financial statements have
been reclassified to conform with current year presentation.
Regulatory Assets and Liabilities
The Company is subject to the provisions of Financial Accounting Standards Board
(FASB) Statement No. 71, Accounting for the Effects of Certain Types of
Regulation. Regulatory assets represent probable future revenues to the Company
associated with certain costs that are expected to be recovered from customers
through the ratemaking process. Regulatory liabilities represent probable future
reductions in revenues associated with amounts that are expected to be credited
to customers through the ratemaking process. Regulatory assets and (liabilities)
reflected in the Balance Sheets at December 31 relate to the following:
1998 1997
-----------------------
(in thousands)
Deferred income taxes $ 362,953 $ 384,549
Deferred income tax credits (315,735) (327,328)
Premium on reacquired debt 83,440 81,417
Department of Energy assessments 31,088 34,416
Vacation pay 28,390 28,783
Natural disaster reserve (19,385) (22,416)
Work force reduction costs 4,082 19,316
Other, net 46,672 59,726
- - - - - - - ----------------------------------------------------------------
Total $ 221,505 $ 258,463
================================================================
In the event that a portion of the Company's operations is no longer subject
to the provisions of Statemen No. 71, the Company would be required to write
off related net regulatory assets and liabilities that are not specifically
recoverable through regulated rates. In addition, the Company would be required
to determine if any impairment to other assets exists, including plant, and
write down the assets, if impaired, to their fair value.
II-68
NOTES (continued)
Alabama Power Company 1998 Annual Report
Revenues and Fuel Costs
The Company currently operates as a vertically integrated utility providing
electricity to retail customers within its traditional service area located
within the state of Alabama, and to wholesale customers in the southeast.
Revenues by type of service were as follows:
1998 1997 1996
--------------------------------
(in millions)
Retail $2,781 $2,511 $2,469
Non-affiliated wholesale 449 431 391
Other 53 45 44
- - - - - - - ---------------------------------------------------------------
Total $3,283 $2,987 $2,904
- - - - - - - ---------------------------------------------------------------
The Company accrues revenues for services rendered but unbilled at the end of
each fiscal period. Fuel costs are expensed as the fuel is used. The Company's
electric rates include provisions to adjust billings for fluctuations in fuel
and the energy component of purchased power costs. Revenues are adjusted for
differences between recoverable fuel costs and amounts actually recovered in
current rates.
The Company has a diversified base of customers. No single customer or
industry comprises 10 percent or more of revenues. For all periods presented,
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 $59
million in 1998, $68 million in 1997, and $64 million in 1996. The Company has a
contract with the U.S. Department of Energy (DOE) that provides for the
permanent disposal of spent nuclear fuel. The DOE failed to begin disposing of
spent fuel in January 1998 as required by contracts, and the Company is pursuing
legal remedies against the government for breach of contract. Sufficient storage
capacity currently is available to permit operation into 2009 and 2013 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, 1998, under this law
to be approximately $31 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 1998 and 3.3 percent in both 1997 and 1996. When property subject
to depreciation is retired or otherwise disposed of in the normal course of
business, its cost -- together with the cost of removal, less salvage -- is
charged to the accumulated provision for depreciation. Minor items of property
included in the original cost of the plant are retired when the related property
unit is retired. Depreciation expense includes an amount for the expected cost
of decommissioning nuclear facilities and removal of other facilities.
Nuclear Regulatory Commission (NRC) regulations require 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 periods approved by the APSC. The NRC's minimum external
funding requirements are based on a generic estimate of the cost to decommission
the radioactive portions of a nuclear unit based on the size and type of
reactor. The Company has filed plans with the NRC to ensure that -- over time --
the deposits and earnings of the external trust funds will provide the minimum
funding amounts prescribed by the NRC.
II-69
NOTES (continued)
Alabama Power Company 1998 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, 1998, for Plant Farley were as
follows:
Site study basis (year) 1998
Decommissioning periods:
Beginning year 2017
Completion year 2031
-------------------------------------------------------------
(in millions)
Site study costs:
Radiated structures $ 629
Non-radiated structures 60
--------------------------------------------------------------
Total $ 689
=============================================================
(in millions)
Ultimate costs:
Radiated structures $1,868
Non-radiated structures 178
-------------------------------------------------------------
Total $2,046
=============================================================
The decommissioning cost estimates are based on prompt dismantlement and
removal of the plant from service. The actual decommissioning costs may vary
from the above estimates because of changes in the assumed date of
decommissioning, changes in NRC requirements, or changes in the assumptions used
in making estimates.
Annual provisions for nuclear decommissioning are based on an annuity method
as approved by the APSC. The amounts expensed in 1998 and fund balance as of
December 31, 1998 were:
(in millions)
Amount expensed in 1998 $ 18
-------------------------------------------------------------
Accumulated provisions:
Balance in external trust funds $ 232
Balance in internal reserves 42
-------------------------------------------------------------
Total $ 274
=============================================================
All of the Company's decommissioning costs are approved for ratemaking.
Significant assumptions include an estimated inflation rate of 4.5 percent and
an estimated trust earnings rate of 7.0 percent.
Income Taxes
The Company uses the liability method of accounting for deferred income taxes
and provides deferred income taxes for all significant income tax temporary
differences. Investment tax credits utilized are deferred and amortized to
income over the average lives of the related property.
Allowance For Funds Used During Construction (AFUDC)
AFUDC represents the estimated debt and equity costs of capital funds that are
necessary to finance the construction of new facilities. While cash is not
realized currently from such allowance, it increases the revenue requirement
over the service life of the plant through a higher rate base and higher
depreciation expense. The composite rate used to determine the amount of
allowance was 9.0 percent in 1998 and 5.8 percent in both 1997 and 1996. AFUDC,
net of income tax, as a percent of net income after dividends on preferred stock
was 1.8 percent in 1998, 0.8 percent in 1997 and 1.1 percent in 1996.
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
The Company's only financial instruments for which the carrying amount did not
approximate fair value at December 31 are as follows:
Carrying Fair
Amount Value
-------------------------
(in millions)
Long-term debt:
At December 31, 1998 $3,112 $3,195
At December 31, 1997 2,541 2,638
Preferred Securities:
At December 31, 1998 297 307
At December 31, 1997 297 300
--------------------------------------------------------------
II-70
NOTES (continued)
Alabama Power Company 1998 Annual Report
The fair value for long-term debt and preferred securities was based on
either closing market prices or closing prices of comparable instruments.
Cash and Cash Equivalents
For purposes of the financial statements, temporary cash investments are
considered cash equivalents. Temporary cash investments are securities with
original maturities of 90 days or less.
Materials and Supplies
Generally, materials and supplies include the cost of transmission,
distribution, and generating plant materials. Materials are charged to inventory
when purchased and then expensed or capitalized to plant, as appropriate, when
installed.
Natural Disaster Reserve
In September 1994, in response to a request by the Company, the APSC issued an
order allowing the Company to establish a Natural Disaster Reserve. Regulatory
treatment allows the Company to accrue $250 thousand per month, until the
maximum accumulated provision of $32 million is attained. However, in December
1995, the APSC approved higher accruals to restore the reserve to its authorized
level whenever the balance in the reserve declines below $22.4 million.
2. RETIREMENT BENEFITS
The Company has defined benefit, trusteed, pension plans that cover
substantially all employees. The Company provides certain medical care and life
insurance benefits for retired employees. Substantially all these employees may
become eligiblefor such benefits when they retire. The Company funds trusts to
the extent deductible under federal income tax regulations or to the extent
required by the APSC and FERC. In 1998, the Company adopted FASB Statement No.
132, Employers' Disclosure about Pensions and Other Postretirement Benefits. The
measurement date is September 30 of each year.
The weighted average rates assumed in the actuarial calculations for both
the pension and postretirement benefit plans were:
1998 1997
- - - - - - - ---------------------------------------------------------------
Discount 6.75% 7.50%
Annual salary increase 4.25 5.00
Long-term return on plan assets 8.50 8.50
- - - - - - - ---------------------------------------------------------------
Pension Plan
Changes during the year in the projected benefit obligations and in the fair
value of plan assets were as follows:
Projected
Benefit Obligations
---------------------------
1998 1997
- - - - - - - ---------------------------------------------------------------
(in millions)
Balance at beginning of year $813 $814
Service cost 22 20
Interest cost 59 58
Benefits paid (51) (38)
Actuarial (gain) loss and
employee transfers 25 (41)
- - - - - - - ---------------------------------------------------------------
Balance at end of year $868 $813
===============================================================
Plan Assets
---------------------------
1998 1997
- - - - - - - ---------------------------------------------------------------
(in millions)
Balance at beginning of year $1,521 $1,334
Actual return on plan assets 9 250
Benefits paid (51) (38)
Employee transfers (18) (25)
- - - - - - - ---------------------------------------------------------------
Balance at end of year $1,461 $1,521
===============================================================
The accrued pension costs recognized in the Balance Sheets were
as follows:
1998 1997
- - - - - - - ---------------------------------------------------------------
(in millions)
Funded status $ 593 $ 708
Unrecognized transition obligation (30) (35)
Unrecognized prior service cost 39 43
Unrecognized net actuarial gain (433) (585)
- - - - - - - ---------------------------------------------------------------
Prepaid asset recognized in the
Balance Sheets $ 169 $ 131
===============================================================
II-71
NOTES (continued)
Alabama Power Company 1998 Annual Report
Components of the plans' net periodic cost were as follows:
1998 1997 1996
- - - - - - - ---------------------------------------------------------------
(in millions)
Service cost $ 22 $ 20 $ 21
Interest cost 59 58 60
Expected return on plan assets (102) (95) (93)
Recognized net actuarial gain (16) (13) (9)
Net amortization (2) (2) (3)
- - - - - - - ---------------------------------------------------------------
Net pension cost (income) $ (39) $ (32) $ (24)
===============================================================
Postretirement Benefits
Changes during the year in the projected benefit obligations and in the fair
value of plan assets were as follows:
Projected
Benefit Obligations
---------------------------
1998 1997
- - - - - - - ---------------------------------------------------------------
(in millions)
Balance at beginning of year $252 $242
Service cost 5 4
Interest cost 19 18
Benefits paid (12) (8)
Actuarial (gain) loss and
employee transfers 14 (4)
- - - - - - - ---------------------------------------------------------------
Balance at end of year $278 $252
===============================================================
Plan Assets
---------------------------
1998 1997
- - - - - - - ---------------------------------------------------------------
(in millions)
Balance at beginning of year $125 $108
Actual return on plan assets 4 16
Employer contributions 20 9
Benefits Paid (12) (8)
- - - - - - - ---------------------------------------------------------------
Balance at end of year $137 $125
===============================================================
The accrued postretirement costs recognized in the Balance Sheets
were as follows:
1998 1997
- - - - - - - ---------------------------------------------------------------
(in millions)
Funded status $(141) $(127)
Unrecognized transition obligation 57 61
Unrecognized net actuarial loss 22 3
Fourth quarter contributions 8 10
- - - - - - - ---------------------------------------------------------------
Accrued liability recognized in the
Balance Sheets $ (54) $ (53)
===============================================================
Components of the plans' net periodic cost were as follows:
1998 1997 1996
- - - - - - - ---------------------------------------------------------------
(in millions)
Service cost $ 5 $ 4 $ 5
Interest cost 18 18 17
Expected return on plan assets (9) (7) (6)
Recognized net gain - - 1
Net amortization 4 4 4
- - - - - - - ------------------------------------------------------ --------
Net postretirement cost $ 18 $ 19 $ 21
===============================================================
An additional assumption used in measuring the accumulated postretirement
benefit obligations was a weighted average medical care cost trend rate of 8.30
percent for 1998, decreasing gradually to 4.75 percent through the year 2005,
and remaining at that level thereafter. An annual increase or decrease in the
assumed medical care cost trend rate of 1 percent would affect the accumulated
benefit obligation and the service and interest cost components at December 31,
1998 as follows:
1 Percent 1 Percent
Increase Decrease
- - - - - - - ---------------------------------------------------------------
(in millions)
Benefit obligation $ 18 $ (15)
Service and interest costs 2 (1)
===============================================================
Work Force Reduction Programs
The Company has incurred additional costs for work force reduction programs. The
costs related to these programs were $19.4 million, $33.0 million and $26.7
million for the years 1998, 1997 and 1996, respectively. In addition, certain
costs of these programs were deferred and are being amortized in accordance with
regulatory treatment. The unamortized balance of these costs was $4.1 million at
December 31, 1998.
3. LITIGATION AND REGULATORY MATTERS
Retail Rate Adjustment Procedures
In November 1982, the APSC adopted rates that provide for periodic adjustments
based upon the Company's earned return on end-of-period retail common equity.
The rates also provide for adjustments to recognize the placing of new
generating facilities in retail service. Both increases and decreases have been
placed into effect since the adoption of these rates. The rate adjustment
II-72
NOTES (continued)
Alabama Power Company 1998 Annual Report
procedures allow a return on common equity range of 13.0 percent to 14.5 percent
and limit increases or decreases in rates to 4 percent in any calendar year.
In June 1995, the APSC issued a rate order granting the Company's request
for gradual adjustments to move toward parity among customer classes. This order
also calls for a moratorium on any periodic retail rate increases (but not
decreases) until July 2001.
In December 1995, the APSC issued an order authorizing the Company to reduce
balance sheet items -- such as plant and deferred charges -- at any time the
Company's actual base rate revenues exceed the budgeted revenues. In April 1997,
the APSC issued an additional order authorizing the Company to reduce balance
sheet asset items. This order authorizes the reduction of such items up to an
amount equal to five times the total estimated annual revenue reduction
resulting from future rate reductions initiated by the Company. In 1998, the
Company - in accordance with the 1995 rate order - recorded $33 million of
additional amortization of premium on reacquired debt.
The ratemaking procedures will remain in effect until the APSC votes to
modify or discontinue them.
Appliance Warranty Litigation
In 1996, a class action against the Company was filed charging the Company with
fraud and non-compliance with regulatory statutes relating to the offer, sale,
and financing of "extended service contracts" in connection with the sale of
electric appliances. The plaintiffs seek damages in an unspecified amount. The
Company has offered extended service agreements to its customers since January
1984, and approximately 175,000 extended service agreements could be involved in
these proceedings. The trial court has granted partial summary judgment in favor
of the plaintiffs. The Company has appealed this decision to the Supreme Court
of Alabama. The final outcome of this case cannot now be determined.
Environmental Litigation
On November 30, 1998, total judgments of nearly $53 million were entered in
favor of five plaintiffs against the Company and two large textile
manufacturers. The plaintiffs alleged that the manufacturers had discharged
certain polluting substances into a stream that empties into Lake Martin, a
hydroelectric reservoir owned by the Company, and that such discharges had
reduced the value of the plaintiffs' residential lots on Lake Martin. Of the
total amount of the judgments, $155 thousand was compensatory damages and the
remainder was punitive damages. The damages were assessed against all three
defendants jointly. Post-trial motions have been filed, and, if relief is not
granted at the trial court level, the Company will appeal these judgements to
the Supreme Court of Alabama. While the Company believes that these judgments
should be reversed or set aside, the final outcome of this matter cannot now be
determined.
FERC Reviews Equity Returns
On September 21, 1998, the FERC entered separate orders affirming the outcome of
the administrative law judge's opinions in two proceedings in which the return
on common equity component of formula rates contained in substantially all of
the operating companies' wholesale power contracts was being challenged as
unreasonably high. These orders resulted in no change in the wholesale power
contracts that were the subject of such proceedings. The FERC also dismissed a
complaint filed by three customers under long-term power sales agreements
seeking to lower the equity return component in such agreements. These customers
have filed applications for rehearing regarding each FERC order. In response to
a requirement of the September 1998 FERC order, Southern Company filed a new
equity return component on the long-term power sales contracts, to be effective
January 5, 1999. The proposed equity return was lowered from 13.75 percent to
12.50 percent. If the filed equity return is approved, the estimated impact on
the Company's revenues will be approximately $5 million annually. The FERC
placed the new rates into effect, subject to refund. Also, this filing was
consolidated with the new proceeding discussed below.
On December 28, 1998, the FERC staff filed a motion asking the FERC to
initiate a new proceeding regarding the equity return and other issues involving
the Company's formula rate contracts. The motion was submitted pursuant to
review procedures applicable to these contracts, and would be applicable to
billings under such contracts on and after January 1, 1999.
Tax Litigation
In August 1997, Southern Company and the Internal Revenue Service (IRS) entered
into a settlement agreement related to tax issues for the years 1984 through
1987. The agreement received final approval by the Joint Congressional
II-73
NOTES (continued)
Alabama Power Company 1998 Annual Report
Committee on Taxation in June 1998 and as a result, the Company recognized
interest income in 1998 of $14 million. The refund by the IRS has been made
and this matter is now concluded.
4. CAPITAL BUDGET
The Company's capital expenditures are currently estimated to total $875 million
in 1999, $653 million in 2000, and $668 million in 2001. Included in these
estimates are the following: the Company will replace all six steam generators
at Plant Farley at a total cost of approximately $234 million. Additionally, the
Company plans to construct and install 1,075 megawatts of new generating
capacity and associated substation facilities at Plant Barry. The projected
capital expenditures for this project amount to approximately $384 million.
The capital budget is subject to periodic review and revision, and actual
capital costs 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.
In addition, significant construction will continue related to transmission
and distribution facilities and the upgrading 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 is often utilized and
the amounts available are discussed below. The Company may issue additional
long-term debt and preferred securities for 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 historically has relied on issuances of first mortgage bonds
and preferred stock, in addition to pollution control revenue bonds issued for
its benefit by public authorities, to meet its long-term external financing
requirements. Recently, the Company's financings have consisted of unsecured
debt and trust preferred securities. In this regard, the Company sought and
obtained stockholder approval in 1997 to amend its corporate charter eliminating
restrictions on the amounts of unsecured indebtedness it may incur. In order to
issue additional debt and equity securities, the Company must comply with
certain earnings coverage requirements designated in its mortgage indenture and
corporate charter. The most restrictive of these provisions requires, for the
issuance of additional first mortgage bonds, that before-income-tax earnings, as
defined, cover pro forma annual interest charges on outstanding first mortgage
bonds at least twice; and for the issuance of additional preferred stock, that
gross income available for interest cover pro forma annual interest charges and
preferred stock dividends at least one and one-half times. The Company's
coverages are at a level that would permit any necessary amount of security
sales at current interest and dividend rates.
Bank Credit Arrangements
The Company maintains committed lines of credit in the amount of $757.7 million
(including $315 million of such lines under which are dedicated to funding
purchase obligations relating to variable rate pollution control bonds). Of
these lines, $677.7 million expire at various times during 1999 and $80 million
expires in 2003. In certain cases, such lines require payment of a commitment
fee based on the unused portion of the commitment or the maintenance of
compensating balances with the banks. 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, 1998, the Company had regulatory approval to have
outstanding up to $750 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.
II-74
NOTES (continued)
Alabama Power Company 1998 Annual Report
Fuel Commitments
To supply a portion of the fuel requirements of its generating plants, the
Company has entered into various long-term commitments for the procurement of
fossil and nuclear fuel. In most cases, these contracts contain provisions for
price escalations, minimum purchase levels and other financial commitments.
Total estimated long-term obligations at December 31, 1998, were as follows:
Year Amounts
----------------
(in millions)
1999 $ 825
2000 547
2001 497
2002 376
2003 381
2004 - 2014 2,417
- - - - - - - ---------------------------------------------------------------
Total commitments $ 5,043
===============================================================
Operating Leases
The Company has entered into coal rail car rental agreements with various terms
and expiration dates. These expenses totaled $5.8 million in 1998, and $3.0
million each for 1997 and 1996. At December 31, 1998, estimated minimum rental
commitments for noncancellable operating leases were as follows:
Year Amounts
----------------
(in millions)
1999 $ 11.4
2000 9.7
2001 7.3
2002 5.9
2003 5.7
2004 - 2018 51.4
- - - - - - - ---------------------------------------------------------------
Total minimum payments $ 91.4
===============================================================
6. JOINT OWNERSHIP AGREEMENTS
The Company and Georgia Power Company own equally all of the outstanding capital
stock of Southern Electric Generating Company (SEGCO), which owns electric
generating units with a total rated capacity of 1,020 megawatts, 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 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 totaled $74 million in 1998, $73
million in 1997 and $75 million in 1996, and is included in "Purchased power
from affiliates" in the Statements of Income.
In addition, the Company has guaranteed unconditionally the obligation of
SEGCO under an installment sale agreement for the purchase of certain pollution
control facilities at SEGCO's generating units, pursuant to which $24.5 million
principal amount of pollution control revenue bonds are outstanding. Georgia
Power Company has agreed to reimburse the Company for the pro rata portion of
such obligation corresponding to its then proportionate ownership of stock of
SEGCO if the Company is called upon to make such payment under its guaranty.
At December 31, 1998, the capitalization of SEGCO consisted of $49 million
of equity and $70 million of long-term debt on which the annual interest
requirement is $4.1 million. SEGCO paid dividends totaling $8.7 million in 1998,
$10.6 million in 1997, and $10.1 million in 1996, of which one-half of each was
paid to the Company. SEGCO's net income was $7.5 million, $8.5 million, and $7.7
million for 1998, 1997 and 1996, respectively.
The Company's percentage ownership and investment in jointly-owned
generating plants at December 31, 1998, 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 $ 94 $ 42
Plant Miller
Units 1 and 2 717 330
----------------------------------------------------------
II-75
NOTES (continued)
Alabama Power Company 1998 Annual Report
7. LONG-TERM POWER SALES AGREEMENTS
General
The Company and the operating affiliates of 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. These
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, profitability is primarily
affected by revenues from capacity sales. The Company's capacity revenues
amounted to $142 million in 1998, $136 million in 1997, and $151 million in
1996.
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 are scheduled to be sold through 1999.
Thereafter, these sales will remain at that approximate level -- unless reduced
by FP&L, FPC, and JEA for the periods after 1999 with a minimum of three years
notice -- 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 sales 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 sales contract with AMEA
entitling AMEA to scheduled amounts of additional capacity (to a maximum 80
megawatts) for a period of 15 years commencing October 1, 1991 (1991 Contract).
In both contracts the power will be sold to AMEA for its member municipalities
that previously were served directly by the Company as wholesale customers.
Under the terms of the contracts, the Company received payments from AMEA
representing the net present value of the revenues associated with the
respective capacity entitlements, discounted at effective annual rates of 9.96
percent and 11.19 percent for the 1986 and 1991 contracts, respectively. These
payments are being recognized as operating revenues and the discounts are being
amortized to other interest expense as scheduled capacity is made available over
the terms of the contracts.
In order to secure AMEA's advance payments and the Company's performance
obligation under the contracts, the Company issued and delivered to an escrow
agent first mortgage bonds representing the maximum amount of liquidated damages
payable by the Company in the event of a default under the contracts. No
principal or interest is payable on such bonds unless and until a default by the
Company occurs. As the liquidated damages decline under the contracts, a portion
of the bonds equal to the decreases are returned to the Company. At December 31,
1998, $99.4 million of such bonds was held by the escrow agent under the
contracts.
8. INCOME TAXES
At December 31, 1998, the tax-related regulatory assets and liabilities were
$363 million and $316 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:
1998 1997 1996
--------------------------------
(in thousands)
Total provision for income taxes:
Federal --
Currently payable $123,384 $197,159 $172,911
Deferred --
current year 59,162 32,884 (6,309)
reversal of prior years 12,984 (44,300) 18,948
- - - - - - - -----------------------------------------------------------------
195,530 185,743 185,550
- - - - - - - -----------------------------------------------------------------
State --
Currently payable 15,761 23,147 16,212
Deferred --
current year 4,811 1,409 697
reversal of prior years 2,473 (2,422) 3,249
- - - - - - - -----------------------------------------------------------------
23,045 22,134 20,158
- - - - - - - -----------------------------------------------------------------
Total 218,575 207,877 205,708
Less income taxes credited
to other income (6,347) (12,351) (22,400)
- - - - - - - -----------------------------------------------------------------
Total income taxes
charged to operations $224,922 $220,228 $228,108
=================================================================
II-76
NOTES (continued)
Alabama Power Company 1998 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:
1998 1997
------------------
(in millions)
Deferred tax liabilities:
Accelerated depreciat $ 861 $ 847
Property basis differences 435 463
Premium on reacquired debt 29 30
Pensions 50 20
Other 46 11
----------------------------------------------------------------
Total
1,421 1,371
- - - - - - - ------------------------------------------------------------------
Deferred tax assets:
Capacity prepayments 28 31
Other deferred costs 25 33
Postretirement benefits 20 18
Unbilled revenue 16 16
Other 56 66
Total 145 164
----------------------------------------------------------------
Net deferred tax liabilities 1,276 1,207
Portion included in current assets
(liabilities), net (73) (15)
- - - - - - - ----------------------------------------------------------------
Accumulated deferred income taxes
in the Balance Sheets $ 1,203 $ 1,192
================================================================
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 $11 million in 1998, 1997, and 1996. At December 31, 1998, 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:
1998 1997 1996
--------------------------
Federal statutory rate 35.0% 35.0% 35.0%
State income tax,
net of federal deduction 2.5 2.4 2.2
Non-deductible book
depreciation 1.5 1.5 1.5
Differences in prior years'
deferred and current tax rates (1.6) (2.3) (1.6)
Other (1.6) (1.9) (3.0)
- - - - - - - ---------------------------------------------------------------
Effective income tax rate 35.8% 34.7% 34.1%
===============================================================
Southern Company files a consolidated federal income tax return. Under a
joint consolidated income tax agreement, each subsidiary's current and deferred
tax expense is computed on a stand-alone basis. Tax benefits from losses of the
parent company are allocated to each subsidiary based on the ratio of taxable
income to total consolidated taxable income.
9. COMPANY OBLIGATED MANDATORILY
REDEEMABLE PREFERRED SECURITIES
Statutory business trusts formed by the Company, of which the Company owns all
the common securities, have issued mandatorily redeemable preferred securities
as follows:
Date of Maturity
Issue Amount Rate Notes Date
--------------------------------------------------------
(millions) (millions)
Trust I 1/1996 $ 97 7.375% $100 3/2026
Trust II 1/1997 200 7.60 206 12/2036
Substantially all of the assets of each trust are junior subordinated notes
issued by the Company in the respective approximate principal amounts set forth
above. In February 1999, the Company issued $50 million of variable rate
mandatorily redeemable preferred securities (Trust III), the initial
distribution rate of which was 4.85 percent. The associated junior subordinated
notes, in the amount of $51.6 million, will be due February 28, 2029.
The Company considers that the mechanisms and obligations relating to the
preferred securities, taken together, constitute a full and unconditional
guarantee by the Company of the Trusts' payment obligations with respect to the
preferred securities.
The Trusts are subsidiaries of the Company, and accordingly are consolidated
in the Company's financial statements.
10. OTHER LONG-TERM DEBT
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 $215.9 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.
II-77
NOTES (continued)
Alabama Power Company 1998 Annual Report
No principal or interest on these first mortgage bonds is payable unless and
until a default occurs on the installment purchase agreements.
In 1997 and 1998, the Company issued unsecured senior notes. The senior notes
are, in effect, subordinated to all secured debt of the Company, including its
first mortgage bonds.
The estimated aggregate annual maturities of capitalized lease obligations
through 2003 are as follows: $1.0 million in 1999, $0.9 million in 2000, $0.8
million in 2001, $0.9 million in 2002 and $0.9 million in 2003.
11. SECURITIES DUE WITHIN ONE YEAR
A summary of the improvement fund requirements and scheduled maturities and
redemptions of long-term debt and preferred stock due within one year at
December 31 is as follows:
1998 1997
------------------------
(in thousands)
Bond improvement fund
requirements $ - $18,450
First mortgage bond maturities
and redemptions 470,000 55,895
Other long-term debt maturities
(Note 10) 1,209 991
-------------------------------------------------------------
Total long-term debt due within
one year 471,209 75,336
-------------------------------------------------------------
Preferred stock to be redeemed 50,000 -
-------------------------------------------------------------
Total $521,209 $75,336
=============================================================
The annual first mortgage bond improvement fund requirement is 1 percent
of the aggregate principal amount of bonds of each series authenticated, so long
as a portion of that series is outstanding, and may be satisfied by the deposit
of cash and/or reacquired bonds, the certification of unfunded property
additions or a combination thereof. Scheduled maturities amount to $0.2 million
in connection with pollution control bonds as a result of the redemption, over a
five-year period, of the 7.25 percent series due 2003.
12. 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 $9.7 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. The Company could be assessed up to $88 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
$176 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 Electric Insurance Limited (NEIL), a
mutual insurer established to provide property damage insurance in an amount up
to $500 million for members' nuclear generating facilities.
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 primary
coverage. This excess insurance is also provided by NEIL.
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 17 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 current maximum annual assessments for the Company under the
three NEIL policies would be $21 million.
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
II-78
NOTES (continued)
Alabama Power Company 1998 Annual Report
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.
All retrospective assessments, whether generated for liability, property
or replacement power may be subject to applicable state premium taxes.
13. 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, 1998, retained earnings of $796 million were
restricted against the payment of cash dividends on common stock under terms of
the mortgage indenture.
14. QUARTERLY FINANCIAL INFORMATION
(Unaudited)
Summarized quarterly financial data for 1998 and 1997 are as follows:
Net Income
After
Dividends
Quarter Operating Operating on Preferred
Ended Revenues Income Stock
- - - - - - - -------------------- -----------------------------------------
(in thousands)
March 1998 $716,505 $130,735 $ 66,041
June 1998 863,715 178,722 94,750
September 1998 1,057,988 242,063 173,958
December 1998 748,165 105,519 42,474
March 1997 $704,768 $123,455 $ 57,807
June 1997 728,089 125,750 63,137
September 1997 962,446 249,487 191,800
December 1997 753,808 128,511 63,195
=================================================================
The Company's business is influenced by seasonal weather conditions.
II-79
SELECTED FINANCIAL AND OPERATING DATA
Alabama Power Company 1998 Annual Report
===========================================================================================================================
1998 1997 1996
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands) $3,386,373 $3,149,111 $3,120,775
Net Income after Dividends
on Preferred Stock (in thousands) $377,223 $375,939 $371,490
Cash Dividends on Common Stock (in thousands) $367,100 $339,600 $347,500
Return on Average Common Equity (percent) 13.63 13.76 13.75
Total Assets (in thousands) $9,225,698 $8,812,867 $8,733,846
Gross Property Additions (in thousands) $610,132 $451,167 $425,024
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $2,784,067 $2,750,569 $2,714,277
Preferred stock 317,512 255,512 340,400
Preferred stock subject to mandatory redemption - - -
Subsidiary obligated mandatorily redeemable preferred securities 297,000 297,000 97,000
Long-term debt 2,646,566 2,473,202 2,354,006
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $6,045,145 $5,776,283 $5,505,683
===========================================================================================================================
Capitalization Ratios (percent):
Common stock equity 46.1 47.6 49.3
Preferred stock 5.2 4.4 6.2
Company obligated mandatorily redeemable preferred securities 4.9 5.2 1.7
Long-term debt 43.8 42.8 42.8
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0 100.0
===========================================================================================================================
First Mortgage Bonds (in thousands):
Issued - - -
Retired 771,108 74,951 83,797
Company Obligated Mandatorily Redeemable Preferred
Securities (in thousands):
Issued - 200,000 97,000
Senior Notes (in thousands):
Issued 1,356,200 193,800 -
Preferred Stock (in thousands):
Issued 200,000 - -
Retired 88,000 184,888 -
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Security Ratings:
First Mortgage Bonds -
Moody's A1 A1 A1
Standard and Poor's A+ A+ A+
Duff & Phelps AA- AA- AA-
Preferred Stock -
Moody's a2 a2 a2
Standard and Poor's A A A
Duff & Phelps A A+ A+
Unsecured Long-Term Debt -
Moody's A2 A2 -
Standard and Poor's A A -
Duff & Phelps A+ A+ -
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Customers (year-end):
Residential 1,106,217 1,092,161 1,073,559
Commercial 182,738 177,362 171,827
Industrial 5,020 5,076 5,100
Other 733 728 732
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Total 1,294,708 1,275,327 1,251,218
===========================================================================================================================
Employees (year-end) 6,631 6,531 6,865
II-80
SELECTED FINANCIAL AND OPERATING DATA
Alabama Power Company 1998 Annual Report
==============================================================================================================================
1995 1994 1993 1992
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands) $3,024,774 $2,935,142 $3,007,609 $2,846,840
Net Income after Dividends
on Preferred Stock (in thousands) $360,894 $356,338 $346,494 $338,555
Cash Dividends on Common Stock (in thousands) $285,000 $268,000 $252,900 $273,300
Return on Average Common Equity (percent) 13.61 13.86 13.94 14.02
Total Assets (in thousands) $8,744,360 $8,459,217 $8,248,683 $6,593,618
Gross Property Additions (in thousands) $551,781 $536,785 $435,843 $367,463
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $2,690,374 $2,614,405 $2,526,348 $2,443,493
Preferred stock 440,400 440,400 440,400 489,400
Preferred stock subject to mandatory redemption - - - -
Subsidiary obligated mandatorily redeemable preferred securities - - - -
Long-term debt 2,374,948 2,455,013 2,362,852 2,202,473
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $5,505,722 $5,509,818 $5,329,600 $5,135,366
==============================================================================================================================
Capitalization Ratios (percent):
Common stock equity 48.9 47.4 47.4 47.6
Preferred stock 8.0 8.0 8.3 9.5
Company obligated mandatorily redeemable preferred securities - - - -
Long-term debt 43.1 44.6 44.3 42.9
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0 100.0 100.0
==============================================================================================================================
First Mortgage Bonds (in thousands):
Issued - 150,000 860,000 745,000
Retired - 20,387 699,788 931,797
Company Obligated Mandatorily Redeemable Preferred
Securities (in thousands):
Issued - - - -
Senior Notes (in thousands):
Issued - - - -
Preferred Stock (in thousands):
Issued - - 158,000 150,000
Retired - - 207,000 145,000
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------
Security Ratings:
First Mortgage Bonds -
Moody's A1 A1 A1 A1
Standard and Poor's A+ A A A
Duff & Phelps A+ A+ A+ A
Preferred Stock -
Moody's a2 a2 a2 a2
Standard and Poor's A A- A- A-
Duff & Phelps A A- A- A-
Unsecured Long-Term Debt -
Moody's - - - -
Standard and Poor's - - - -
Duff & Phelps - - - -
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------
Customers (year-end):
Residential 1,058,197 1,042,974 1,027,130 1,012,294
Commercial 166,480 162,239 157,337 152,530
Industrial 5,338 5,341 5,391 5,434
Other 725 716 713 704
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------
Total 1,230,740 1,211,270 1,190,571 1,170,962
==============================================================================================================================
Employees (year-end) 7,261 7,996 8,009 8,116
II-81A
SELECTED FINANCIAL AND OPERATING DATA
Alabama Power Company 1998 Annual Report
===============================================================================================================================
1991 1990 1989 1988
- - - - - - - -------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands) $2,846,794 $2,722,424 $2,629,354 $2,476,626
Net Income after Dividends
on Preferred Stock (in thousands) $339,666 $312,803 $311,146 $283,475
Cash Dividends on Common Stock (in thousands) $232,900 $220,800 $217,300 $212,700
Return on Average Common Equity (percent) 14.55 14.00 14.53 14.03
Total Assets (in thousands) $6,549,462 $6,362,293 $6,279,431 $6,180,945
Gross Property Additions (in thousands) $397,011 $444,680 $459,199 $643,892
- - - - - - - -------------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock 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
Subsidiary obligated mandatorily redeemable preferred securities - - - -
Long-term debt 2,382,635 2,397,931 2,435,129 2,496,492
- - - - - - - -------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $5,254,233 $5,175,421 $5,125,840 $5,098,207
===============================================================================================================================
Capitalization Ratios (percent):
Common stock equity 45.4 44.1 42.7 41.1
Preferred stock 9.2 9.6 9.8 9.9
Company obligated mandatorily redeemable preferred securities - - - -
Long-term debt 45.4 46.3 47.5 49.0
- - - - - - - -------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0 100.0 100.0
===============================================================================================================================
First Mortgage Bonds (in thousands):
Issued 250,000 - - 150,000
Retired 227,695 33,122 75,650 42,445
Company Obligated Mandatorily Redeemable Preferred
Securities (in thousands):
Issued - - - -
Senior Notes (in thousands):
Issued - - - -
Preferred Stock (in thousands):
Issued - - - 100,000
Retired 17,500 5,000 5,000 2,500
- - - - - - - -------------------------------------------------------------------------------------------------------------------------------
Security Ratings:
First Mortgage Bonds -
Moody's A1 A1 A1 A1
Standard and Poor's A A A A
Duff & Phelps A A A 6
Preferred Stock -
Moody's a2 a2 a2 a2
Standard and Poor's A- A- A- A-
Duff & Phelps A- A- A- 7
Unsecured Long-Term Debt -
Moody's - - - -
Standard and Poor's - - - -
Duff & Phelps - - - -
- - - - - - - -------------------------------------------------------------------------------------------------------------------------------
Customers (year-end):
Residential 997,585 985,566 974,622 964,581
Commercial 148,228 144,340 141,265 137,955
Industrial 5,496 5,322 5,200 5,120
Other 697 690 684 678
- - - - - - - -------------------------------------------------------------------------------------------------------------------------------
Total 1,152,006 1,135,918 1,121,771 1,108,334
===============================================================================================================================
Employees (year-end) 8,513 9,473 9,698 10,302
II-81B
SELECTED FINANCIAL AND OPERATING DATA (continued)
Alabama Power Company 1998 Annual Report
===========================================================================================================================
1998 1997 1996
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $1,133,435 $997,507 $998,806
Commercial 779,169 724,148 696,453
Industrial 853,550 775,591 759,628
Other 14,523 13,563 13,729
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Total retail 2,780,677 2,510,809 2,468,616
Sales for resale - non-affiliates 448,973 431,023 391,669
Sales for resale - affiliates 103,562 161,795 216,620
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 3,333,212 3,103,627 3,076,905
Other revenues 53,161 45,484 43,870
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Total $3,386,373 $3,149,111 $3,120,775
===========================================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 15,794,543 14,336,408 14,593,761
Commercial 11,904,509 11,330,312 10,904,476
Industrial 21,585,117 20,727,912 19,999,258
Other 196,647 180,389 192,573
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Total retail 49,480,816 46,575,021 45,690,068
Sales for resale - non-affiliates 11,840,909 12,329,480 9,491,237
Sales for resale - affiliates 5,976,099 8,993,326 10,292,066
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Total 67,297,824 67,897,827 65,473,371
===========================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 7.18 6.96 6.84
Commercial 6.55 6.39 6.39
Industrial 3.95 3.74 3.80
Total retail 5.62 5.39 5.40
Sales for resale 3.10 2.78 3.07
Total sales 4.95 4.57 4.70
Residential Average Annual Kilowatt-Hour
Use Per Customer 14,370 13,254 13,705
Residential Average Annual Revenue
Per Customer $1,031.21 $922.21 $937.95
Plant Nameplate Capacity Ratings (Note 1)
(year-end) (megawatts) 11,151 11,151 11,151
Territorial Peak-Hour Demand (megawatts) (Note 2):
Winter 7,757 8,478 8,413
Summer 10,329 9,778 9,912
Annual Load Factor (percent) (Note 2) 62.9 62.7 61.3
Plant Availability (percent):
Fossil-steam 85.6 86.3 86.6
Nuclear 80.2 88.8 90.5
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 65.3 65.7 67.0
Nuclear 16.3 17.9 18.5
Hydro 6.9 7.5 7.1
Oil and gas 1.5 0.7 0.4
Purchased power -
From non-affiliates 3.3 2.4 2.4
From affiliates 6.7 5.8 4.6
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0
===========================================================================================================================
Total Fuel Economy Data (Note 1):
BTU per net kilowatt-hour generated 8,938 9,984 10,035
Cost of fuel per million BTU (cents) 171.85 148.61 147.09
Average cost of fuel per net kilowatt-hour generated (cents) 1.54 1.48 1.48
===========================================================================================================================
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-82
SELECTED FINANCIAL AND OPERATING DATA (continued)
Alabama Power Company 1998 Annual Report
==============================================================================================================================
1995 1994 1993 1992
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $997,069 $913,146 $947,277 $845,660
Commercial 670,453 647,202 634,895 589,816
Industrial 805,596 803,587 832,938 800,311
Other 13,619 13,515 13,344 12,734
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------
Total retail 2,486,737 2,377,450 2,428,454 2,248,521
Sales for resale - non-affiliates 370,140 354,760 364,105 407,791
Sales for resale - affiliates 127,730 164,762 181,975 158,088
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 2,984,607 2,896,972 2,974,534 2,814,400
Other revenues 40,167 38,170 33,075 32,440
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------
Total $3,024,774 $2,935,142 $3,007,609 $2,846,840
==============================================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 14,383,231 13,183,147 13,185,062 12,069,268
Commercial 10,043,220 9,645,798 9,185,462 8,629,869
Industrial 19,862,577 19,479,364 18,595,237 18,260,274
Other 186,848 185,876 181,673 176,798
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------
Total retail 44,475,876 42,494,185 41,147,434 39,136,209
Sales for resale - non-affiliates 8,046,189 6,775,176 7,143,672 8,382,571
Sales for resale - affiliates 6,705,174 8,432,533 8,081,324 7,210,697
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------
Total 59,227,239 57,701,894 56,372,430 54,729,477
==============================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 6.93 6.93 7.18 7.01
Commercial 6.68 6.71 6.91 6.83
Industrial 4.06 4.13 4.48 4.38
Total retail 5.59 5.59 5.90 5.75
Sales for resale 3.38 3.42 3.59 3.63
Total sales 5.04 5.02 5.28 5.14
Residential Average Annual Kilowatt-Hour
Use Per Customer 13,686 12,746 12,936 12,017
Residential Average Annual Revenue
Per Customer $948.71 $882.88 $929.36 $842.00
Plant Nameplate Capacity Ratings (Note 1)
(year-end) (megawatts) 10,831 10,431 10,431 10,431
Territorial Peak-Hour Demand (megawatts) (Note 2):
Winter 7,958 8,217 7,152 7,077
Summer 10,090 9,028 9,457 8,801
Annual Load Factor (percent) (Note 2) 59.2 62.2 58.6 59.6
Plant Availability (percent):
Fossil-steam 88.3 86.9 89.7 88.9
Nuclear 81.1 92.5 86.6 80.2
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 67.1 62.9 63.9 64.3
Nuclear 17.1 21.7 20.1 19.0
Hydro 7.0 8.4 6.9 8.5
Oil and gas 0.4 * * *
Purchased power -
From non-affiliates 2.7 1.3 1.1 1.2
From affiliates 5.7 5.7 8.0 7.0
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0 100.0
==============================================================================================================================
Total Fuel Economy Data (Note 1):
BTU per net kilowatt-hour generated 10,025 9,961 10,003 10,000
Cost of fuel per million BTU (cents) 148.68 157.62 173.66 164.57
Average cost of fuel per net kilowatt-hour generated (cents) 1.49 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-83A
SELECTED FINANCIAL AND OPERATING DATA (continued)
Alabama Power Company 1998 Annual Report
=================================================================================================================================
1991 1990 1989 1988
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $864,347 $825,645 $781,982 $761,805
Commercial 582,730 551,634 533,487 510,910
Industrial 790,224 777,580 762,274 738,755
Other 12,662 12,103 11,743 11,255
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------------
Total retail 2,249,963 2,166,962 2,089,486 2,022,725
Sales for resale - non-affiliates 407,912 434,996 409,202 355,362
Sales for resale - affiliates 159,375 93,473 104,488 76,691
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 2,817,250 2,695,431 2,603,176 2,454,778
Other revenues 29,544 26,993 26,178 21,848
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------------
Total $2,846,794 $2,722,424 $2,629,354 $2,476,626
=================================================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 12,324,898 11,996,794 11,346,736 11,332,285
Commercial 8,526,131 8,201,534 7,915,685 7,711,092
Industrial 17,511,579 17,713,153 17,360,791 16,881,342
Other 174,760 170,420 166,485 165,122
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------------
Total retail 38,537,368 38,081,901 36,789,697 36,089,841
Sales for resale - non-affiliates 8,810,442 10,277,060 10,292,329 7,905,750
Sales for resale - affiliates 7,784,285 4,519,275 5,048,743 3,551,142
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------------
Total 55,132,095 52,878,236 52,130,769 47,546,733
=================================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 7.01 6.88 6.89 6.72
Commercial 6.83 6.73 6.74 6.63
Industrial 4.51 4.39 4.39 4.38
Total retail 5.84 5.69 5.68 5.60
Sales for resale 3.42 3.57 3.35 3.77
Total sales 5.11 5.10 4.99 5.16
Residential Average Annual Kilowatt-Hour
Use Per Customer 12,435 12,256 11,717 11,839
Residential Average Annual Revenue
Per Customer $872.04 $843.50 $807.50 $795.84
Plant Nameplate Capacity Ratings (Note 1)
(year-end) (megawatts) 10,539 9,879 9,879 9,279
Territorial Peak-Hour Demand (megawatts) (Note 2):
Winter 6,586 6,293 7,264 6,377
Summer 8,627 8,878 8,256 7,991
Annual Load Factor (percent) (Note 2) 59.9 57.4 59.5 59.6
Plant Availability (percent):
Fossil-steam 93.1 92.2 90.7 91.3
Nuclear 87.0 86.5 83.1 91.9
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 61.5 57.0 54.1 53.9
Nuclear 20.8 21.6 21.0 26.1
Hydro 8.2 8.7 11.0 4.8
Oil and gas * 0.1 0.1 0.1
Purchased power -
From non-affiliates 1.6 0.9 1.8 0.5
From affiliates 7.9 11.7 12.0 14.6
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0 100.0
=================================================================================================================================
Total Fuel Economy Data (Note 1):
BTU per net kilowatt-hour generated 9,985 10,072 10,061 10,137
Cost of fuel per million BTU (cents) 170.49 171.55 172.20 168.21
Average cost of fuel per net kilowatt-hour generated (cents) 1.70 1.73 1.73 1.71
=================================================================================================================================
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.
11-83B
GEORGIA POWER COMPANY
FINANCIAL SECTION
II-84
MANAGEMENT'S REPORT
Georgia Power Company 1998 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 three
directors who are not employees, provides a broad overview of management's
financial reporting and control functions. At least three times a year this
committee meets with management, the internal auditors, and the independent
public accountants to ensure that these groups are fulfilling their obligations
and to discuss auditing, internal control and financial reporting matters. The
internal auditors and the independent public accountants have access to the
members of the audit committee at any time.
Management believes that its policies and procedures provide reasonable
assurance that the Company's operations are conducted with a high standard of
business ethics.
In management's opinion, the financial statements present fairly, in all
material respects, the financial position, results of operations and cash flows
of Georgia Power Company in conformity with generally accepted accounting
principles.
/s/ H. Allen Franklin
H. Allen Franklin
President and Chief
Executive Officer
/s/ David M. Ratcliffe
David M. Ratcliffe
Executive Vice President,
Treasurer and Chief
Financial Officer
February 10, 1999
II-85
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Georgia Power Company:
We have audited the accompanying balance sheets and statements of capitalization
of Georgia Power Company (a Georgia corporation and a wholly owned subsidiary of
Southern Company) as of December 31, 1998 and 1997, 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, 1998. 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-97 through II-117)
referred to above present fairly, in all material respects, the financial
position of Georgia Power Company as of December 31, 1998 and 1997, and the
results of its operations and its cash flows for each of the three years in the
period ended December 31, 1998, in conformity with generally accepted
accounting principles.
/s/ Arthur Andersen LLP
Arthur Andersen LLP
Atlanta, Georgia
February 10, 1999
II-86
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Georgia Power Company 1998 Annual Report
RESULTS OF OPERATIONS
Earnings
Georgia Power Company's 1998 earnings totaled $570 million, representing a $24
million (4.0 percent) decrease from 1997. This earnings decrease resulted
primarily from higher operating expenses, additional depreciation charges
pursuant to a Georgia Public Service Commission (GPSC) retail accounting order
discussed below, lower wholesale capacity revenues, and the write-off of a
portion of the Rocky Mountain plant investment. These decreases to earnings were
partially offset by higher retail revenues, lower financing costs and increased
non-operating income. Earnings for 1997 totaled $594 million, representing a $14
million (2.4 percent) increase over 1996. This earnings increase resulted
primarily from lower operating expenses, lower financing costs, and increased
non-operating income, partially offset by lower retail revenues and additional
depreciation charges pursuant to the GPSC retail accounting order.
Revenues
The following table summarizes the factors impacting operating revenues for the
1996-1998 period:
Increase (Decrease)
From Prior Year
------------------------------------
1998 1997 1996
------------------------------------
Retail - (in millions)
Sales growth $ 174 $ 62 $ 58
Weather 101 (74) (25)
Fuel cost recovery 70 (30) 28
Demand-side programs (25) (3) (10)
- - - - - - - --------------------------------------------------------------------
Total retail 320 (45) 51
- - - - - - - --------------------------------------------------------------------
Sales for resale -
Non-affiliates (23) 1 (9)
Affiliates 43 3 (41)
- - - - - - - --------------------------------------------------------------------
Total sales for resale 20 4 (50)
- - - - - - - --------------------------------------------------------------------
Other operating revenues 13 10 10
- - - - - - - --------------------------------------------------------------------
Total operating revenues $ 353 $ (31) $ 11
====================================================================
Percent change 8.0% (0.7)% 0.3%
- - - - - - - --------------------------------------------------------------------
Retail revenues of $4.3 billion in 1998 increased $320 million (8.0 percent)
from 1997 primarily due to higher energy sales to residential and commercial
customers. Retail revenues of $4.0 billion in 1997 decreased $45 million (1.1
percent) from 1996 primarily due to milder-than-normal weather, as well as
commercial and industrial customers taking advantage of load management rates.
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.
Wholesale revenues from sales to non-affiliated utilities decreased slightly
in 1998 and were as follows:
1998 1997 1996
-------------------------------
(in millions)
Outside service area -
Long-term contracts $ 51 $ 71 $ 84
Other sales 94 80 37
Inside service area 115 132 161
- - - - - - - ---------------------------------------------------------------
Total $260 $283 $282
===============================================================
Revenues from long-term contracts outside the service area decreased in 1998
primarily due to lower capacity charges and decreased energy sales and in 1997
primarily due to scheduled reductions in the amount of megawatt-hour capacity
under these contracts. See Note 7 to the financial statements for further
information regarding these sales. Revenues from other sales outside the service
area increased in 1998 and 1997 primarily due to power marketing activities.
These increases were primarily offset by increases in purchased power from
non-affiliates and, as a result, had no significant effect on net income.
Wholesale revenues from customers within the service area decreased in 1998 and
1997 primarily due to a decrease in revenues under a power supply agreement with
Oglethorpe Power Corporation (OPC). OPC decreased its purchases of capacity by
250 megawatts each in September 1996, 1997, and 1998 and has notified the
Company of its intent to decrease purchases of capacity by an additional 250
megawatts in September 1999 and 125 megawatts in September 2000.
Revenues from sales to affiliated companies within the Southern electric
system, as well as purchases of energy, will vary from year to year depending on
demand and the availability and cost of generating resources at each company.
These transactions do not have a significant impact on earnings.
II-87
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1998 Annual Report
Kilowatt-hour (KWH) sales for 1998 and the percent change by year were as
follows:
Percent Change
----------------------------
1998
KWH 1998 1997 1996
-----------------------------------------
(in billions)
Residential 19.5 12.6% (3.0)% 3.0%
Commercial 22.9 8.2 1.5 4.9
Industrial 27.3 2.2 1.9 3.6
Other 0.5 1.0 0.4 8.6
--------
Total retail 70.2 6.9 0.4 3.9
--------
Sales for resale -
Non-affiliates 6.4 (5.2) (13.6) 19.4
Affiliates 2.0 19.4 44.6 (56.9)
--------
Total sales for resale 8.4 (0.3) (6.0) (3.0)
--------
Total sales 78.6 6.0 (0.3) 3.0
========
- - - - - - - ------------------------------------------------------------------
Residential and commercial sales increased in 1998 12.6 percent and 8.2
percent, respectively, and industrial sales increased slightly by 2.2 percent.
The increases are attributed primarily to sales growth and hotter temperatures
in the summer months. Residential sales in 1997 declined 3.0 percent while sales
to commercial and industrial customers increased slightly by 1.5 percent and 1.9
percent, respectively. Milder-than-normal temperatures experienced in 1997
contributed to the moderate sales.
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 KWH generated were as follows:
1998 1997 1996
-------------------------
Total generation
(billions of KWH) 69.1 66.5 63.7
Sources of generation
(percent) --
Coal 73.3 74.8 74.3
Nuclear 21.6 21.8 22.4
Hydro 2.6 2.7 2.7
Oil and gas 2.5 0.7 0.6
Average cost of fuel per net
KWH generated
(cents) -- 1.36 1.32 1.35
- - - - - - - ---------------------------------------------------------------
Fuel expense increased 7.0 percent in 1998 primarily due to an increase in
generation to meet higher energy demands and a higher average cost of fuel. Fuel
expense increased 2.6 percent in 1997 primarily due to an increase in
generation, partially offset by a lower average cost of fuel.
Purchased power expense increased $70 million (21.9 percent) to meet higher
energy demands and power marketing activities. The majority of the energy
purchased for power marketing activities was resold to non-affiliated third
parties and had no significant effect on net income. In June 1998, the Company
began purchasing capacity and energy from a 300 megawatt cogeneration facility
pursuant to a 30-year purchase power agreement. Purchased power expense
decreased $66 million (17.1 percent) in 1997 primarily due to decreased
purchases from affiliated companies and declines in contractual capacity buyback
purchases from the co-owners of Plant Vogtle. Under the terms of the 1991 retail
rate order, the costs of declining Plant Vogtle contractual capacity buyback
purchases were levelized over a six-year period ending September 1997. The
levelization is reflected in the amortization of deferred Plant Vogtle costs in
the Statements of Income. See Note 1 to the financial statements under "Plant
Vogtle Phase-In Plans" for additional information.
II-88
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1998 Annual Report
Other operation and maintenance (O&M) expenses, excluding the provision for
separation benefits, increased 15.9 percent primarily due to continuing expenses
related to a new customer service system implemented in January 1998,
modification of certain information systems for year 2000 compliance discussed
below, an increase in outage costs at steam power generating facilities, and
increased line maintenance. Other O&M expenses, excluding the provision for
separation benefits, decreased 4.1 percent in 1997 primarily due to initiatives
in 1996 to reduce fossil generation materials inventory levels and an adjustment
in 1996 to deferred postretirement benefits to reflect changes in the retiree
benefits plan.
Depreciation and amortization increased $191 million in 1998 and $140
million in 1997 primarily due to accelerated depreciation of generating plant
pursuant to the retail accounting order and an increase in plant-in-service. See
Note 3 to the financial statements under "Retail Rate Order" for additional
information.
The Company has deferred certain expenses and recorded a deferred return
related to Plant Vogtle under phase-in plans. The amortization of deferred Plant
Vogtle costs reflects the completion in September 1997 of the amortization of
the levelized buybacks and the Plant Vogtle Unit 1 cost deferrals under a 1987
GPSC order. In December 1998, the remaining Vogtle Unit 2 cost deferrals were
fully amortized to expense under a 1998 retail rate order. See Note 1 to the
financial statements under "Plant Vogtle Phase-In Plans" for information
regarding the deferral and subsequent amortization of costs related to Plant
Vogtle.
Additionally, as a result of the 1998 retail rate order, the Company
recorded a $34 million pre-tax write-off associated with a portion of its
investment in the Rocky Mountain plant. See Note 3 to the financial statements
under "Rocky Mountain Plant Status" for additional information.
Other income (expense) increased in 1998 primarily due to the recognition of
$73 million in interest income resulting from the resolution of tax issues with
the Internal Revenue Service (IRS) and the State of Georgia. Other income
(expense) increased in 1997 primarily due to increased tax benefits from losses
of the parent company allocated to the Company under the joint consolidated
income tax agreement between Southern Company and its subsidiaries. See Note 8
to the financial statements for additional information.
Total financing costs decreased in 1998 and 1997. These changes were
primarily due to the refinancing or retirement of securities. The Company
refinanced or retired $754 million and $701 million of securities in 1998 and
1997, respectively. Dividends on preferred stock decreased $13 million and $26
million in 1998 and 1997, respectively. These decreases were partially offset by
increases in interest and other charges of $6 million and $17 million in 1998
and 1997, respectively, primarily due to the issuance of additional mandatorily
redeemable preferred securities in 1996 and 1997.
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 utility plants with long economic life. 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 securities. 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 regulatory matters and energy sales.
The Company currently operates as a vertically integrated utility providing
electricity to customers within its traditional service area located in the
state of Georgia. Prices for electricity provided by the Company to retail
customers are set by the GPSC under cost-based regulatory principles.
II-89
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1998 Annual Report
On January 1, 1999, the Company began operating under a new three-year
retail rate order approved by the GPSC on December 18, 1998. The Company's
earnings will continue to be evaluated against a retail return on common equity
range of 10 percent to 12.5 percent, with rate reductions of $262 million in
1999 and an additional reduction of $24 million in 2000. The order provides for
$85 million in each year, plus up to $50 million of any earnings in excess of
the 12.5 percent return during the second and third years, to be applied to
accelerated amortization or depreciation of assets. Two-thirds of any additional
earnings in excess of the 12.5 percent return will be applied to rate
reductions, with the remaining one-third retained by the Company. The Company
will not file for a general base rate increase unless its projected retail
return on common equity falls below 10 percent, and will be required to file a
general rate case on July 1, 2001 in response to which the GPSC would be
expected to determine whether the rate order should be continued, modified, or
discontinued. See Note 3 to the financial statements under "Retail Rate Order"
for additional information.
Under a previous three-year accounting order ending December 1998, the
Company's earnings were evaluated against a retail return on common equity range
of 10 percent to 12.5 percent. Earnings in excess of 12.5 percent were used to
accelerate the amortization of regulatory assets or depreciation of electric
plant.
As a result of the Company recognizing the write-off of a portion of its
cost in the Rocky Mountain plant and completing the amortization of deferred
Plant Vogtle costs in 1998 in accordance with the new retail rate order, future
depreciation and amortization will decrease. Future depreciation and
amortization will also decrease as a result of the cap on the amount of
accelerated amortization or depreciation of assets under the new retail rate
order. See Note 3 to the financial statements under "Retail Rate Order" for
additional information.
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, initiatives to increase sales to existing customers, 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 1999 through 2001.
In September 1998, OPC decreased its purchases of capacity under a power
supply agreement by 250 megawatts and has notified the Company of its intent to
decrease purchases of capacity by an additional 250 megawatts in September 1999
and 125 megawatts in September 2000. As a result, the Company's capacity
revenues from OPC will decline by approximately $23 million in 1999, an
additional $19 million in 2000, and an additional $4 million in 2001. Under the
amended 1995 Integrated Resource Plan approved by the GPSC in March 1997, the
resources associated with the decreased purchases in 1998 will be used to meet
the needs of the Company's retail customers through 2004. See Note 3 to the
financial statements under "FERC Review of Equity Returns" for additional
information about other wholesale regulatory matters.
The Company has entered into a five-year purchase power agreement scheduled
to begin in June 2000 for approximately 215 megawatts. Capacity and fixed O&M
payments are estimated to be between $7 million and $8 million each year.
The Company plans to construct an eight unit, 600-megawatt combustion
turbine peaking power plant that will begin operation in 2000 and will serve the
wholesale market. The plant will supply power to fulfill a contract for 400
megawatts of peaking power already established with the Company. The addition of
this facility will increase related O&M and depreciation expenses for the
Company. Because the plant will be dedicated to the wholesale market, retail
rates will not be affected. The Company may expand the facility to a total of
1,200 to 1,900 megawatts of capacity over the next two to three years in order
to meet additional anticipated wholesale power demand.
Compliance costs related to current and future environmental laws and
regulations could affect earnings if such costs are not fully recovered. The
Clean Air Act and other important environmental items are discussed further
under "Environmental Issues."
II-90
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1998 Annual Report
The electric utility industry in the United States is currently undergoing a
period of dramatic change as a result of regulatory and competitive factors.
Among the primary agents of change has been the Energy Policy Act of 1992
(Energy Act). The Energy Act allows independent power producers (IPPs) to access
a utility's transmission network in order to sell electricity to other
utilities. This enhances the incentive for IPPs to build cogeneration plants for
a utility's large industrial and commercial customers and sell electric energy
to other utilities. Also, electricity sales for resale rates are being driven
down by wholesale transmission access and numerous potential new energy
suppliers, including power marketers and brokers. The Company is aggressively
working to maintain and expand its share of wholesale sales in the Southeastern
power markets. Although the Energy Act does not permit retail customer access,
it was a major catalyst for the current restructuring and consolidation taking
place within the utility industry.
The Company continues to compete with other electric suppliers within the
state. In Georgia, most new retail customers with at least 900 kilowatts of
connected load may choose their electricity supplier. Numerous federal and state
initiatives are in varying stages to promote wholesale and retail competition
across the nation. Among other things, these initiatives allow customers to
choose their electricity provider. As these initiatives materialize, the
structure of the utility industry could radically change. Some states have
approved initiatives that result in a separation of the ownership and/or
operation of generating facilities from the ownership and/or operation of
transmission and distribution facilities. While the GPSC has held workshops to
discuss retail competition and industry restructuring, there has been no
proposed or enacted legislation to date in Georgia. Enactment would require
numerous issues to be resolved, including significant ones relating to
transmission pricing and recovery of costs. The GPSC plans to release a schedule
and procedure order for a stranded costs docket in the first half of 1999. The
ability of the Company to recover all its costs, including the regulatory assets
described in Note 1 to the financial statements, could have a material effect on
the financial condition of the Company. The Company is attempting to reduce
regulatory assets and other costs through the three-year retail rate order. See
Note 3 to the financial statements under "Retail Rate Order" for additional
information.
Unless the Company remains a low-cost producer and provides quality service,
the Company's retail energy sales growth could be limited as competition
increases. Conversely, continuing to be a low-cost producer could provide
opportunities to increase market share and profitability in markets that evolve
with changing regulation.
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 that are not specifically recoverable, and
determine if any other assets have been impaired. See Note 1 to the financial
statements under "Regulatory Assets and Liabilities" for additional information.
The staff of the Securities and Exchange Commission has questioned certain
of the current accounting practices of the electric utility industry - including
the Company's - regarding the recognition, measurement, and classification of
decommissioning costs for nuclear generating facilities in the financial
statements. In response to these questions, the FASB has decided to review the
accounting for liabilities related to the retirement of long-lived assets,
including nuclear decommissioning. If the FASB issues new accounting rules, the
estimated costs of retiring the Company's nuclear and other facilities may be
required to be recorded as liabilities in the Balance Sheets. Also, the annual
provisions for such costs could change. Because of the Company's current ability
to recover asset retirement costs through rates, these changes would not have a
significant adverse effect on results of operations. See Note 1 to the financial
statements under "Depreciation and Nuclear Decommissioning" for additional
information.
II-91
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1998 Annual Report
Year 2000
Year 2000 Challenge
In order to save storage space, computer programmers in the 1960s and 1970s
shortened the year portion of date entries to just two digits. Computers
assumed, in effect, that all years began with "19." This practice was widely
adopted and hard-coded into computer chips and processors found in some
equipment. This approach, intended to save processing time and storage space,
was used until the mid-1990s. Unless corrected before the year 2000, affected
software systems and devices containing a chip or microprocessor with date and
time functions could incorrectly process dates or the systems may cease to
function.
The Company depends on complex computer systems for many aspects of its
operations, which include generation, transmission, and distribution of
electricity, as well as other business support activities. The Company's goal is
to have critical devices or software that are required to maintain operations to
be Year 2000 ready by June 1999. Year 2000 ready means that a system or
application is determined suitable for continued use through the Year 2000 and
beyond. Critical systems include, but are not limited to, reactor control
systems, safe shutdown systems, turbine generator systems, control center
computer systems, customer service systems, energy management systems, and
telephone switches and equipment.
Year 2000 Program and Status
The Company's executive management recognizes the seriousness of the Year 2000
challenge and has dedicated what it believes to be adequate resources to address
the issue. The Millennium Project is a team of employees, IBM consultants, and
other contractors whose progress is reviewed on a monthly basis by a steering
committee of Southern Company executives.
The Company's Year 2000 program was divided into two phases. Phase I began
in 1996 and consisted of identifying and assessing corporate assets related to
software systems and devices that contain a computer chip or clock. The first
phase was completed in June 1997. Phase 2 consists of testing and remediating
high priority systems and devices. Also, contingency planning is included in
this phase. Completion of Phase 2 is targeted for June 1999. The Millennium
Project will continue to monitor the affected computer systems, devices, and
applications into the year 2000.
The Southern Company has completed more than 70 percent of the activities
contained in its work plan. The percentage of completion and projected
completion by function are as follows:
- - - - - - - ------------------------------------------------------------------------------
Work Plan
----------------------------------------------------
Remediation Project
Inventory Assessment Testing Completion
- - - - - - - -----------------------------------------------------------------------------
Generation 100% 100% 70% 6/99
- - - - - - - -----------------------------------------------------------------------------
Energy Management 100 100 90 6/99
- - - - - - - -----------------------------------------------------------------------------
Transmission and
Distribution 100 100 100 1/99
- - - - - - - -----------------------------------------------------------------------------
Telecommunications 100 100 50 6/99
- - - - - - - -----------------------------------------------------------------------------
Corporate Applications 100 100 90 3/99
- - - - - - - -----------------------------------------------------------------------------
Year 2000 Costs
Current projected total costs for Year 2000 readiness, including the Company's
share of costs of Southern Nuclear Operating Company, are approximately $38
million. These costs include labor necessary to identify, test, and renovate
affected devices and systems. From its inception through December 31, 1998, the
Year 2000 program costs, recognized as expense, amounted to $27 million.
Year 2000 Risks
The Company is implementing a detailed process to minimize the possibility of
service interruptions related to the Year 2000. The Company believes, based on
current tests, that the system can provide customers with electricity. These
tests increase confidence, but do not guarantee error-free operation. The
Company is taking what it believes to be prudent steps to prepare for the Year
2000, and it expects any interruptions in service that may occur within the
service territory to be isolated and short in duration.
The Company expects the risks associated with Year 2000 to be no more severe
than the scenarios that its electric system is routinely prepared to handle. The
most likely worst case scenario consists of the service loss of one of the
largest generating units and/or the service loss of any single bulk transmission
element in its service territory. The Company has followed a proven methodology
II-92
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1998 Annual Report
for identifying and assessing software and devices containing potential Year
2000 challenges. Remediation and testing of those devices are in progress.
Following risk assessment, the Company is preparing contingency plans as
appropriate and is participating in North American Electric Reliability Council
- - - - - - - - coordinated national drills during 1999.
The Company is currently reviewing the Year 2000 readiness of material third
parties that provide goods and services crucial to the Company's operations.
Among such critical third parties are fuel, transportation, telecommunications,
water, chemical, and other suppliers. Contingency plans based on the assessment
of each third party's ability to continue supplying critical goods and services
to the Company are being developed.
There is a potential for some earnings erosion caused by reduced electrical
demand by customers because of their Year 2000 issues.
Year 2000 Contingency Plans
Because of experience with hurricanes and other storms, the Company is skilled
at developing and using contingency plans in unusual circumstances. As part of
Year 2000 business continuity and contingency planning, the Company is drawing
on that experience to make risk assessments and is developing additional plans
to deal specifically with situations that could arise relative to Year 2000
challenges. The Company is identifying critical operational locations, and key
employees will be on duty at those locations during the Year 2000 transition. In
September 1999, drills are scheduled to be conducted to test contingency plans.
Because of the level of detail of the contingency planning process, management
feels that the contingency plans will keep any service interruptions that may
occur within the service territory isolated and short in duration.
Exposure to Market Risks
Due to cost-based rate regulation, the Company has limited exposure to market
volatility in interest rates and prices of electricity. To mitigate residual
risks relative to movements in electricity prices, the Company enters into fixed
price contracts for the purchase and sale of electricity through the wholesale
electricity market. Realized gains and losses are recognized in the income
statement as incurred. At December 31, 1998, exposure from these activities was
not material to the Company's financial position, results of operations, or cash
flows. Also, based on the Company's overall interest rate exposure at December
31, 1998, a near-term 100 basis point change in interest rates would not
materially affect the financial statements.
New Accounting Standards
The FASB has issued Statement No. 133, Accounting for Derivative Instruments and
Hedging Activities, which must be adopted by the year 2000. This statement
establishes accounting and reporting standards for derivative instruments -
including certain derivative instruments embedded in other contracts - and for
hedging activities. The Company has not yet quantified the impact of adopting
this statement on its financial statements; however, the adoption could increase
volatility in earnings.
In March 1998, the American Institute of Certified Public Accountants (AICPA)
issued a new Statement of Position, Accounting for the Costs of Computer
Software Developed or Obtained for Internal Use. This statement requires
capitalization of certain costs of internal-use software. The Company adopted
this statement in January 1999, and it is not expected to have a material impact
on the financial statements.
In April 1998, the AICPA issued a new Statement of Position, Reporting on the
Costs of Start-up Activities. This statement requires that the costs of start-up
activities and organizational costs be expensed as incurred. Any of these costs
previously capitalized by a company must be written off in the year of adoption.
The Company adopted this statement in January 1999, and it is not expected to
have a material impact on the financial statements.
In December 1998, the Emerging Issues Task Force (EITF) of the FASB issued
EITF No. 98-10, Accounting for Contracts Involved in Energy Trading and Risk
Management Activities. The EITF requires that energy trading contracts must be
marked to market through the income statement, with gains and losses reflected
rather than revenues and purchased power. Energy trading contracts are defined
II-93
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1998 Annual Report
as energy contracts entered into with the objective of generating profits on or
from exposure to shifts or changes in market prices. The Company adopted the
required accounting in January 1999, and it is not expected to have a material
impact on the financial statements.
FINANCIAL CONDITION
Plant Additions
In 1998 gross utility plant additions were $499 million. These additions were
primarily related to transmission and distribution facilities and to the
purchase of nuclear fuel. The funds needed for gross property additions are
currently provided from operations. The Statements of Cash Flows provide
additional details.
Financing Activities
In 1998 the Company continued to lower its financing costs by refinancing
higher-cost issues. New issues during 1996 through 1998 totaled $1.6 billion and
retirement or repayment of securities totaled $2.0 billion. Composite financing
rates for long-term debt and preferred stock for the years 1996 through 1998, as
of year-end, were as follows:
1998 1997 1996
----------------------------------
Composite interest rate
on long-term debt 5.64% 6.11% 6.39%
Composite preferred
stock dividend rate 5.52 5.18 6.34
- - - - - - - ------------------------------------------------------------------
Subsidiaries of the Company have issued mandatorily redeemable preferred
securities. See Note 9 to the financial statements under "Preferred Securities"
for additional information.
Liquidity and Capital Requirements
Cash provided from operations increased by $30 million in 1998, primarily due to
higher retail revenues.
The Company estimates that construction expenditures for the years 1999
through 2001 will total $755 million, $734 million and $829 million,
respectively. Investments in additional combustion turbine and combined cycle
generating units, transmission and distribution facilities, enhancements to
existing generating plants, and equipment to comply with environmental
requirements are planned.
Cash requirements for improvement fund requirements, redemptions announced,
and maturities of long-term debt and preferred stock are expected to total $601
million during 1999 through 2001.
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. The amount to be funded is $24 million in 1999 and
increases to $30 million in 2000 and 2001. For additional information concerning
nuclear decommissioning costs, see Note 1 to the financial statements under
"Depreciation and Nuclear Decommissioning."
Sources of Capital
The Company expects to meet future capital requirements primarily using funds
generated from operations and, if needed, by the issuance of new debt and equity
securities, term loans, and short-term borrowings. To meet short-term cash needs
and contingencies, the Company had approximately $1.3 billion of unused credit
arrangements with banks at the beginning of 1999. See Note 9 to the financial
statements under "Bank Credit Arrangements" for additional information.
The Company historically has relied on issuances of first mortgage bonds and
preferred stock, in addition to pollution control revenue bonds issued for its
benefit by public authorities, to meet its long-term external financing
requirements. Recently, the Company's financings have consisted of unsecured
debt and trust preferred securities. In this regard, the Company sought and
obtained stockholder approval in 1997 to amend its corporate charter eliminating
restrictions on the amounts of unsecured indebtedness it may incur.
If the Company chooses to issue first mortgage bonds or preferred stock, it
is required to meet certain coverage requirements specified in its mortgage
indenture and corporate charter. 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.
II-94
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1998 Annual Report
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 -- significantly
impacted the operating companies of Southern Company, including Georgia Power.
Specific reductions in sulfur dioxide and nitrogen oxide emissions from
fossil-fired generating plants are required in two phases. Phase I compliance
began in 1995 and initially affected 28 generating units in the Southern
electric system. As a result of Southern Company's compliance strategy, an
additional 22 generating units were brought into compliance with Phase I
requirements. Phase II compliance is required in 2000, and all fossil-fired
generating plants in the Southern electric system will be affected.
Southern Company achieved Phase I sulfur dioxide compliance at the affected
units by switching to low-sulfur coal, which required some equipment upgrades.
Construction expenditures for Georgia Power's Phase I compliance totaled
approximately $167 million.
For Phase II sulfur dioxide compliance, Southern Company could use emission
allowances, increase fuel switching, and/or install flue gas desulfurization
equipment at selected plants. Also, equipment to control nitrogen oxide
emissions will be installed on additional system fossil-fired units as necessary
to meet Phase II limits and ozone non-attainment requirements for metropolitan
Atlanta through 2000. Georgia Power's current compliance strategy for Phase II
and ozone non-attainment could require total estimated construction expenditures
of approximately $39 million, of which $14 million remains to be spent as of
December 31, 1998.
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.
In July 1997, the Environmental Protection Agency (EPA) revised the national
ambient air quality standards for ozone and particulate matter. This revision
makes the standards significantly more stringent. In September 1998, the EPA
issued the final regional nitrogen oxide rules to the states for implementation.
The states have one year to adopt and implement the new rules. The final rules
affect 22 states including Georgia. The EPA rules are being challenged in the
courts by several states and industry groups. Implementation of the final state
rules could require substantial further reductions in nitrogen oxide emissions
from fossil-fired generating facilities and other industry in these states.
Implementation of the standards could result in significant additional
compliance costs and capital expenditures that cannot be determined until the
results of legal challenges are known and the states have adopted their final
rules.
The EPA and state environmental regulatory agencies are reviewing and
evaluating various matters including: nitrogen oxide emission control strategies
for ozone non-attainment areas; additional controls for hazardous air pollutant
emissions; control strategies to reduce regional haze; and hazardous waste
disposal requirements. The impact of new standards will depend on the
development and implementation of applicable regulations.
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 $6 million, $4
million and $2 million, in 1998, 1997 and 1996, respectively. Additional sites
may require environmental remediation for which the Company may be liable for a
portion of or all required clean-up costs. See Note 3 to the financial
statements under "Certain Environmental Contingencies" for information regarding
the Company's potentially responsible party status at a site in Brunswick,
Georgia, and the status of sites listed on the State of Georgia's hazardous site
inventory.
Several major pieces of environmental legislation are being considered for
reauthorization or amendment by Congress. These include: the Clean Air Act; the
Clean Water Act; the Comprehensive Environmental Response, Compensation, and
Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances
Control Act; and the Endangered Species Act. Changes to these laws could affect
many areas of the Company's operations. The full impact of any such changes
cannot be determined at this time.
II-95
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1998 Annual Report
Compliance with possible additional legislation related to global climate
change, electromagnetic fields and other environmental and health concerns could
significantly affect the Company. The impact of new legislation -- if any --
will depend on the subsequent development and implementation of applicable
regulations. In addition, the potential exists for liability as the result of
lawsuits alleging damages caused by electromagnetic fields.
Cautionary Statement Regarding Forward-Looking
Information
The Company's 1998 Annual Report contains forward-looking and historical
information. The Company cautions that there are various important factors that
could cause actual results to differ materially from those indicated in the
forward-looking information; accordingly, there can be no assurance that such
indicated results will be realized. These factors include legislative and
regulatory initiatives regarding deregulation and restructuring of the electric
utility industry; the extent and timing of the entry of additional competition
in the Company's markets; potential business strategies -- including
acquisitions or dispositions of assets or internal restructuring -- that may be
pursued by Southern Company; state and federal rate regulation; Year 2000
issues; changes in or application of environmental and other laws and
regulations to which the Company is subject; political, legal and economic
conditions and developments; financial market conditions and the results of
financing efforts; changes in commodity prices and interest rates; weather and
other natural phenomena; and other factors discussed in the reports--including
Form 10-K--filed from time to time by the Company with the Securities and
Exchange Commission.
II-96
STATEMENTS OF INCOME
For the Years Ended December 31, 1998, 1997, and 1996
Georgia Power Company 1998 Annual Report
===============================================================================================================================
1998 1997 1996
- - - - - - - -------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Revenues:
Revenues $ 4,656,647 $ 4,347,009 $ 4,380,893
Revenues from affiliates 81,606 38,708 35,886
- - - - - - - -------------------------------------------------------------------------------------------------------------------------------
Total operating revenues 4,738,253 4,385,717 4,416,779
- - - - - - - -------------------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation--
Fuel 917,119 857,269 835,194
Purchased power from non-affiliates 229,960 143,409 157,308
Purchased power from affiliates 161,003 177,240 229,324
Provision for separation benefits 2,369 5,459 39,099
Other 817,220 696,700 741,383
Maintenance 358,218 317,199 315,934
Depreciation and amortization 763,390 572,640 432,940
Amortization of deferred Plant Vogtle costs (Note 1) 50,412 120,577 136,650
Write-down of Rocky Mountain plant (Note 3) 33,536 - -
Taxes other than income taxes 204,623 207,192 207,098
Federal and state income taxes 406,983 426,918 435,904
- - - - - - - -------------------------------------------------------------------------------------------------------------------------------
Total operating expenses 3,944,833 3,524,603 3,530,834
- - - - - - - -------------------------------------------------------------------------------------------------------------------------------
Operating Income 793,420 861,114 885,945
Other Income (Expense):
Allowance for equity funds used during construction 3,235 6,012 3,144
Equity in earnings of unconsolidated subsidiary (Note 4) 3,735 4,266 3,851
Interest income (Note 3) 79,578 10,581 5,333
Other, net (41,512) (35,834) (43,502)
Income taxes applicable to other income 8,351 31,763 18,581
- - - - - - - -------------------------------------------------------------------------------------------------------------------------------
Income Before Interest and Other Charges 846,807 877,902 873,352
- - - - - - - -------------------------------------------------------------------------------------------------------------------------------
Interest and Other Charges:
Interest on long-term debt 180,746 194,344 207,851
Allowance for debt funds used during construction (7,117) (8,962) (11,416)
Interest on interim obligations 12,213 7,795 15,478
Amortization of debt discount, premium and expense, net 13,366 14,179 14,790
Other interest charges 17,105 10,254 6,338
Distributions on preferred securities of subsidiary companies 54,327 47,369 14,958
- - - - - - - -------------------------------------------------------------------------------------------------------------------------------
Interest and other charges, net 270,640 264,979 247,999
- - - - - - - -------------------------------------------------------------------------------------------------------------------------------
Net Income 576,167 612,923 625,353
Dividends on Preferred Stock 5,939 18,927 45,026
- - - - - - - -------------------------------------------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred Stock $ 570,228 $ 593,996 $ 580,327
===============================================================================================================================
The accompanying notes are an integral part of these statements.
II-97
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1998, 1997, and 1996
Georgia Power Company 1998 Annual Report
==========================================================================================================================
1998 1997 1996
- - - - - - - --------------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Activities:
Net income $ 576,167 $ 612,923 $ 625,353
Adjustments to reconcile net income to net
cash provided from operating activities --
Depreciation and amortization 867,637 674,286 521,086
Deferred income taxes and investment tax credits, net (93,005) (21,425) 35,700
Allowance for equity funds used during construction (3,235) (6,012) (3,144)
Amortization of deferred Plant Vogtle costs 50,412 120,577 136,650
Other, net (6,546) 2,076 45,255
Changes in certain current assets and liabilities --
Receivables, net (25,453) 13,387 9,421
Inventories (11,156) 39,748 55,753
Payables 47,862 (10,007) (35,651)
Taxes accrued 22,139 (3,596) 11,766
Energy cost recovery, retail (7,649) (20,103) 679
Other (15,142) (30,026) (15,880)
- - - - - - - --------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities 1,402,031 1,371,828 1,386,988
- - - - - - - --------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (499,053) (475,921) (428,220)
Other 67,031 16,223 (13,149)
- - - - - - - --------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities (432,022) (459,698) (441,369)
- - - - - - - --------------------------------------------------------------------------------------------------------------------------
Financing Activities:
Proceeds --
Preferred securities - 364,250 225,000
First mortgage bonds - - 10,000
Pollution control bonds 89,990 284,700 112,825
Senior notes 495,000 - -
Retirements --
Preferred stock (106,064) (356,392) (179,148)
First mortgage bonds (558,250) (60,258) (210,860)
Pollution control bonds (89,990) (284,700) (119,665)
Interim obligations, net (25,378) (64,266) 30,166
Special deposits -- redemption funds - 44,454 (44,454)
Capital distribution to parent company (270,000) (205,000) (250,000)
Payment of preferred stock dividends (9,137) (26,917) (46,911)
Payment of common stock dividends (536,600) (520,000) (475,500)
Miscellaneous (26,641) (20,024) (10,646)
- - - - - - - --------------------------------------------------------------------------------------------------------------------------
Net cash used for financing activities (1,037,070) (844,153) (959,193)
- - - - - - - --------------------------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents (67,061) 67,977 (13,574)
Cash and Cash Equivalents at Beginning of Year 83,333 15,356 28,930
- - - - - - - --------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 16,272 $ 83,333 $ 15,356
==========================================================================================================================
Supplemental Cash Flow Information:
Cash paid during the year for --
Interest (net of amount capitalized) $ 269,524 $ 258,298 $ 249,434
Income taxes (net of refunds) 480,318 427,596 373,886
- - - - - - - --------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
II-98
BALANCE SHEETS
At December 31, 1998 and 1997
Georgia Power Company 1998 Annual Report
================================================================================================================================
ASSETS 1998 1997
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Utility Plant:
Plant in service $ 15,441,146 $ 15,082,570
Less accumulated provision for depreciation 6,109,331 5,319,680
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
9,331,815 9,762,890
Nuclear fuel, at amortized cost 121,169 126,882
Construction work in progress (Note 4) 189,849 214,128
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Total 9,642,833 10,103,900
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Other Property and Investments:
Southern Electric Generating Company, at equity (Note 4) 24,360 24,973
Nuclear decommissioning trusts, at market 284,536 194,417
Miscellaneous 34,781 87,907
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Total 343,677 307,297
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Current Assets:
Cash and cash equivalents 16,272 83,333
Receivables--
Customer accounts receivable 439,420 385,844
Other accounts and notes receivable 99,574 110,278
Affiliated companies 16,817 20,333
Accumulated provision for uncollectible accounts (5,500) (3,000)
Fossil fuel stock, at average cost 104,133 96,067
Materials and supplies, at average cost 243,477 240,387
Prepayments 29,670 27,503
Vacation pay deferred 43,610 40,996
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Total 987,473 1,001,741
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets:
Deferred charges related to income taxes (Note 8) 604,488 688,472
Deferred Plant Vogtle costs (Note 1) - 50,412
Premium on reacquired debt, being amortized 173,858 166,609
Prepaid pension costs 103,606 67,777
Debt expense, being amortized 51,261 40,927
Miscellaneous 126,422 146,593
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Total 1,059,635 1,160,790
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Total Assets $ 12,033,618 $ 12,573,728
================================================================================================================================
The accompanying notes are an integral part of these statements.
II-99
BALANCE SHEETS (continued)
At December 31, 1998 and 1997
Georgia Power Company 1998 Annual Report
=================================================================================================================================
CAPITALIZATION AND LIABILITIES 1998 1997
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Capitalization (See accompanying statements):
Common stock equity $ 3,784,172 $ 4,019,728
Preferred stock 15,527 157,247
Company obligated mandatorily redeemable preferred securities
of subsidiaries substantially all of whose assets are junior
subordinated debentures or notes (Note 9) 689,250 689,250
Long-term debt 2,744,362 2,982,835
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Total 7,233,311 7,849,060
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Current Liabilities:
Preferred stock due within one year (Note 9) 35,656 -
Long-term debt due within one year (Note 9) 399,429 220,855
Notes payable to banks (Note 9) 117,634 142,300
Commercial paper (Note 9) 223,218 223,930
Accounts payable--
Affiliated companies 75,774 71,373
Other 326,317 261,293
Customer deposits 69,584 68,618
Taxes accrued--
Federal and state income 15,801 4,480
Other 122,359 111,541
Interest accrued 60,187 72,437
Miscellaneous 100,793 105,683
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Total 1,546,752 1,282,510
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes (Note 8) 2,249,613 2,417,547
Accumulated deferred investment tax credits 381,914 397,202
Deferred credits related to income taxes (Note 8) 284,017 297,560
Employee benefits provisions 177,148 169,887
Miscellaneous 160,863 159,962
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Total 3,253,555 3,442,158
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Commitments and Contingent Matters (Notes 1 through 7)
Total Capitalization and Liabilities $ 12,033,618 $ 12,573,728
================================================================================================================================
The accompanying notes are an integral part of these statements.
II-100
STATEMENTS OF CAPITALIZATION
At December 31, 1998 and 1997
Georgia Power Company 1998 Annual Report
==================================================================================================================================
1998 1997 1998 1997
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------------
(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 1,660,206 1,929,971
Premium on preferred stock 158 160
Retained earnings (See accompanying statement) (Note 9) 1,779,558 1,745,347
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------------
Total common stock equity 3,784,172 4,019,728 52.3 % 51.2 %
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------------
Cumulative Preferred Stock, without par value:
Authorized -- 55,000,000 shares
Outstanding -- 511,834 shares at December 31, 1998
Outstanding -- 4,719,226
shares at December 31, 1997
$100 stated value --
4.60% to 6.60% 51,183 52,355
Adjustable rate -- at January 1, 1998:
4.85% - 64,213
5.27% - 40,679
- - - - - - - --------------------------------------------------------------------------------------------------------------
Total cumulative preferred stock (annual dividend
requirement -- $2,827,000) 51,183 157,247
Less amount due within one year (Note 9) 35,656 -
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------------
Cumulative preferred stock excluding amount due within one year 15,527 157,247 0.2 2.0
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------------
Company Obligated Mandatorily
Redeemable Preferred Securities (Note 9):
$25 liquidation value -- 9% 100,000 100,000
$25 liquidation value -- 7.75% 225,000 225,000
$25 liquidation value -- 7.60% 175,000 175,000
$25 liquidation value -- 7.75% 189,250 189,250
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------------
Total (annual distribution requirement -- $54,404,000) 689,250 689,250 9.5 8.8
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------------
Long-Term Debt:
First mortgage bonds --
Maturity Interest Rates
April 1, 1998 5 1/2% - 100,000
September 1, 1999 6 1/8% 195,000 195,000
March 1, 2000 6% 100,000 100,000
October 1, 2000 7% - 100,000
September 1, 2002 6 7/8% - 150,000
April 1, 2003 6 5/8% 200,000 200,000
August 1, 2003 6.35% 75,000 75,000
2004 through 2006 6.07% 10,000 10,000
2008 6 7/8% 50,000 50,000
2023 through 2025 7.55% to 7.95% 266,000 474,250
- - - - - - - ---------------------------------------------------------------------------------------------------------------
Total first mortgage bonds 896,000 1,454,250
- - - - - - - ---------------------------------------------------------------------------------------------------------------
Pollution control bonds -- (Note 9)
Maturity Interest Rates
-------- --------------
2000 4.375% 50,000 50,000
2004-2005 5% to 5.375% 57,000 103,790
2011 Variable (4.0% at 1/1/99) 10,450 10,450
2018 6% 4,600 26,700
2019-2023 5.75% to 6.35% 140,560 144,660
2022-2023 Variable (4.0% to 5.05% at 1/1/99) 64,500 64,500
2024-2025 5.4% to 6.75% 440,325 457,325
2024-2028 Variable (3.10% to 5.20% at 1/1/99) 619,055 529,065
2029-2033 Variable (3.25% to 5.15% at 1/1/99) 234,700 234,700
2034 Variable (3.25% at 1/1/99) 50,000 50,000
- - - - - - - ---------------------------------------------------------------------------------------------------------------
Total pollution control bonds 1,671,190 1,671,190
- - - - - - - ---------------------------------------------------------------------------------------------------------------
II-101
STATEMENTS OF CAPITALIZATION (continued)
At December 31, 1998 and 1997
Georgia Power Company 1998 Annual Report
===================================================================================================================================
1998 1997 1998 1997
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
Senior notes -- (Note 9)
Maturity Interest Rates
-------- --------------
December 1, 2005 5.50% 150,000 -
December 31, 2038 6.60% 200,000 -
December 31, 2047 6.875% 145,000 -
- - - - - - - ---------------------------------------------------------------------------------------------------------------
Total senior notes 495,000 -
- - - - - - - ---------------------------------------------------------------------------------------------------------------
Other long-term debt (Note 9) 86,280 86,675
Unamortized debt discount, net (4,679) (8,425)
- - - - - - - ---------------------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
requirement -- $177,628,000) 3,143,791 3,203,690
Less amount due within one year (Note 9) 399,429 220,855
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------------
Long-term debt excluding amount due within one year 2,744,362 2,982,835 38.0 38.0
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------------
Total Capitalization $ 7,233,311 $ 7,849,060 100.0 % 100.0 %
===================================================================================================================================
The accompanying notes are an integral part of these statements.
II-102
STATEMENTS OF RETAINED EARNINGS
For the Years Ended December 31, 1998, 1997, and 1996
Georgia Power Company 1998 Annual Report
==================================================================================================================================
1998 1997 1996
- - - - - - - ----------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Balance at Beginning of Period $ 1,745,347 $ 1,674,774 $ 1,569,905
Net income after dividends on preferred stock 570,228 593,996 580,327
Cash dividends on common stock (536,600) (520,000) (475,500)
Preferred stock transactions, net 583 (3,423) 42
- - - - - - - ----------------------------------------------------------------------------------------------------------------------------------
Balance at End of Period (Note 9) $ 1,779,558 $ 1,745,347 $ 1,674,774
==================================================================================================================================
STATEMENTS OF PAID-IN CAPITAL
For the Years Ended December 31, 1998, 1997, and 1996
Georgia Power Company 1998 Annual Report
==================================================================================================================================
1998 1997 1996
- - - - - - - ----------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Balance at Beginning of Period $ 1,929,971 $ 2,134,886 $ 2,384,444
Capital distribution to parent company (270,000) (205,000) (250,000)
Contributions to capital by parent company 235 85 442
- - - - - - - ----------------------------------------------------------------------------------------------------------------------------------
Balance at End of Period $ 1,660,206 $ 1,929,971 $ 2,134,886
==================================================================================================================================
The accompanying notes are an integral part of these statements.
II-103
NOTES TO FINANCIAL STATEMENTS
Georgia Power Company 1998 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING
POLICIES
General
The Company is a wholly owned subsidiary of Southern Company, which is the
parent company of five operating companies, Southern Company Services (SCS), a
system service company, Southern Communications Services (Southern LINC),
Southern Energy, Inc. (Southern Energy), Southern Nuclear Operating Company
(Southern Nuclear), Southern Company Energy Solutions, and other direct and
indirect subsidiaries. The operating companies (Alabama Power Company, Georgia
Power Company, Gulf Power Company, Mississippi Power Company, and Savannah
Electric and Power Company) provide electric service in four Southeastern
states. Contracts among the operating companies -- dealing with jointly owned
generating facilities, interconnecting transmission lines, and the exchange of
electric power -- are regulated by the Federal Energy Regulatory Commission
(FERC) or the Securities and Exchange Commission (SEC). SCS provides, at cost,
specialized services to Southern Company and subsidiary companies. Southern LINC
provides digital wireless communications services to the operating companies and
also markets these services to the public within the Southeast. Southern Energy
designs, builds, owns, and operates power production and delivery facilities and
provides a broad range of energy related services in the United States and
international markets. Southern Nuclear provides services to Southern Company's
nuclear power plants. Southern Company Energy Solutions develops new business
opportunities related to energy products and services.
Southern Company is registered as a holding company under the Public Utility
Holding Company Act of 1935 (PUHCA). Both Southern Company and its subsidiaries
are subject to the regulatory provisions of this act. The Company is also
subject to regulation by the FERC and the Georgia Public Service Commission
(GPSC). The Company follows generally accepted accounting principles (GAAP) and
complies with the accounting policies and practices prescribed by the respective
regulatory commissions. The preparation of financial statements in conformity
with GAAP requires the use of estimates, and the actual results may differ from
these estimates.
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 expected 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:
1998 1997
----------------------
(in millions)
Deferred income taxes $ 604 $ 688
Deferred income tax credits (284) (298)
Premium on reacquired debt 174 167
Corporate building lease 53 52
Deferred Plant Vogtle costs - 50
Vacation pay 44 41
Postretirement benefits 36 38
Department of Energy assessments 26 29
Deferred nuclear outage costs 24 28
Demand-side program costs - 11
Other, net 12 10
- - - - - - - ---------------------------------------------------------------
Total $ 689 $ 816
===============================================================
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 net regulatory assets and liabilities that are not specifically
recoverable through regulated rates. In addition, the Company would be required
to determine if any impairment to other assets exists, including plant, and
write down the assets, if impaired, to their fair value.
11-104
NOTES (continued)
Georgia Power Company 1998 Annual Report
Revenues and Fuel Costs
The Company currently operates as a vertically integrated utility providing
electricity to retail customers within its traditional service area located
within the state of Georgia, and to wholesale customers in the Southeast.
Revenues by type of service were as follows:
1998 1997 1996
--------------------------------
(in millions)
Retail $4,298 $3,978 $4,023
Non-affiliated wholesale 260 283 282
Other 99 86 76
- - - - - - - ---------------------------------------------------------------
Total $4,657 $4,347 $4,381
===============================================================
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
costs, energy component of purchased power costs, and certain other 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. For all periods presented,
uncollectible accounts averaged 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 $74
million in 1998, $76 million in 1997, and $78 million in 1996. The Company has a
contract with the U.S. Department of Energy (DOE) that provides for the
permanent disposal of spent nuclear fuel. The DOE failed to begin disposing of
spent fuel in January 1998 as required by the contracts, and the Company is
pursuing legal remedies against the government for breach of contract.
Sufficient storage capacity currently is available to permit operation into 2003
at Plant Hatch and into 2017 at Plant Vogtle. Plant Vogtle's spent fuel storage
capacity includes the installation in 1998 of additional rack capacity.
Activities for adding dry cask storage capacity at Plant Hatch by as early as
1999 are in progress.
Also, the Energy Policy Act of 1992 required the establishment in 1993 of a
Uranium Enrichment Decontamination and Decommissioning Fund, which is to be
funded in part by a special assessment on utilities with nuclear plants. This
fund will be used by the DOE for the decontamination and decommissioning of its
nuclear fuel enrichment facilities. The assessment will be paid over a 15-year
period, which began in 1993. The law provides that utilities will recover these
payments in the same manner as any other fuel expense. The Company -- based on
its ownership interests -- estimates its remaining liability under this law at
December 31, 1998, to be approximately $24 million. This obligation is recorded
in the accompanying Balance Sheets.
Depreciation and Nuclear Decommissioning
Depreciation of the original cost of depreciable utility plant in service is
provided primarily by using composite straight-line rates, which approximated
3.2 percent in 1998 and 3.1 percent in 1997 and 1996. In addition, the Company
recorded accelerated depreciation of electric plant of $316 million in 1998,
$159 million in 1997, and $24 million in 1996. The amount of such charges in the
accumulated provision for depreciation is $505 million at December 31, 1998. See
Note 3 under "Retail Rate Order" for additional information. When property
subject to depreciation is retired or otherwise disposed of in the normal course
of business, its cost -- together with the cost of removal, less salvage -- is
charged to the accumulated provision for depreciation. Minor items of property
included in the original cost of the plant are retired when the related property
unit is retired. Depreciation expense includes an amount for the expected costs
of decommissioning nuclear facilities and removal of other facilities.
Nuclear Regulatory Commission (NRC) regulations require 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 ordered 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.
11-105
NOTES (continued)
Georgia Power Company 1998 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
its retirement date. The estimated site study costs based on the most current
study and ultimate costs assuming an inflation rate of 3.6% for the Company's
ownership interests are as follows:
Plant Plant
Hatch Vogtle
--------------------
Site study basis (year) 1997 1997
Decommissioning periods:
Beginning year 2014 2027
Completion year 2027 2038
- - - - - - - -------------------------------------------------------------
(in millions)
Site study costs:
Radiated structures $372 $317
Non-radiated structures 33 44
- - - - - - - -------------------------------------------------------------
Total $405 $361
=============================================================
(in millions)
Ultimate costs:
Radiated structures $722 $ 922
Non-radiated structures 65 129
- - - - - - - -------------------------------------------------------------
Total $787 $1,051
=============================================================
The decommissioning cost estimates are based on prompt dismantlement and
removal of the plant from service. The actual decommissioning costs may vary
from the above estimates because of changes in the assumed date of
decommissioning, changes in NRC requirements, changes in the assumptions used in
making estimates, changes in regulatory requirements, changes in technology, and
changes in costs of labor, materials, and equipment.
Annual provisions for nuclear decommissioning expense are based on an
annuity method as approved by the GPSC. The amounts expensed in 1998 and fund
balance as of December 31, 1998 were:
Plant Plant
Hatch Vogtle
- - - - - - - -------------------------------------------------------------
(in millions)
Amount expensed in 1998 $ 11 $ 9
- - - - - - - -------------------------------------------------------------
Accumulated provisions:
Balance in external trust funds $172 $112
Balance in internal reserves 19 12
- - - - - - - -------------------------------------------------------------
Total $191 $124
=============================================================
Effective January 1, 1999, the GPSC increased the annual provision for
decommissioning expenses to $26 million. This amount is based on the NRC generic
estimate to decommission the radioactive portion of the facilities as of 1997 of
$526 million and $438 million for plants Hatch and Vogtle, respectively. The
ultimate costs associated with the 1997 NRC minimum funding requirements are
$1.1 billion and $1.3 billion for plants Hatch and Vogtle, respectively.
Significant assumptions include an estimated inflation rate of 3.6% and an
estimated trust earnings rate of 6.5%. The Company expects the GPSC to
periodically review and adjust, if necessary, the amounts collected in rates for
the anticipated cost of decommissioning.
Income Taxes
The Company uses the liability method of accounting for deferred income taxes
and provides deferred income taxes for all significant income tax temporary
differences. Investment tax credits utilized are deferred and amortized to
income over the average lives of the related property.
Plant Vogtle Phase-In Plans
In 1987 and 1989, the GPSC ordered that the allowed costs of Plant Vogtle, a
two-unit nuclear facility of which Georgia Power owns 45.7 percent, be phased
into rates. Pursuant to the orders, the Company recorded a deferred return under
phase-in plans until October 1991 when the allowed investment was fully
reflected in rates. In 1991, the GPSC levelized the remaining Plant Vogtle
declining capacity buyback expenses over a six-year period. In addition, the
Company deferred certain Plant Vogtle operating expenses and financing costs
under accounting orders issued by the GPSC. These GPSC orders provided for the
recovery of deferred costs within 10 years. Costs deferred under the 1987 order
and the levelized buybacks were fully recovered as of September 1997. Under a
December 18, 1998 retail rate order from the GPSC, the remaining deferred costs
were fully amortized to expense in December 1998. See Note 3 under "Retail Rate
Order" for additional information.
Allowance for Funds Used During Construction
(AFUDC)
AFUDC represents the estimated debt and equity costs of capital funds that are
necessary to finance the construction of new facilities. While cash is not
11-106
NOTES (continued)
Georgia Power Company 1998 Annual Report
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 1998, 1997 and 1996, the average AFUDC rates
were 6.71 percent, 7.60 percent and 6.59 percent, respectively. AFUDC, net of
taxes, as a percentage of net income after dividends on preferred stock, was
less than 2.0 percent for 1998, 1997, and 1996.
Utility Plant
Utility plant is stated at original cost, less regulatory disallowances.
Original cost includes: materials; labor; payroll-related costs such as taxes,
pensions, and other benefits; and the cost of funds used during construction.
The cost of maintenance, repairs, and replacement of minor items of property is
charged to maintenance expense. The cost of replacements of property (exclusive
of minor items of property) is charged to utility plant.
Cash and Cash Equivalents
For purposes of the financial statements, temporary cash investments are
considered cash equivalents. Temporary cash investments are securities with
original maturities of 90 days or less.
Financial Instruments
The Company's financial instruments for which the carrying amounts did not
approximate fair value at December 31 were as follows:
Carrying Fair
Amount Value
------------------------
Long-term debt: (in millions)
At December 31, 1998 $3,058 $3,105
At December 31, 1997 3,125 3,170
Preferred securities:
At December 31, 1998 689 716
At December 31, 1997 689 720
- - - - - - - --------------------------------------------------------------
The fair values for securities were based on either closing market prices or
closing prices of comparable instruments.
Materials and Supplies
Generally, materials and supplies include the cost of transmission, distribution
and generating plant materials. Materials are charged to inventory when
purchased and then expensed or capitalized to plant, as appropriate, when
installed.
2. RETIREMENT BENEFITS
The Company has defined benefit, trusteed pension plans that cover substantially
all employees. The Company provides certain medical care and life insurance
benefits for retired employees. Substantially all these employees may become
eligible for such benefits when they retire. The Company funds trusts to the
extent deductible under federal income tax regulations or to the extent required
by the GPSC and FERC. In 1998, the Company adopted FASB Statement No. 132,
Employers' Disclosure about Pensions and Other Postretirement Benefits. The
measurement date is September 30 of each year.
The weighted average rates assumed in the actuarial calculations for both
the pension and postretirement benefit plans were:
1998 1997
- - - - - - - -----------------------------------------------------------------
Discount 6.75% 7.50%
Annual salary increase 4.25 5.00
Expected long-term return on plan
assets 8.50 8.50
- - - - - - - -----------------------------------------------------------------
Pension Plan
Changes during the year in the projected benefit obligations and in the fair
value of plan assets were as follows:
Projected
Benefit Obligations
---------------------------
1998 1997
- - - - - - - ----------------------------------------------------------------
(in millions)
Balance at beginning of year $1,119 $1,172
Service cost 30 30
Interest cost 82 82
Benefits paid (55) (42)
Actuarial (gain) loss and
employee transfers 41 (123)
- - - - - - - ----------------------------------------------------------------
Balance at end of year $1,217 $1,119
================================================================
Plan Assets
---------------------------
1998 1997
- - - - - - - ----------------------------------------------------------------
(in millions)
Balance at beginning of year $1,931 $1,797
Actual return on plan assets 11 338
Benefits paid (55) (42)
Employee transfers (28) (162)
- - - - - - - ----------------------------------------------------------------
Balance at end of year $1,859 $1,931
================================================================
11-107
NOTES (continued)
Georgia Power Company 1998 Annual Report
The accrued pension costs recognized in the Balance Sheets were as
follows:
1998 1997
- - - - - - - ---------------------------------------------------------------
(in millions)
Funded status $ 642 $ 812
Unrecognized transition obligation (35) (39)
Unrecognized prior service cost 45 48
Unrecognized net actuarial gain (548) (753)
- - - - - - - ---------------------------------------------------------------
Prepaid asset recognized in the
Balance Sheets $ 104 $ 68
===============================================================
Components of the plans' net periodic cost were as follows:
1998 1997 1996
- - - - - - - ---------------------------------------------------------------
(in millions)
Service cost $ 30 $ 30 $ 35
Interest cost 82 82 86
Expected return on plan assets (127) (121) (124)
Recognized net actuarial gain (20) (18) (14)
Net amortization (1) (1) (2)
- - - - - - - ---------------------------------------------------------------
Net pension income $ (36) $ (28) $ (19)
===============================================================
Postretirement Benefits
Changes during the year in the projected benefit obligations and
in the fair value of plan assets were as follows:
Projected
Benefit Obligations
---------------------------
1998 1997
- - - - - - - ----------------------------------------------------------------
(in millions)
Balance at beginning of year $ 435 $ 430
Service cost 7 7
Interest cost 32 32
Benefits paid (16) (13)
Actuarial loss and employee
transfers 6 (21)
- - - - - - - ----------------------------------------------------------------
Balance at end of year $ 464 $ 435
================================================================
Plan Assets
---------------------------
1998 1997
- - - - - - - ----------------------------------------------------------------
(in millions)
Balance at beginning of year $122 $112
Actual return on plan assets 4 9
Employer contributions 40 14
Benefits paid (16) (13)
- - - - - - - ----------------------------------------------------------------
Balance at end of year $150 $122
================================================================
The accrued postretirement costs recognized in the Balance
Sheets were as follows:
1998 1997
- - - - - - - ---------------------------------------------------------------
(in millions)
Funded status $ (314) $ (313)
Unrecognized transition obligation 131 139
Unrecognized net actuarial loss 57 47
Fourth quarter contributions 19 29
- - - - - - - ---------------------------------------------------------------
Accrued liability recognized in the
Balance Sheets $ (107) $ (98)
===============================================================
Components of the plans' net periodic cost were as follows:
1998 1997 1996
- - - - - - - ---------------------------------------------------------------
(in millions)
Service cost $ 7 $ 7 $ 9
Interest cost 32 32 30
Expected return on plan assets (9) (7) (5)
Recognized net actuarial loss 1 1 2
Net amortization 9 9 9
- - - - - - - ---------------------------------------------------------------
Net postretirement cost $ 40 $ 42 $ 45
===============================================================
An additional assumption used in measuring the accumulated postretirement
benefit obligations was a weighted average medical care cost trend rate of 8.30
percent for 1998, decreasing gradually to 4.75 percent through the year 2005,
and remaining at that level thereafter. An annual increase or decrease in the
assumed medical care cost trend rate of 1 percent would affect the accumulated
benefit obligation and the service and interest cost components at December 31,
1998 as follows:
1 Percent 1 Percent
Increase Decrease
- - - - - - - ---------------------------------------------------------------
(in millions)
Benefit obligation $ 38 $ (32)
Service and interest costs 3 (3)
===============================================================
3. REGULATORY AND LITIGATION MATTERS
Retail Rate Order
As required by the GPSC, the Company filed a general rate case in 1998. On
December 18, 1998, the GPSC approved a new three-year rate order for the
Company. Under terms of the order, earnings will continue to be evaluated
against a retail return on common equity range of 10 percent to 12.5 percent.
Retail rates will be decreased by $262 million on an annual basis effective
January 1, 1999, and by an additional $24 million effective January 1, 2000. The
II-108
NOTES (continued)
Georgia Power Company 1998 Annual Report
order further provides for $85 million in each year, plus up to $50 million of
any earnings in excess of the 12.5 percent return during the second and third
years, to be applied to accelerated amortization or depreciation of assets.
Two-thirds of any additional earnings in excess of the 12.5 percent return will
be applied to rate reductions, with the remaining one-third retained by the
Company. The Company will not file for a general base rate increase unless its
projected retail return on common equity falls below 10 percent, and will be
required to file a general rate case on July 1, 2001, in response to which the
GPSC would be expected to determine whether the rate order should be continued,
modified, or discontinued.
Under a previous three-year accounting order ending December 1998, the
Company's earnings were evaluated against a retail return on common equity range
of 10 percent to 12.5 percent. Earnings in excess of 12.5 percent were used to
accelerate the amortization of regulatory assets or depreciation of electric
plant. The Company was required to absorb cost increases of approximately $29
million annually during the order's three-year operation, including $14 million
annually of accelerated depreciation of electric plant.
The Company's 1996 retail return on common equity was within the 10 percent
to 12.5 percent range. During 1998 and 1997, for earnings in excess of the 12.5
percent retail return, the Company recorded charges of $292 million and $135
million, respectively, that are presented in the financial statements as
depreciation expense of electric plant and as an addition to the accumulated
provision for depreciation.
FERC Review of Equity Returns
On September 21, 1998, the FERC entered separate orders affirming the outcome of
the administrative law judge's opinions in two proceedings in which the return
on common equity component of formula rates contained in substantially all of
the operating companies' wholesale power contracts was being challenged as
unreasonably high. These orders resulted in no change in the wholesale power
contracts that were the subject of such proceedings. The FERC also dismissed a
complaint filed by three customers under long-term power sales agreements
seeking to lower the equity return component in such agreements. These customers
have filed applications for rehearing regarding each FERC order. In response to
a requirement of the September 1998 FERC order, Southern Company filed a new
equity return component on the long-term power sales contracts, to be effective
January 5, 1999. The proposed equity return was lowered from 13.75 percent to
12.50 percent. If the filed return is approved, annual revenues will decrease by
approximately $1 million. The FERC placed the new rates into effect, subject to
refund. Also, this filing was consolidated with the new proceeding discussed
below.
On December 28, 1998, the FERC staff filed a motion asking the FERC to
initiate a new proceeding regarding the equity return and other issues involving
the Company's formula rate contracts. The motion was submitted pursuant to
review procedures applicable to theses contracts, and would be applicable to
billings under such contracts on and after January 1, 1999.
Rocky Mountain Plant Status
In its 1985 financing order, the GPSC concluded that completion of the Rocky
Mountain pumped storage hydroelectric plant in 1991, as then planned, was not
economically justifiable and reasonable and withheld authorization for the
Company to spend funds from approved securities issuances on that plant. In
1988, the Company and Oglethorpe Power Corporation (OPC) entered into a joint
ownership agreement for OPC to assume responsibility for the construction and
operation of the plant, as discussed in Note 6. In 1995, the plant went into
commercial operation.
In June 1996, the GPSC initiated a review of the plant. On January 14, 1998,
the GPSC ordered that the Company be allowed approximately $108 million of its
$142 million investment in the plant in rate base as of December 31, 1998. The
Company appealed the GPSC's order to the Superior Court of Fulton County,
Georgia. Under the rate order approved by the GPSC on December 18, 1998, the
Company voluntarily dismissed the appeal. As a result, in December 1998, the
Company recorded a charge to earnings of $21 million, after taxes, associated
with the write-down of the plant.
Tax Litigation
In August 1997, Southern Company and the Internal Revenue Service (IRS) entered
into a settlement agreement related to tax issues for the years 1984 through
1987. The agreement received final approval by the Joint Congressional Committee
on Taxation in June 1998 and as a result, the Company recognized interest income
in 1998 of $69 million. The refund by the IRS has been made and this matter is
now concluded.
11-109
NOTES (continued)
Georgia Power Company 1998 Annual Report
Additionally, the Company received a refund from the State of Georgia
pertaining to the same issues and recognized an additional $4 million in
interest income in 1998.
Demand-Side Conservation Programs
In August 1995, the GPSC ordered the Company to discontinue its current
demand-side conservation programs by the end of 1995. Rate riders previously
approved by the GPSC for recovery of the Company's costs incurred in connection
with these programs remained in effect until January 1998 when costs deferred
were fully collected.
Under a GPSC accounting order approved February 16, 1996, the Company
recognized approximately $29 million of deferred program costs over a three-year
period ending December 1998, which were not recovered through the riders.
Certain Environmental Contingencies
In January 1995, the Company and four other unrelated entities were notified by
the EPA that they have been designated as potentially responsible parties under
the Comprehensive Environmental Response, Compensation and Liability Act with
respect to a site in Brunswick, Georgia. As of December 31, 1998, the Company
has recognized approximately $5 million in cumulative expenses associated with
this site. This represents the Company's agreed upon share of removal and
remedial investigation and feasibility study costs. The final outcome of this
matter cannot now be determined. However, based on the nature and extent of the
Company's activities relating to the site, management believes that the
Company's portion of any remaining remediation costs should not be material.
In compliance with the Georgia Hazardous Site Response Act of 1993, the
State of Georgia was required to compile an inventory of all known or suspected
sites where hazardous wastes, constituents or substances have been disposed of
or released in quantities deemed reportable by the State. In developing this
list, the State identified several hundred properties throughout the State,
including 26 sites which may require environmental remediation that were either
previously or are currently owned by the Company. The majority of these sites
are electrical power substations and power generation facilities. The Company
has remediated nine electrical substations on the list at a cumulative cost of
approximately $3 million. The State has removed from the list one power
generation facility following the assessment which indicated no remediation was
necessary. In addition, the Company has recognized approximately $23 million in
cumulative expenses through December 31, 1998 for the assessment of the
remaining sites on the list and the anticipated clean-up cost for 11 sites that
the Company plans to remediate. Any cost of remediating the remaining sites
cannot presently be determined until such studies are completed for each site
and the State of Georgia determines whether remediation is required. If all
listed sites were required to be remediated, the Company could incur expenses of
up to approximately $10 million in additional clean-up costs and construction
expenditures of up to approximately $56 million to develop new waste management
facilities or install additional pollution control devices.
The accrued costs for environmental remediation obligations are not
discounted to their present value.
Nuclear Performance Standards
The GPSC has 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 comparable 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 award or penalty under the performance standards
criteria.
The first evaluation was conducted in 1993 for performance during the
1990-92 period. The GPSC approved a performance award of approximately $8.5
million for the Company. This award was collected through the retail fuel cost
recovery provision and recognized in income over a 36-month period which ended
in October 1996. In January 1997, the GPSC approved a performance award of
approximately $11.7 million for performance during the 1993-95 period. This
award is being collected through the retail fuel cost recovery provision and
recognized in income over a 36-month period that began in January 1997.
11-110
NOTES (continued)
Georgia Power Company 1998 Annual Report
4. COMMITMENTS
Construction Program
While the Company has no traditional baseload generating plants under
construction, the construction of eight combustion turbine peaking units is
planned to be completed by 2000. In addition, significant construction of
transmission and distribution facilities, and projects to upgrade and extend the
useful life of generating plants and to remain in compliance with environmental
requirements will continue. The Company currently estimates property additions
to be approximately $755 million in 1999, $734 million in 2000, and $829 million
in 2001.
The construction program is subject to periodic review and revision, and
actual construction costs may vary from estimates because of numerous factors,
including, but not limited to, changes in business conditions, load growth
estimates, environmental regulations, and regulatory requirements.
Fuel Commitments
To supply a portion of the fuel requirements of its generating plants, the
Company has entered into various long-term commitments for the procurement of
fossil and nuclear fuel. In most cases, these contracts contain provisions for
price escalations, minimum purchase levels and other financial commitments.
Total estimated long-term fossil and nuclear fuel commitments at December 31,
1998 were as follows:
Minimum
Year Obligations
----------------------
(in millions)
1999 $ 642
2000 545
2001 483
2002 414
2003 366
2004 and beyond 719
- - - - - - - ----------------------------------------------------------------
Total minimum obligations $3,169
================================================================
Additional commitments for coal and for nuclear fuel will be required in the
future to supply the Company's fuel needs.
Purchased Power Commitments
In connection with the joint ownership arrangement for Plant Vogtle, discussed
in Note 6, the Company has made commitments to purchase portions of OPC's and
the Municipal Electric Authority of Georgia's (MEAG's) capacity and energy from
this plant. Declining commitments were in effect during periods of up to seven
years following commercial operation and ended in 1996. In addition, the Company
has commitments regarding a portion of a 5 percent interest in Plant Vogtle
owned by MEAG that are in effect 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 $56 million, $54 million, and $68 million in
1998, 1997, and 1996, respectively. The current projected Plant Vogtle capacity
payments are:
Year Amounts
----------------------
(in millions)
1999 $ 59
2000 62
2001 61
2002 60
2003 60
2004 and beyond 711
- - - - - - - ----------------------------------------------------------------
Total $ 1,013
================================================================
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.
The Company and an affiliate, Alabama Power Company, own equally all of the
outstanding capital stock of Southern Electric Generating Company (SEGCO), which
owns electric generating units with a total rated capacity of 1,020 megawatts,
as well as associated transmission facilities. The capacity of the units has
been sold equally to the Company and Alabama Power Company 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
II-111
NOTES (continued)
Georgia Power Company 1998 Annual Report
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:
1998 1997 1996
---------------------------------
(in millions)
Energy $45 $45 $47
Capacity 30 30 30
- - - - - - - --------------------------------------------------------------
Total $75 $75 $77
==============================================================
Kilowatt-hours 3,146 3,038 2,780
- - - - - - - --------------------------------------------------------------
At December 31, 1998, the capitalization of SEGCO consisted of $49 million
of equity and $70 million of long-term debt on which the annual interest
requirement is $4 million.
The Company has entered into other various long-term commitments for the
purchase of electricity. Total long-term obligations at December 31, 1998 were
as follows:
Year Amounts
----------------------
(in millions)
1999 $ 18
2000 21
2001 22
2002 23
2003 23
2004 and beyond 363
- - - - - - - ----------------------------------------------------------------
Total $ 470
================================================================
Operating Leases
The Company has entered into coal rail car rental agreements with various terms
and expiration dates. These expenses totaled $13 million for 1998, and $11
million each for 1997 and 1996. At December 31, 1998, estimated minimum rental
commitments for these noncancelable operating leases were as follows:
Year Amounts
----------------------
(in millions)
1999 $ 11
2000 11
2001 11
2002 12
2003 12
2004 and beyond 120
- - - - - - - ----------------------------------------------------------------
Total $177
================================================================
5. NUCLEAR INSURANCE
Under the Price-Anderson Amendments Act of 1988, the Company maintains
agreements of indemnity with the NRC that, together with private insurance,
cover third-party liability arising from any nuclear incident occurring at the
Company's nuclear power plants. The act provides funds up to $9.7 billion for
public liability claims that could arise from a single nuclear incident. Each
nuclear plant is insured against this liability to a maximum of $200 million by
private insurance, with the remaining coverage provided by a mandatory program
of deferred premiums that could be assessed, after a nuclear incident, against
all owners of nuclear reactors. The Company could be assessed up to $88 million
per incident for each licensed reactor it operates but not more than an
aggregate of $10 million per incident to be paid in a calendar year for each
reactor. Such maximum assessment for the Company, excluding any applicable state
premium taxes, -- based on its ownership and buyback interests -- is $178
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 Electric Insurance Limited (NEIL), a
mutual insurer established to provide property damage insurance in an amount up
to $500 million for members' nuclear generating facilities.
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 primary
coverage. This excess insurance is also provided by NEIL.
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 17 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 current maximum annual assessments for the Company under the
three NEIL policies would be $25 million.
For all on-site property damage insurance policies for commercial nuclear
II-112
NOTES (continued)
Georgia Power Company 1998 Annual Report
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.
All retrospective assessments, whether generated for liability, property or
replacement power, may be subject to applicable state premium taxes.
6. FACILITY SALES AND JOINT OWNERSHIP
AGREEMENTS
The Company has sold undivided interests in plants Hatch, Wansley, Vogtle, and
Scherer Units 1 and 2 to OPC, an electric membership generation and transmission
corporation; MEAG, a public corporation and an instrumentality of the state of
Georgia; and the City of Dalton, Georgia. The Company has sold an interest in
Plant Scherer Unit 3 to Gulf Power Company, an affiliate. Additionally, the
Company has sold 76.4 percent of Plant Scherer Unit 4 to Florida Power & Light
Company (FP&L) and the remaining 23.6 percent to Jacksonville Electric Authority
(JEA). The Company has also sold transmission facilities to Georgia Transmission
Corporation (formerly OPC's transmission division), MEAG, and the City of
Dalton.
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.
The Company owns 25.4 percent of the Rocky Mountain pumped storage
hydroelectric plant. OPC owns the remainder, and is the operator of the plant.
The Company owns six of eight 80 megawatt combustion turbine generating units
and 75 percent of the related common facilities at Plant McIntosh. Savannah
Electric and Power Company, an affiliate, owns the remainder and operates the
plant. The Company and Florida Power Corporation (FPC) jointly own a combustion
turbine unit at Intercession City, Florida, near Orlando. The unit began
commercial operation in January 1997, and is operated by FPC. The Company owns a
one-third interest in the unit, with use of 100 percent of the unit's capacity
from June through September. FPC has the capacity the remainder of the year.
At December 31, 1998, the Company's percentage ownership and investment
(exclusive of nuclear fuel) in jointly owned facilities in commercial operation,
were as follows:
Company Accumulated
Facility (Type) Ownership Investment Depreciation
- - - - - - - --------------------------------------------------------------------
(in millions)
Plant Vogtle (nuclear) 45.7% $3,296* $1,514
Plant Hatch (nuclear) 50.1 840 538
Plant Wansley (coal) 53.5 298 141
Plant Scherer (coal)
Units 1 and 2 8.4 112 48
Unit 3 75.0 545 179
Plant McIntosh
Common Facilities 75.0 19 1
(combustion-turbine)
Rocky Mountain 25.4 169* 61
(pumped storage)
Intercession City 33.3 12 **
(combustion-turbine)
- - - - - - - --------------------------------------------------------------------
* Investment net of write-offs.
** Less than $1 million.
7. LONG-TERM POWER SALES AGREEMENTS
The Company and the operating subsidiaries of Southern Company have long-term
contractual agreements for the sale of capacity and energy to non-affiliated
utilities located outside the system's service area. These agreements consist of
firm unit power sales pertaining to capacity from specific generating units.
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 were as follows:
Year Revenues Capacity
-------------------------------------
(in millions) (megawatts)
1998 $ 32 162
1997 42 159
1996 41 173
-------------------------------------
Unit power from specific generating plants is being sold to FP&L, FPC, JEA,
and the City of Tallahassee, Florida. Under these agreements, the Company sold
approximately 162 megawatts of capacity in 1998 and is scheduled to sell
approximately 162 megawatts of capacity in 1999. In 2000, 129 megawatts will be
sold. After 2000, capacity sales will decline to approximately 105 megawatts --
unless reduced by FP&L, FPC, and JEA -- until the expiration of the contracts in
2010.
II-113
NOTES (continued)
Georgia Power Company 1998 Annual Report
8. INCOME TAXES
At December 31, 1998, tax-related regulatory assets were $604 million and
tax-related regulatory liabilities were $284 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:
1998 1997 1996
-------------------------------
Total provision for income taxes: (in millions)
Federal:
Currently payable $ 415 $352 $325
Deferred -
Current year 131 49 70
Reversal of prior years (218) (68) (41)
Deferred investment tax
credits 7 - -
- - - - - - - -----------------------------------------------------------------
335 333 354
- - - - - - - -----------------------------------------------------------------
State:
Currently payable 77 65 56
Deferred -
Current year 18 8 12
Reversal of prior years (31) (11) (5)
- - - - - - - -----------------------------------------------------------------
64 62 63
- - - - - - - -----------------------------------------------------------------
Total 399 395 417
- - - - - - - -----------------------------------------------------------------
Less:
Income taxes credited
to other income (8) (32) (19)
- - - - - - - -----------------------------------------------------------------
Total income taxes
charged to operations $ 407 $427 $436
=================================================================
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:
1998 1997
-------------------
(in millions)
Deferred tax liabilities:
Accelerated depreciation $1,670 $1,732
Property basis differences 854 968
Other 158 142
- - - - - - - ----------------------------------------------------------------
Total 2,682 2,842
- - - - - - - ----------------------------------------------------------------
Deferred tax assets:
Other property basis differences 211 216
Federal effect of state deferred taxes 95 99
Other deferred costs 96 83
Disallowed Plant Vogtle buybacks 23 23
Other 21 14
- - - - - - - ----------------------------------------------------------------
Total 446 435
- - - - - - - ----------------------------------------------------------------
Net deferred tax liabilities 2,236 2,407
Portion included in current assets 13 11
- - - - - - - ----------------------------------------------------------------
Accumulated deferred income taxes
in the Balance Sheets $2,249 $2,418
================================================================
Deferred investment tax credits are amortized over the life of the related
property with such amortization normally applied as a credit to reduce
depreciation in the Statements of Income. Credits amortized in this manner
amounted to $22 million in 1998, $15 million in 1997, and $17 million in 1996.
At December 31, 1998, all investment tax credits available to reduce federal
income taxes payable had been utilized.
A reconciliation of the federal statutory tax rate to the effective income
tax rate is as follows:
1998 1997 1996
--------------------------
Federal statutory rate 35% 35% 35%
State income tax, net of
federal deduction 4 4 4
Non-deductible book
depreciation 6 4 3
Other (4) (4) (2)
- - - - - - - ---------------------------------------------------------------
Effective income tax rate 41% 39% 40%
===============================================================
Southern Company and its subsidiaries file a consolidated federal income tax
return. Under a joint consolidated income tax agreement, each subsidiary's
current and deferred tax expense is computed on a stand-alone basis. Tax
benefits from losses of the parent company are allocated to each subsidiary
based on the ratio of taxable income to total consolidated taxable income.
II-114
NOTES (continued)
Georgia Power Company 1998 Annual Report
9. CAPITALIZATION
First Mortgage Bond Indenture & Charter Restrictions
The Company historically has relied on issuances of first mortgage bonds and
preferred stock, in addition to pollution control revenue bonds issued for its
benefit by public authorities, to meet its long-term external financing
requirements. Recently, the Company's financings have consisted of unsecured
debt and trust preferred securities. In this regard, the Company sought and
obtained stockholder approval in 1997 to amend its corporate charter eliminating
restrictions on the amounts of unsecured indebtedness it may incur.
The Company's first mortgage bond indenture contains various restrictions
that remain in effect as long as the bonds are outstanding. At December 31,
1998, $883 million of retained earnings and paid-in capital was unrestricted for
the payment of cash dividends or any other distributions under terms of the
mortgage indenture. If additional first mortgage bonds are issued, supplemental
indentures in connection with those issues may contain more stringent
restrictions than those currently in effect.
Preferred Securities
In December 1994, Georgia Power Capital, L.P., of which the Company is the sole
general partner, issued $100 million of 9 percent mandatorily redeemable
preferred securities. Substantially all of the assets of Georgia Power Capital,
L.P., are $103 million aggregate principal amount of Georgia Power's 9 percent
Junior Subordinated Deferrable Interest Debentures due December 19, 2024.
Statutory business trusts formed by the Company, of which the Company owns
all the common securities, have issued mandatorily redeemable preferred
securities as follows:
Date of Maturity
Issue Amount Rate Notes Date
---------------------------------------------------
(millions) (millions)
Trust I 8/1996 $225.00 7.75% $232 6/2036
Trust II 1/1997 175.00 7.60% 180 12/2036
Trust III 6/1997 189.25 7.75% 195 3/2037
Substantially all of the assets of each trust are junior subordinated notes
issued by the Company in the respective approximate principal amounts set forth
above. In February 1999, the Company issued an additional $200 million of
mandatorily redeemable preferred securities (Trust IV), bearing interest at 6.85
percent. The associated junior subordinated notes will be due March 31, 2029.
The Company considers that the mechanisms and obligations relating to the
preferred securities, taken together, constitute a full and unconditional
guarantee by the Company of Georgia Power Capital, L.P.'s and the Trusts'
payment obligations with respect to the preferred securities.
Georgia Power Capital, L.P., and the Trusts are subsidiaries of the Company,
and accordingly are consolidated in the Company's financial statements.
Pollution Control Bonds
The Company has incurred obligations in connection with the sale by public
authorities of tax-exempt pollution control revenue bonds. The Company has
authenticated and delivered to trustees an aggregate of $1.2 billion of its
first mortgage bonds, which are pledged as security for its obligations under
pollution control revenue contracts. No interest on these first mortgage bonds
is payable unless and until a default occurs on the installment purchase or loan
agreements.
Senior Notes
In January, November, and December 1998, the Company issued unsecured senior
notes. The senior notes are, in effect, subordinated to all secured debt of the
Company, including its first mortgage bonds.
Bank Credit Arrangements
At the beginning of 1999, the Company had unused credit arrangements with banks
totaling $1.3 billion, of which $722 million expires at various times during
1999, $30 million expires at May 1, 2000, and $500 million expires at April 24,
2003.
Of the total $1.3 billion in unused credit, $1 billion is a syndicated
credit arrangement with $500 million expiring April 23, 1999 and $500 million
expiring April 24, 2003. Both agreements provide the option of converting
borrowings into two-year term loans upon expiration date. The agreements contain
stated borrowing rates but also allow for competitive bid loans. In addition,
the agreements require payment of commitment fees based on the unused portions
of the commitments. Annual fees are also paid to the agent bank.
II-115
NOTES (continued)
Georgia Power Company 1998 Annual Report
Approximately $162 million of the $722 million arrangements expiring during
1999 allow for two-year term loans executable upon expiration date of the credit
facilities. The $30 million credit arrangement expiring at May 1, 2000 allows
for term loans of up to three years. All of the arrangements include stated
borrowing rates but also allow for negotiated rates. These agreements also
require payment of commitment fees based on the unused portion of the
commitments or the maintenance of compensating balances with the banks. These
balances are not legally restricted from withdrawal.
The $1.3 billion in unused credit arrangements provide liquidity support to
the Company's variable rate pollution control bonds. The amount of variable rate
pollution control bonds outstanding as of December 31, 1998 was $979 million.
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 1998.
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, 1998 and 1997, the Company had a capitalized
lease obligation for its corporate headquarters building of $87 million with an
interest rate of 8.1 percent. The lease agreement 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, 1998 and 1997, the interest and lease amortization deferred on
the Balance Sheets are $53 million and $52 million, respectively.
Assets Subject to Lien
The Company's mortgage dated as of March 1, 1941, as amended and supplemented,
securing the first mortgage bonds issued by the Company, constitutes a direct
lien on substantially all of the Company's fixed property and franchises.
Securities Due Within One Year
A summary of the improvement fund requirements and scheduled maturities and
redemptions of securities due within one year at December 31 is as follows:
1998 1997
-------------------
(in millions)
Bond improvement fund requirements $ 9 $ 15
Less:
Portion to be satisfied by certifying
property additions - -
- - - - - - - ----------------------------------------------------------------
Cash requirements 9 15
First mortgage bond maturities
and redemptions 390 205
- - - - - - - ----------------------------------------------------------------
Total long-term debt 399 220
Preferred stock 36 -
- - - - - - - ----------------------------------------------------------------
Total $435 $220
================================================================
The Company's first mortgage bond indenture includes an improvement fund
requirement that amounts to 1 percent of each outstanding series of bonds
authenticated under the indenture prior to January 1 of each year, other than
those issued to collateralize pollution control obligations. The requirement may
be satisfied by June 1 of each year by depositing cash, reacquiring bonds, or by
pledging additional property equal to 1 2/3 times the requirement. The 1999
requirement was met in the first quarter of the year by depositing cash with the
trustee. These funds were used to redeem first mortgage bonds.
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 requirements, to meet replacement provisions of the mortgage,
or through use of proceeds from the sale of property pledged under the mortgage.
II-116
NOTES (continued)
Georgia Power Company 1998 Annual Report
In general, for the first five years a series of first mortgage bonds is
outstanding, the Company is prohibited from redeeming for improvement fund
purposes more than 1 percent annually of the original issue amount.
10. QUARTERLY FINANCIAL DATA (UNAUDITED)
Summarized quarterly financial information for 1998 and 1997 is as follows:
Net Income
After
Dividends on
Operating Operating Preferred Stock
Quarter Ended Revenues Income
- - - - - - - ---------------------------------------------------------------------
(in millions)
--------------------------------------------
March 1998 $ 984 $177 $ 106
June 1998 1,226 188 137
September 1998 1,530 325 255
December 1998 998 104 72
March 1997 $ 959 $180 $ 106
June 1997 1,015 205 131
September 1997 1,407 317 257
December 1997 1,005 159 100
- - - - - - - ---------------------------------------------------------------------
Earnings in the fourth quarter of 1998, compared to the fourth quarter of
1997, decreased primarily as a result of the December 1998 Rocky Mountain
write-off.
The Company's business is influenced by seasonal weather conditions.
II-117
SELECTED FINANCIAL AND OPERATING DATA
Georgia Power Company 1998 Annual Report
===============================================================================================================================
1998 1997 1996
- - - - - - - -------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands) $4,738,253 $4,385,717 $4,416,779
Net Income after Dividends
on Preferred Stock (in thousands) $570,228 $593,996 $580,327
Cash Dividends on Common Stock (in thousands) $536,600 $520,000 $475,500
Return on Average Common Equity (percent) 14.61 14.53 13.73
Total Assets (in thousands) $12,033,618 $12,573,728 $13,006,635
Gross Property Additions (in thousands) $499,053 $475,921 $428,220
- - - - - - - -------------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $3,784,172 $4,019,728 $4,154,281
Preferred stock 15,527 157,247 464,611
Preferred stock subject to mandatory redemption - - -
Company obligated mandatorily redeemable preferred securities 689,250 689,250 325,000
Long-term debt 2,744,362 2,982,835 3,200,419
- - - - - - - -------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $7,233,311 $7,849,060 $8,144,311
===============================================================================================================================
Capitalization Ratios (percent):
Common stock equity 52.3 51.2 51.0
Preferred stock 0.2 2.0 5.7
Company obligated mandatorily redeemable preferred securities 9.5 8.8 4.0
Long-term debt 38.0 38.0 39.3
- - - - - - - -------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0 100.0
===============================================================================================================================
First Mortgage Bonds (in thousands):
Issued - - 10,000
Retired 558,250 60,258 210,860
Preferred Stock (in thousands):
Issued - - -
Retired 106,064 356,392 179,148
Senior Notes (in thousands):
Issued 495,000 - -
Company Obligated Mandatorily Redeemable
Preferred Securities (in thousands):
Issued - 364,250 225,000
- - - - - - - -------------------------------------------------------------------------------------------------------------------------------
Security Ratings:
First Mortgage Bonds -
Moody's A1 A1 A1
Standard and Poor's A+ A+ A+
Duff & Phelps AA- AA- AA-
Preferred Stock -
Moody's a2 a2 a2
Standard and Poor's A A A
Duff & Phelps A+ A+ A+
Unsecured Long-Term Debt -
Moody's A2 A2 A2
Standard and Poor's A A A
Duff & Phelps A+ A+ A+
- - - - - - - -------------------------------------------------------------------------------------------------------------------------------
Customers (year-end):
Residential 1,596,488 1,561,675 1,531,453
Commercial 221,180 211,672 205,087
Industrial 9,485 9,988 10,424
Other 3,034 2,748 2,645
- - - - - - - -------------------------------------------------------------------------------------------------------------------------------
Total 1,830,187 1,786,083 1,749,609
===============================================================================================================================
Employees (year-end) 8,371 8,354 * 10,346
*In 1997 Georgia Power Company transferred 1,855 employees to Southern Nuclearompany.
II-118
SELECTED FINANCIAL AND OPERATING DATA (continued)
Georgia Power Company 1998 Annual Report
=======================================================================================================================------------
1995 1994 1993 1992
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands) $4,405,338 $4,162,403 $4,451,181 $4,297,436
Net Income after Dividends
on Preferred Stock (in thousands) $608,862 $525,544 $569,853 $520,538
Cash Dividends on Common Stock (in thousands) $451,500 $429,300 $402,400 $384,000
Return on Average Common Equity (percent) 14.43 12.84 14.37 13.60
Total Assets (in thousands) $13,470,275 $13,712,658 $13,736,110 $10,964,442
Gross Property Additions (in thousands) $480,449 $638,426 $674,432 $508,444
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $4,299,012 $4,141,554 $4,045,458 $3,888,237
Preferred stock 692,787 692,787 692,787 692,792
Preferred stock subject to mandatory redemption - - - 6,250
Company obligated mandatorily redeemable preferred securities 100,000 100,000 - -
Long-term debt 3,315,460 3,757,823 4,031,387 4,131,016
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $8,407,259 $8,692,164 $8,769,632 $8,718,295
===================================================================================================================================
Capitalization Ratios (percent):
Common stock equity 51.1 47.6 46.1 44.6
Preferred stock 8.2 8.0 7.9 8.0
Company obligated mandatorily redeemable preferred securities 1.2 1.2 - -
Long-term debt 39.5 43.2 46.0 47.4
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0 100.0 100.0
===================================================================================================================================
First Mortgage Bonds (in thousands):
Issued 75,000 - 1,135,000 975,000
Retired 505,789 133,559 1,337,822 1,381,300
Preferred Stock (in thousands):
Issued - - 175,000 195,000
Retired - - 245,005 165,004
Senior Notes (in thousands):
Issued - - - -
Company Obligated Mandatorily Redeemable
Preferred Securities (in thousands):
Issued - 100,000 - -
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------------
Security Ratings:
First Mortgage Bonds -
Moody's A1 A2 A3 A3
Standard and Poor's A+ A A- A-
Duff & Phelps AA- A+ A+ A-
Preferred Stock -
Moody's a2 a3 baa1 baa1
Standard and Poor's A A- BBB+ BBB+
Duff & Phelps A A- A- BBB
Unsecured Long-Term Debt -
Moody's A2 A3 Baa1 Baa1
Standard and Poor's A A- BBB+ BBB+
Duff & Phelps A+ A A BBB+
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------------
Customers (year-end):
Residential 1,500,024 1,466,382 1,441,972 1,421,175
Commercial 198,624 193,648 188,820 183,784
Industrial 10,796 10,976 11,217 11,479
Other 2,568 2,426 2,322 2,269
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------------
Total 1,712,012 1,673,432 1,644,331 1,618,707
===================================================================================================================================
Employees (year-end) 11,061 11,765 12,528 12,600
II-119A
SELECTED FINANCIAL AND OPERATING DATA (continued)
Georgia Power Company 1998 Annual Report
=================================================================================================================================
1991 1990 1989 1988
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands) $4,301,428 $4,445,809 $4,145,240 $3,897,479
Net Income after Dividends
on Preferred Stock (in thousands) $474,855 $208,066 $449,099 $479,532
Cash Dividends on Common Stock (in thousands) $375,200 $389,600 $394,500 $386,600
Return on Average Common Equity (percent) 12.76 5.52 11.72 13.06
Total Assets (in thousands) $10,842,538 $11,176,619 $11,372,346 $11,130,539
Gross Property Additions (in thousands) $548,051 $558,727 $727,631 $929,019
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock 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
Company obligated mandatorily redeemable preferred securities - - - -
Long-term debt 4,553,189 5,000,225 5,054,001 4,861,378
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $9,046,286 $9,406,934 $9,677,502 $9,487,792
=================================================================================================================================
Capitalization Ratios (percent):
Common stock equity 41.7 39.1 39.9 40.1
Preferred stock 8.0 7.8 7.9 8.6
Company obligated mandatorily redeemable preferred securities - - - -
Long-term debt 50.3 53.1 52.2 51.3
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0 100.0 100.0
=================================================================================================================================
First Mortgage Bonds (in thousands):
Issued - 300,000 250,000 150,000
Retired 598,384 91,117 91,516 206,677
Preferred Stock (in thousands):
Issued 100,000 - - -
Retired 100,000 83,750 7,500 3,750
Senior Notes (in thousands):
Issued - - - -
Company Obligated Mandatorily Redeemable
Preferred Securities (in thousands):
Issued - - - -
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------------
Security Ratings:
First Mortgage Bonds -
Moody's Baa1 Baa1 Baa2 Baa2
Standard and Poor's BBB+ BBB+ BBB+ BBB
Duff & Phelps BBB+ BBB BBB 9
Preferred Stock -
Moody's baa1 baa1 baa2 baa2
Standard and Poor's BBB BBB BBB BBB-
Duff & Phelps BBB- BBB- BBB- 10
Unsecured Long-Term Debt -
Moody's Baa2 Baa2 - Baa3
Standard and Poor's BBB+ BBB - BBB-
Duff & Phelps BBB+ - - 10
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------------
Customers (year-end):
Residential 1,397,682 1,378,888 1,355,211 1,329,173
Commercial 179,933 178,391 177,814 174,147
Industrial 11,946 12,115 12,311 12,353
Other 2,190 2,114 2,050 1,993
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------------
Total 1,591,751 1,571,508 1,547,386 1,517,666
=================================================================================================================================
Employees (year-end) 13,700 13,746 13,900 15,110
II-119B
SELECTED FINANCIAL AND OPERATING DATA (continued)
Georgia Power Company 1998 Annual Report
===============================================================================================================================
1998 1997 1996
- - - - - - - -------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $1,486,699 $1,326,787 $1,371,033
Commercial 1,591,363 1,493,353 1,486,586
Industrial 1,170,881 1,110,311 1,118,633
Other 49,274 47,848 47,060
- - - - - - - -------------------------------------------------------------------------------------------------------------------------------
Total retail 4,298,217 3,978,299 4,023,312
Sales for resale - non-affiliates 259,234 282,365 281,580
Sales for resale - affiliates 81,606 38,708 35,886
- - - - - - - -------------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 4,639,057 4,299,372 4,340,778
Other revenues 99,196 86,345 76,001
- - - - - - - -------------------------------------------------------------------------------------------------------------------------------
Total $4,738,253 $4,385,717 $4,416,779
===============================================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 19,481,486 17,295,022 17,826,451
Commercial 22,861,391 21,134,346 20,823,073
Industrial 27,283,147 26,701,685 26,191,831
Other 543,462 538,163 536,057
- - - - - - - -------------------------------------------------------------------------------------------------------------------------------
Total retail 70,169,486 65,669,216 65,377,412
Sales for resale - non-affiliates 6,438,891 6,795,300 7,868,342
Sales for resale - affiliates 2,038,400 1,706,699 1,180,207
- - - - - - - -------------------------------------------------------------------------------------------------------------------------------
Total 78,646,777 74,171,215 74,425,961
===============================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 7.63 7.67 7.69
Commercial 6.96 7.07 7.14
Industrial 4.29 4.16 4.27
Total retail 6.13 6.06 6.15
Sales for resale 4.02 3.78 3.51
Total sales 5.90 5.80 5.83
Residential Average Annual Kilowatt-Hour Use Per Customer 12,314 11,171 11,763
Residential Average Annual Revenue Per Customer $939.72 $857.01 $904.70
Plant Nameplate Capacity Ratings (year-end) (megawatts) 14,437 14,437 14,367
Maximum Peak-Hour Demand (megawatts):
Winter 11,959 10,407 10,410
Summer 13,923 13,153 12,914
Annual Load Factor (percent) 58.7 57.4 62.2
Plant Availability (percent):
Fossil-steam 86.0 85.8 85.2
Nuclear 91.6 88.8 89.3
- - - - - - - -------------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 62.3 64.3 60.4
Nuclear 18.3 18.8 18.2
Hydro 2.2 2.2 2.2
Oil and gas 2.2 0.6 0.5
Purchased power -
From non-affiliates 6.5 2.7 5.6
From affiliates 8.5 11.4 13.1
- - - - - - - -------------------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0
===============================================================================================================================
Total Fuel Economy Data:
BTU per net kilowatt-hour generated 10,118 9,990 10,468
Cost of fuel per million BTU (cents) 134.62 132.61 128.72
Average cost of fuel per net kilowatt-hour generated (cents) 1.36 1.32 1.35
===============================================================================================================================
* Less than one-tenth of one percent.
II-120
SELECTED FINANCIAL AND OPERATING DATA (continued)
Georgia Power Company 1998 Annual Report
==========================================================================================================================
1995 1994 1993 1992
- - - - - - - --------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $1,337,060 $1,180,358 $1,291,035 $1,128,396
Commercial 1,449,108 1,367,315 1,354,130 1,285,681
Industrial 1,141,766 1,100,995 1,113,067 1,083,856
Other 44,255 42,983 41,399 39,504
- - - - - - - --------------------------------------------------------------------------------------------------------------------------
Total retail 3,972,189 3,691,651 3,799,631 3,537,437
Sales for resale - non-affiliates 290,302 351,591 534,370 640,308
Sales for resale - affiliates 76,906 60,899 61,668 67,835
- - - - - - - --------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 4,339,397 4,104,141 4,395,669 4,245,580
Other revenues 65,941 58,262 55,512 51,856
- - - - - - - --------------------------------------------------------------------------------------------------------------------------
Total $4,405,338 $4,162,403 $4,451,181 $4,297,436
==========================================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 17,307,399 15,680,709 16,649,859 14,939,172
Commercial 19,844,999 18,738,461 18,278,508 17,260,614
Industrial 25,286,340 24,337,632 23,635,363 22,978,312
Other 493,720 484,009 460,801 436,144
- - - - - - - --------------------------------------------------------------------------------------------------------------------------
Total retail 62,932,458 59,240,811 59,024,531 55,614,242
Sales for resale - non-affiliates 6,591,841 7,968,475 14,307,030 15,870,222
Sales for resale - affiliates 2,738,947 3,056,050 3,027,733 3,320,060
- - - - - - - --------------------------------------------------------------------------------------------------------------------------
Total 72,263,246 70,265,336 76,359,294 74,804,524
==========================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 7.73 7.53 7.75 7.55
Commercial 7.30 7.30 7.41 7.45
Industrial 4.52 4.52 4.71 4.72
Total retail 6.31 6.23 6.44 6.36
Sales for resale 3.94 3.74 3.44 3.69
Total sales 6.00 5.84 5.76 5.68
Residential Average Annual Kilowatt-Hour Use Per Customer 11,654 10,766 11,630 10,603
Residential Average Annual Revenue Per Customer $900.28 $810.39 $901.79 $800.88
Plant Nameplate Capacity Ratings (year-end) (megawatts) 14,344 13,943 13,759 14,076
Maximum Peak-Hour Demand (megawatts):
Winter 9,819 10,509 9,067 8,938
Summer 12,828 11,758 12,573 11,448
Annual Load Factor (percent) 59.6 63.0 58.5 60.5
Plant Availability (percent):
Fossil-steam 85.8 83.1 85.9 86.6
Nuclear 91.8 88.4 85.5 87.7
- - - - - - - --------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 63.0 61.3 62.1 61.4
Nuclear 19.3 18.0 16.2 17.0
Hydro 2.5 2.6 2.3 2.5
Oil and gas 0.6 0.1 0.2 *
Purchased power -
From non-affiliates 7.7 9.7 10.2 12.2
From affiliates 6.9 8.3 9.0 6.9
- - - - - - - --------------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0 100.0
==========================================================================================================================
Total Fuel Economy Data:
BTU per net kilowatt-hour generated 10,039 9,915 9,912 9,900
Cost of fuel per million BTU (cents) 143.85 145.33 153.62 153.08
Average cost of fuel per net kilowatt-hour generated (cents) 1.44 1.44 1.52 1.52
==========================================================================================================================
* Less than one-tenth of one percent.
II-121A
SELECTED FINANCIAL AND OPERATING DATA (continued)
Georgia Power Company 1998 Annual Report
===============================================================================================================================
1991 1990 1989 1988
- - - - - - - -------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $1,111,358 $1,109,165 $1,022,781 $979,047
Commercial 1,243,067 1,218,441 1,143,727 1,054,995
Industrial 1,057,702 1,061,830 1,006,416 983,822
Other 37,861 36,773 34,775 31,743
- - - - - - - -------------------------------------------------------------------------------------------------------------------------------
Total retail 3,449,988 3,426,209 3,207,699 3,049,607
Sales for resale - non-affiliates 736,643 784,086 760,809 707,076
Sales for resale - affiliates 65,586 168,251 150,394 86,751
- - - - - - - -------------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 4,252,217 4,378,546 4,118,902 3,843,434
Other revenues 49,211 67,263 26,338 54,045
- - - - - - - -------------------------------------------------------------------------------------------------------------------------------
Total $4,301,428 $4,445,809 $4,145,240 $3,897,479
===============================================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 14,815,089 14,771,648 14,134,195 13,800,038
Commercial 16,885,833 16,627,128 15,843,181 14,790,561
Industrial 22,298,062 22,126,604 21,801,404 21,412,845
Other 429,016 428,459 414,107 397,669
- - - - - - - -------------------------------------------------------------------------------------------------------------------------------
Total retail 54,428,000 53,953,839 52,192,887 50,401,113
Sales for resale - non-affiliates 18,719,924 20,158,681 20,479,412 18,544,705
Sales for resale - affiliates 3,885,892 8,272,528 7,489,948 3,327,814
- - - - - - - -------------------------------------------------------------------------------------------------------------------------------
Total 77,033,816 82,385,048 80,162,247 72,273,632
===============================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 7.50 7.51 7.24 7.09
Commercial 7.36 7.33 7.22 7.13
Industrial 4.74 4.80 4.62 4.59
Total retail 6.34 6.35 6.15 6.05
Sales for resale 3.55 3.35 3.26 3.63
Total sales 5.52 5.31 5.14 5.32
Residential Average Annual Kilowatt-Hour Use Per Customer 10,675 10,795 10,530 10,484
Residential Average Annual Revenue Per Customer $800.78 $810.56 $761.96 $743.82
Plant Nameplate Capacity Ratings (year-end) (megawatts) 14,076 14,366 14,366 13,018
Maximum Peak-Hour Demand (megawatts):
Winter 10,001 8,977 10,101 9,866
Summer 13,090 13,196 12,735 12,295
Annual Load Factor (percent) 55.2 55.5 56.3 59.1
Plant Availability (percent):
Fossil-steam 93.3 92.5 93.0 94.5
Nuclear 81.6 81.3 89.2 69.4
- - - - - - - -------------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 63.6 65.1 64.0 72.0
Nuclear 15.3 13.7 14.1 9.6
Hydro 2.3 2.2 2.1 1.2
Oil and gas * 0.1 0.1 0.1
Purchased power -
From non-affiliates 10.3 11.0 10.2 8.2
From affiliates 8.5 7.9 9.5 8.9
- - - - - - - -------------------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0 100.0
===============================================================================================================================
Total Fuel Economy Data:
BTU per net kilowatt-hour generated 9,960 9,939 10,020 9,969
Cost of fuel per million BTU (cents) 157.97 166.22 164.27 166.28
Average cost of fuel per net kilowatt-hour generated (cents) 1.57 1.65 1.65 1.66
===============================================================================================================================
* Less than one-tenth of one percent.
11-121B
GULF POWER COMPANY
FINANCIAL SECTION
II-122
MANAGEMENT'S REPORT
Gulf Power Company 1998 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 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 /s/ Arlan E. Scarbrough
Travis J. Bowden Arlan E. Scarbrough
President Chief Financial Officer
and Chief Executive Officer
February 10, 1999
II-123
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To 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
Southern Company) as of December 31, 1998 and 1997, 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, 1998. 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-134 through II-150)
referred to above present fairly, in all material respects, the financial
position of Gulf Power Company as of December 31, 1998 and 1997, and the
results of its operations and its cash flows for each of the three years in the
period ended December 31, 1998, in conformity with generally accepted
accounting principles.
/s/ Arthur Andersen LLP
Atlanta, Georgia
February 10, 1999
II-124
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Gulf Power Company 1998 Annual Report
RESULTS OF OPERATIONS
Earnings
Gulf Power Company's 1998 net income after dividends on preferred stock was
$56.5 million, a decrease of $1.1 million from the previous year. The decrease
in earnings was primarily a result of higher operating expenses in 1998 when
compared to 1997.
In 1997, earnings were $57.6 million, down $0.2 million when compared to
1996. The change was attributed to lower residential revenues due to
milder-than-normal weather.
Revenues
Operating revenues increased in 1998 when compared to 1997 and decreased in 1997
when compared to 1996. The following table summarizes the factors impacting
operating revenues for the past three years:
Increase (Decrease)
From Prior Year
---------------------------------------
1998 1997 1996
---------------------------------------
(in thousands)
Retail --
Sales growth $15,021 $ 4,005 $ 7,123
Weather 6,656 (5,277) (1,057)
Regulatory cost
recovery and other (34,179) (7,837) 5,649
- - - - - - - --------------------------------------------------------------------
Total retail (12,502) (9,109) 11,715
- - - - - - - --------------------------------------------------------------------
Sales for resale--
Non-affiliates (1,804) 496 2,788
Affiliates 25,882 (1,002) (857)
- - - - - - - --------------------------------------------------------------------
Total sales for resale 24,078 (506) 1,931
Other operating
revenues 13,086 1,106 1,642
- - - - - - - --------------------------------------------------------------------
Total operating
revenues $24,662 $(8,509) $15,288
====================================================================
Percent change 3.9% (1.3)% 2.5%
- - - - - - - --------------------------------------------------------------------
Retail revenues of $509.1 million in 1998 decreased $12.5 million or 2.4
percent from the prior year due primarily to the recovery of lower fuel costs.
The price per ton of coal, which is the Company's primary fuel source, was lower
in 1998 as the costs related to prior year coal contract renegotiations were
fully amortized and a major coal contract price was reduced. See Note 5 to the
financial statements under "Fuel Commitments" for further information. Retail
revenues for 1997 decreased $9.1 million or 1.7 percent when compared to 1996
due primarily to a decrease in residential revenues as a result of mild weather
and recovery of lower purchased power capacity costs.
The decrease in regulatory cost recovery and other retail revenues is
primarily attributable to the recovery of decreased fuel costs as mentioned
previously. Regulatory cost recovery and other includes recovery provisions for
fuel expense and the energy component of purchased power costs; energy
conservation costs; purchased power capacity costs; and environmental compliance
costs. The recovery provisions generally 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 $104.5 million in 1998, an increase of $24.1 million or
29.9 percent over 1997 due to additional energy sales to affiliated companies,
which is discussed below. Revenues from sales to utilities outside the service
area under long-term contracts consist of capacity and energy components.
Capacity revenues reflect the recovery of fixed costs and a return on investment
under the contracts. Energy is generally sold at variable cost. The capacity and
energy components under these long-term contracts were as follows:
1998 1997 1996
----------------------------------------
(in thousands)
Capacity $22,503 $24,899 $25,400
Energy 14,556 18,160 19,804
- - - - - - - -------------------------------------------------------------
Total $37,059 $43,059 $45,204
=============================================================
Declining capacity revenues reflect the decline in net plant investment
related to these sales.
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.
Other operating revenues increased in 1998 due primarily to adjustments to
reflect differences between recoverable costs and the amounts actually reflected
in current rates. See Notes 1 and 3 to the financial statements under "Revenues
and Regulatory Cost Recovery Clauses" and "Environmental Cost Recovery,"
respectively, for further discussion.
II-125
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 1998 Annual Report
Kilowatt-hour sales for 1998 and the percent changes by year were as follows:
KWH Percent Change
------------- ------------------------------
1998 1998 1997 1996
------------- ------------------------------
(millions)
Residential 4,437 7.7% (1.0)% 3.6%
Commercial 3,112 7.4 3.2 3.7
Industrial 1,834 (3.7) 5.3 0.7
Other 19 4.7 1.6 2.7
-------------
Total retail 9,402 5.2 1.6 3.0
Sales for resale
Non-affiliates 1,342 (12.4) (0.2) 9.9
Affiliates 1,758 107.3 19.5 (6.5)
-------------
Total 12,502 10.5 2.5 3.3
=================================================================
In 1998, total retail energy sales increased due to higher temperatures when
compared to the milder-than-normal temperatures in 1997 and due to increases in
the number of residential and commercial customers. The decrease in industrial
energy sales in 1998 when compared to 1997 primarily reflects the shut down of a
major industrial customer's plant site and temporary production delays of other
industrial customers. In 1997, residential energy sales declined as a result of
the milder weather when compared with more normal weather in 1996. The increase
in industrial energy sales was primarily the result of the Real-Time-Pricing
program. The price structure of this program has encouraged participating
industrial customers to lower their peak demand requirements and increase their
purchases of energy during off-peak periods. See "Future Earnings Potential" for
information on the Company's initiatives to remain competitive and to meet
conservation goals set by the Florida Public Service Commission (FPSC).
Decreases in energy sales for resale to non-affiliates of 12.4 percent in
1998 when compared to 1997 and 0.2 percent in 1997 when compared to 1996 are
primarily related to unit power sales under long-term contracts to other Florida
utilities and bulk power sales under short-term contracts to other
non-affiliated utilities. Energy sales to affiliated companies vary from year to
year as mentioned previously.
Expenses
Total operating expenses in 1998 increased $25.6 million or 4.8 percent from the
amount recorded in 1997 due primarily to higher fuel, purchased power, and
maintenance expenses, offset by lower other operation expenses. In 1997, total
operating expenses decreased $3.9 million or 0.7 percent from 1996. The decrease
was due to lower fuel, purchased power, and maintenance expenses, offset by
higher other operation expenses and depreciation and amortization expenses.
Fuel expenses in 1998 when compared to 1997 increased $16.6 million or 9.2
percent due to increased generation resulting from a higher demand for energy,
while average fuel costs decreased as noted below. In 1997, fuel expenses
decreased when compared to 1996 due to slightly lower fuel costs.
Purchased power expenses increased in 1998 by $6.9 million or 18.8 percent
above 1997 amounts due to an increased demand for energy. In 1997, purchased
power expenses decreased $6.5 million or 14.9 percent from the amount recorded
in 1996. This change was due primarily to a reduction in the cost of purchased
power from affiliated companies.
The amount and sources of generation and the average cost of fuel per net
kilowatt-hour generated were as follows:
1998 1997 1996
-------------------------------
Total generation
(millions of kilowatt-hours) 11,986 10,435 10,214
Sources of generation
(percent)
Coal 98.0 99.6 99.5
Oil and gas 2.0 0.4 0.5
Average cost of fuel per net
kilowatt-hour generated
(cents)-- 1.69 1.99 2.02
- - - - - - - ---------------------------------------------------------------------
Other operation expenses decreased $7.3 million or 5.7 percent in 1998 due to
a decrease in the amortization costs of prior year payments related to
renegotiations of coal supply contracts. This decrease was partially offset by
higher implementation costs of a new customer accounting system, increased costs
related to the Year 2000 program, and an increase in the accrual to the
accumulated provision for property damage. In 1997, other operation expenses
increased $11.1 million or 9.6 percent from the 1996 level. This change was
attributable to higher amortization costs of prior year payments related to
renegotiations of coal supply contracts, implementation costs related to a new
customer accounting system, and increased production and distribution costs
II-126
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 1998 Annual Report
related to 1997 work force reduction programs. See Note 2 to the financial
statements under "Workforce Reduction Programs" for further discussion.
Maintenance expenses in 1998 rose by $9.3 million or 19.4 percent, as
compared to 1997, due primarily to scheduled maintenance performed at Plant
Crist and Plant Smith and increased transmission and distribution maintenance.
In 1997, maintenance expenses decreased $3.1 million or 6.0 percent when
compared to the prior year due to a decrease in scheduled maintenance of
production facilities.
Interest on long-term debt in 1998 decreased $2.0 million or 9.1 percent from
1997 due primarily to a decrease in interest expense on pollution control bonds
refinanced in 1997 and two long-term bank notes that matured in 1998. This
decrease was partially offset by an increase in interest due to two first
mortgage bonds maturing in 1998 being replaced with senior notes at a slightly
higher interest rate. In 1997, interest on long-term debt decreased $3.0 million
or 12.1 percent from the prior year as a result of retirements and refinancings.
Distributions on preferred securities increased $3.2 million in 1998. This
increase was attributable to the issuance of $45 million of trust preferred
securities in January 1998 to replace preferred stock. In 1997, distributions on
preferred securities increased $2.8 million due to the issuance of $40 million
of trust preferred securities in January 1997.
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 utility plant with a long economic life. 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 securities. Any
recognition of inflation by regulatory authorities is reflected in the rate of
return allowed.
Future Earnings Potential
The results of operations for the past three years are not necessarily
indicative of future earnings potential. The level of future earnings depends on
numerous factors ranging from energy sales growth to a potentially less
regulated and more competitive environment.
Gulf Power currently operates as a vertically integrated utility providing
electricity to customers within its traditional service area located in
northwest Florida. Prices for electricity provided by the Company to retail
customers are set by the FPSC.
Future earnings in the near term will depend upon growth in energy sales,
which is subject to a number of factors. Traditionally, these factors have
included weather, competition, changes in contracts with neighboring utilities,
energy conservation practiced by customers, the elasticity of demand, and the
rate of economic growth in the Company's service area. In the fourth quarter of
1998, the FPSC opened a docketed proceeding to consider whether the rate of
return authorized for another investor-owned electric utility subject to the
FPSC's jurisdiction continues to be reasonable under current market conditions.
Although no official action has been taken by the FPSC at this time with regard
to the authorized returns for Gulf Power or any of the other investor-owned
electric utilities subject to the FPSC's jurisdiction, a similar investigation
could be initiated by action of the FPSC or its staff at any time.
The electric utility industry in the United States is currently undergoing a
period of dramatic change as a result of regulatory and competitive factors.
Among the primary agents of change has been the Energy Policy Act of 1992
(Energy Act). The Company is positioning the business to meet the challenge of
this major change in the traditional practice of selling electricity. The Energy
Act allows independent power producers (IPPs) to access the Company's
transmission network in order to sell electricity to other utilities. This
enhances the incentive for IPPs to build cogeneration plants for industrial and
II-127
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 1998 Annual Report
commercial customers and sell energy generation to other utilities. The Company
has and will continue to evaluate opportunities to partner and participate in
profitable cogeneration projects. In 1998, partnering with one of the Company's
largest industrial customers, construction was completed on 15 megawatts of
Company-owned cogeneration on the customer's plant site. Also, electricity sales
for resale rates are being driven down by wholesale transmission access and
numerous potential new energy suppliers, including power marketers and brokers.
The Company is aggressively working to maintain and expand its share of
wholesale sales in the southeastern power markets.
Although the Energy Act does not permit retail customer access, it was a
major catalyst for the current restructuring and consolidation taking place
within the utility industry. Numerous federal and state initiatives are in
varying stages to promote wholesale and retail competition. Among other things,
these initiatives allow customers to choose their electricity provider. As the
initiatives materialize, the structure of the utility industry could radically
change. Some states have approved initiatives that result in a separation of the
ownership and/or operation of generating facilities from the ownership and/or
operation of transmission and distribution facilities. While various
restructuring and competition initiatives have been or are being discussed in
Florida, none have been enacted to date. Enactment would require numerous issues
to be resolved, including significant ones relating to transmission pricing and
recovery of any stranded investments. The inability of the Company to recover
its investments, including the regulatory assets described in Note 1 to the
financial statements, could have a material adverse effect on the financial
condition of the Company. The Company is attempting to minimize or reduce its
cost exposure.
Continuing to be a low-cost producer could provide opportunities to increase
market share and profitability in markets that evolve with changing regulation.
Conversely, 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.
In 1996, the FPSC approved a new optional Commercial/Industrial Service Rider
(CISR), which is applicable to the rate schedules for the Company's largest
existing and potential customers who are able to show they have viable
alternatives to purchasing the Company's energy services. The CISR, approved as
a pilot program, provides the flexibility needed to enable the Company to offer
its services in a more competitive manner to these customers. The publicity of
the CISR ruling, increased competitive pressures, and general awareness of
customer choice pilots and proposals across the country have stimulated interest
on the part of customers in custom tailored offerings. The Company has
participated in one-on-one discussions with many of these customers, and has
negotiated and executed two Contract Service Agreements within the CISR pilot
program.
The FPSC will set new conservation goals and approve programs to accomplish
the goals by year-end 1999. Conservation goals are set every five years for a
ten-year period. The last conservation goals proceeding was in 1994 and
established demand-side management programs and conservation goals for 1995 to
2004. In the previous and current goals proceedings, the emphasis remains on
using price flexibility and competitive offerings of energy efficient products
and services. The new goals will be for the 2000 to 2009 period.
Compliance costs related to current and future environmental laws and
regulations 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." Also, Florida legislation adopted in 1993 that provides
for recovery of prudent environmental compliance costs is discussed in Note 3 to
the financial statements under "Environmental Cost Recovery."
The Company is subject to the provisions of Financial Accounting Standards
Board (FASB) Statement No. 71, Accounting for the Effects of Certain Types of
Regulation. In the event that a portion of the Company's operations is no longer
subject to these provisions, the Company would be required to write off related
regulatory assets and liabilities that are not specifically recoverable, and
determine if any other assets have been impaired. See Note 1 to the financial
statements under "Regulatory Assets and Liabilities" for additional information.
II-128
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 1998 Annual Report
Exposure to Market Risks
Due to cost-based rate regulation, the Company has limited exposure to market
volatility in interest rates and prices of electricity. To mitigate residual
risks relative to movements in electricity prices, the Company enters into fixed
price contracts for the purchase and sale of electricity through the wholesale
electricity market. Realized gains and losses are recognized in the income
statements as incurred. At December 31, 1998, exposure from these activities was
not material to the Company's financial position, results of operations, or cash
flows. Also, based on the Company's overall interest rate exposure at December
31, 1998, a near-term 100 basis point change in interest rates would not
materially affect the Company's financial statements.
New Accounting Standards
The FASB has issued Statement No. 133, Accounting for Derivative Instruments and
Hedging Activities, which must be adopted by the year 2000. This statement
establishes accounting and reporting standards for derivative instruments -
including certain derivative instruments embedded in other contracts - and for
hedging activities. Adoption of this statement is not expected to have a
material impact on the Company's financial statements.
In March 1998, the American Institute of Certified Public Accountants (AICPA)
issued a new Statement of Position, Accounting for the Costs of Computer
Software Developed or Obtained for Internal Use. This statement requires
capitalization of certain costs of internal-use software. The Company adopted
this statement in January 1999, and it is not expected to have a material impact
on the financial statements.
In April 1998, the AICPA issued a new Statement of Position, Reporting on the
Costs of Start-up Activities. This statement requires that the costs of start-up
activities and organizational costs be expensed as incurred. Any of these costs
previously capitalized by a company must be written off in the year of adoption.
The Company adopted this statement in January 1999, and it is not expected to
have a material impact on the financial statements.
In December 1998, the Emerging Issues Task Force (EITF) of the FASB issued
EITF No. 98-10, Accounting for Contracts Involved in Energy Trading and Risk
Management Activities. The EITF requires that energy trading contracts must be
marked to market through the income statement, with gains and losses reflected
rather than revenues and purchased power. Energy trading contracts are defined
as energy contracts entered into with the objective of generating profits on or
from exposure to shifts or changes in market prices. The Company adopted the
required accounting in January 1999, and it is not expected to have a material
impact on the financial statements.
Year 2000
Year 2000 Challenge
In order to save storage space, computer programmers in the 1960s and 1970s
shortened the year portion of date entries to just two digits. Computers
assumed, in effect, that all years began with "19." This practice was widely
adopted and hard-coded into computer chips and processors found in some
equipment. This approach, intended to save processing time and storage space,
was used until the mid-1990s. Unless corrected before the year 2000, affected
software systems and devices containing a chip or microprocessor with date and
time functions could incorrectly process dates or the systems may cease to
function.
The Company depends on complex computer systems for many aspects of its
operations, which include generation, transmission, and distribution of
electricity, as well as other business support activities. The Company's goal is
to have critical devices or software that are required to maintain operations to
be Year 2000 ready by June 1999. Year 2000 ready means that a system or
application is determined suitable for continued use through the Year 2000 and
beyond. Critical systems include, but are not limited to, turbine generator
systems, control center computer systems, customer service systems, energy
management systems, and telephone switches and equipment.
Year 2000 Program and Status
The Company's executive management recognizes the seriousness of the Year 2000
challenge and has dedicated what it believes to be adequate resources to address
the issue. The Millennium Project is a team of employees, IBM consultants, and
other contractors whose progress is reviewed on a monthly basis by a steering
committee of Southern Company executives.
II-129
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 1998 Annual Report
The work was divided into two phases. Phase I began in 1996 and consisted of
identifying and assessing corporate assets related to software systems and
devices that contain a computer chip or clock. The first phase was completed in
June 1997. Phase 2 consists of testing and remediating high priority systems and
devices. Also, contingency planning is included in this phase. Completion of
Phase 2 is targeted for June 1999. The Millennium Project will continue to
monitor the affected computer systems, devices, and applications into the Year
2000.
Southern Company has completed more than 70 percent of the activities
contained in its work plan. The percentage of completion and projected
completion dates by function are as follows:
- - - - - - - ------------------------------------------------------------------
Work Plan
-----------------------------------------
Remediation Project
Inventory Assessment Testing Completion
- - - - - - - ------------------------------------------------------------------
Generation 100% 100% 70% 6/99
- - - - - - - ------------------------------------------------------------------
Energy Management 100 100 90 6/99
- - - - - - - ------------------------------------------------------------------
Transmission and
Distribution 100 100 100 1/99
- - - - - - - ------------------------------------------------------------------
Telecommunications 100 100 50 6/99
- - - - - - - ------------------------------------------------------------------
Corporate Applications 100 100 90 3/99
- - - - - - - ------------------------------------------------------------------
Year 2000 Costs
The Company's current projected total costs for Year 2000 readiness are
approximately $4.8 million. These costs include labor necessary to identify,
test, and renovate affected devices and systems. From its inception through
December 31, 1998, the Year 2000 program costs, recognized as expense, amounted
to $3.0 million, of which $2.5 million was recorded in 1998.
Year 2000 Risks
The Company is implementing a detailed process to minimize the possibility of
service interruptions related to the Year 2000. The Company believes, based on
current tests, that the system can provide customers with electricity. These
tests increase confidence, but do not guarantee error-free operation. The
Company is taking what it believes to be prudent steps to prepare for the Year
2000, and it expects any interruptions in service that may occur within the
Company's service territory to be isolated and short in duration.
The Company expects the risks associated with Year 2000 to be no more severe
than the scenarios that its electric system is routinely prepared to handle. The
most likely worst case scenario consists of the service loss of one of the
largest generating units and/or the service loss of any single bulk transmission
element in its service territory. The Company has followed a proven methodology
for identifying and assessing software and devices containing potential Year
2000 challenges. Remediation and testing of those devices are in progress.
Following risk assessment, the Company is preparing contingency plans as
appropriate and is participating in North American Electric Reliability Council
- - - - - - - - coordinated national drills during 1999.
The Company is currently reviewing the Year 2000 readiness of material third
parties that provide goods and services crucial to the Company's operations.
Among such critical third parties are fuel, transportation, telecommunications,
water, chemical, and other suppliers. Contingency plans based on the assessment
of each third party's ability to continue supplying critical goods and services
to the Company are being developed.
There is a potential for some earnings erosion caused by reduced electrical
demand by customers because of their own Year 2000 issues.
Year 2000 Contingency Plans
Because of experience with hurricanes and other storms, the Company is skilled
at developing and using contingency plans in unusual circumstances. As part of
Year 2000 business continuity and contingency planning, the Company is drawing
on that experience to make risk assessments and is developing additional plans
to deal specifically with situations that could arise relative to Year 2000
challenges. The Company is identifying critical operational locations, and key
employees will be on duty at those locations during the Year 2000 transition. In
September 1999, drills are scheduled to be conducted to test contingency plans.
Because of the level of detail of the contingency planning process, management
feels that the contingency plans will keep any service interruptions that may
occur within the Company's service territory isolated and short in duration.
II-130
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 1998 Annual Report
FINANCIAL CONDITION
Overview
The Company's financial condition continues to be very solid. During 1998, gross
property additions were $69.7 million. Funds for the property additions were
provided by internal sources. See the Statements of Cash Flows for further
details.
Financing Activities
In 1998, the Company sold $45 million of trust preferred securities and $50
million of senior insured quarterly notes. Retirements, including maturities
during 1998, totaled $45 million of first mortgage bonds, $9.5 million of
preferred stock, and $8.3 million of long-term bank notes. The proceeds from the
issuance of $45 million of trust preferred securities were used to repay
short-term indebtedness that was used to redeem preferred stock tendered at the
end of 1997 and to redeem additional preferred stock during 1998. This
refinancing will result in savings of approximately $0.6 million annually. See
the Statements of Cash Flows for further details.
Composite financing rates for the years 1996 through 1998 as of year end were
as follows:
1998 1997 1996
-----------------------------
Composite interest rate on
long-term debt 6.1% 5.9% 6.1%
Composite rate on
trust preferred securities 7.3% 7.6% -
Composite preferred stock
dividend rate 5.1% 6.1% 6.4%
- - - - - - - -----------------------------------------------------------------
The composite interest rate on long-term debt increased in 1998 primarily as
a result of the maturity of two low-cost first mortgage bond issues, which were
replaced with long-term notes with a slightly higher interest rate. The decrease
in the composite preferred stock dividend rate in 1998 was primarily due to the
retirement of higher-cost preferred stock.
Capital Requirements for Construction
The Company's gross property additions, including those amounts related to
environmental compliance, are budgeted at $434 million for the three years
beginning in 1999 ($72 million in 1999, $100 million in 2000, and $262 million
in 2001). Actual construction costs may vary from this estimate because of
changes in such factors as: business conditions; environmental regulations; load
projections; the cost and efficiency of construction labor, equipment, and
materials; and the cost of capital. In addition, there can be no assurance that
costs related to capital expenditures will be fully recovered. The Company has
budgeted $263.6 million for the years 1999 through 2002 for the estimated cost
of a 532 megawatt combined cycle gas unit to be located in the eastern portion
of its service area. The unit is expected to have an in-service date of June
2002, subject to regulatory approval. The Company will continue its program to
maintain and upgrade transmission and distribution facilities and generating
plants.
Other Capital Requirements
In addition to the funds needed for the construction program, approximately $27
million will be required by the end of 2001 in connection with maturities of
long-term debt. Also, the Company will continue to retire higher-cost debt and
preferred securities and replace these securities 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 -- significantly
affected the Company. Specific reductions in sulfur dioxide and nitrogen oxide
emissions from fossil-fired generating plants are required in two phases. Phase
I compliance began in 1995 and initially affected 28 generating units of
Southern Company. As a result of Southern Company's compliance strategy, an
additional 22 generating units were brought into compliance with Phase I
requirements. Phase II compliance is required in 2000, and all fossil-fired
generating plants will be affected.
Southern Company achieved Phase I sulfur dioxide compliance at the affected
plants by switching to low-sulfur coal, which required some equipment upgrades.
Construction expenditures for Phase I compliance totaled approximately $300
million for Southern Company, including approximately $42 million for Gulf
Power.
II-131
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 1998 Annual Report
For Phase II sulfur dioxide compliance, Southern Company could use emission
allowances, increase fuel switching, and/or install flue gas desulfurization
equipment at selected plants. Also, equipment to control nitrogen oxide
emissions will be installed on additional system fossil-fired units as required
to meet Phase II limits. Current compliance strategy for Phase II and ozone
non-attainment could require total estimated construction expenditures for
Southern Company of approximately $70 million, of which $16 million remains to
be spent. Phase II compliance is not expected to have a material impact on Gulf
Power.
Following adoption of legislation in April of 1992 allowing electric
utilities in Florida to seek FPSC approval of their Clean Air Act Compliance
Plans, Gulf Power 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.
In 1993, the Florida Legislature adopted legislation that allows a utility to
petition the FPSC for recovery of prudent environmental compliance costs that
are not being recovered through base rates or any other recovery mechanism. The
legislation is discussed in Note 3 to the financial statements under
"Environmental Cost Recovery." Substantially all of the costs for the Clean Air
Act and other new environmental legislation discussed below are expected to be
recovered through the Environmental Cost Recovery Clause.
In July 1997, the Environmental Protection Agency (EPA) revised the national
ambient air quality standards for ozone and particulate matter. This revision
makes the standards significantly more stringent. In September 1998, the EPA
issued the final regional nitrogen oxide rules to the states for implementation.
The states have one year to adopt and implement the new rules. The final rules
affect 22 states including Alabama and Georgia. See Note 6 to the financial
statements under "Joint Ownership Agreements" related to the Company's ownership
interest in Georgia Power's Plant Scherer Unit No. 3. The EPA rules are being
challenged in the courts by several states and industry groups. Implementation
of the final state rules could require substantial further reductions in
nitrogen oxide emissions from fossil-fired generating facilities and other
industry in these states. Implementation of the standards could result in
significant additional compliance costs and capital expenditures that cannot be
determined until the results of legal challenges are known and the states have
adopted their final rules.
The EPA and state environmental regulatory agencies are reviewing and
evaluating various other matters including: nitrogen oxide emission control
strategies for ozone non-attainment areas; additional controls for hazardous air
pollutant emissions; and hazardous waste disposal requirements. The impact of
new standards will depend on the development and implementation of applicable
regulations.
Gulf Power 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 substantial costs to clean up properties.
The Company conducts studies to determine the extent of any required cleanup
costs and has recognized in the financial statements costs to clean up known
sites. For additional information, see Note 3 to the financial statements under
"Environmental Cost Recovery."
Several major pieces of environmental legislation are being considered for
reauthorization or amendment by Congress. These include: the Clean Air Act; the
Clean Water Act; the Comprehensive Environmental Response, Compensation and
Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances
Control Act; and the Endangered Species Act. Changes to these laws could affect
many areas of the Company's operations. The full impact of any such changes
cannot be determined at this time.
Compliance with possible additional legislation related to global climate
change, electric and magnetic fields, and other environmental 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 electric and magnetic fields.
Sources of Capital
At December 31, 1998, the Company had approximately $1.0 million of cash and
cash equivalents and $35.5 million of unused committed lines of credit with
banks to meet its short-term cash needs. Refer to Statements of Cash Flows for
II-132
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 1998 Annual Report
details related to the Company's financing activities. See Note 5 to the
financial statements under "Bank Credit Arrangements" for additional
information.
The Company historically has relied on issuances of first mortgage bonds and
preferred stock, in addition to pollution control revenue bonds issued for its
benefit by public authorities, to meet its long-term external financing
requirements. Recently, the Company's financings have consisted of unsecured
debt and trust preferred securities. In this regard, the Company sought and
obtained stockholder approval in 1997 to amend its corporate charter eliminating
restrictions on the amounts of unsecured indebtedness it may incur.
If the Company chooses to issue first mortgage bonds or preferred stock, it
is required to meet certain coverage requirements specified in its mortgage
indenture and corporate charter. 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.
Cautionary Statement Regarding Forward-Looking Information
Gulf Power Company's 1998 Annual Report contains forward-looking and historical
information. The Company cautions that there are various important factors that
could cause actual results to differ materially from those indicated in the
forward-looking information; accordingly, there can be no assurance that such
indicated results will be realized. These factors include legislative and
regulatory initiatives regarding deregulation and restructuring of the electric
utility industry; the extent and timing of the entry of additional competition
in the Company's markets; potential business strategies--including acquisitions
or dispositions of assets or internal restructuring--that may be pursued by the
company; state and federal rate regulation; Year 2000 issues; changes in or
application of environmental and other laws and regulations to which the Company
is subject; political, legal and economic conditions and developments; financial
market conditions and the results of financing efforts; changes in commodity
prices and interest rates; weather and other natural phenomena; and other
factors discussed in the reports--including Form 10-K--filed from time to time
by the Company with the Securities and Exchange Commission.
II-133
STATEMENTS OF INCOME
For the Years Ended December 31, 1998, 1997, and 1996
Gulf Power Company 1998 Annual Report
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
1998 1997 1996
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Revenues:
Revenues $ 607,876 $ 609,096 $ 616,603
Revenues from affiliates 42,642 16,760 17,762
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Total operating revenues 650,518 625,856 634,365
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation-
Fuel 197,462 180,843 184,500
Purchased power from non-affiliates 29,369 11,938 8,300
Purchased power from affiliates 14,445 24,955 35,076
Other 119,011 126,266 115,154
Maintenance 57,286 47,988 51,050
Depreciation and amortization 59,129 57,874 56,645
Taxes other than income taxes 51,462 51,775 52,027
Federal and state income taxes (Note 8) 34,089 35,034 37,821
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Total operating expenses 562,253 536,673 540,573
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Operating Income 88,265 89,183 93,792
Other Income (Expense):
Interest income 931 1,203 1,921
Other, net (2,339) (992) (1,678)
Income taxes applicable to other income 1,890 1,584 248
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Income Before Interest Charges and Other 88,747 90,978 94,283
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Interest Charges and Other:
Interest on long-term debt 19,718 21,699 24,691
Other interest charges 2,548 2,076 1,824
Interest on notes payable 1,190 891 2,071
Amortization of debt discount, premium, and expense, net 2,100 2,281 2,087
Distributions on preferred securities of subsidiary trust 6,034 2,804 -
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Interest charges and other, net 31,590 29,751 30,673
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Net Income 57,157 61,227 63,610
Dividends on Preferred Stock 636 3,617 5,765
===========================================================================================================================
Net Income After Dividends on Preferred Stock $ 56,521 $ 57,610 $ 57,845
===========================================================================================================================
The accompanying notes are an integral part of these statements.
II-134
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1998, 1997, and 1996
Gulf Power Company 1998 Annual Report
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------------
1998 1997 1996
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Activities:
Net income $ 57,157 $ 61,227 $ 63,610
Adjustments to reconcile net income to net
cash provided by operating activities --
Depreciation and amortization 69,633 72,860 71,825
Deferred income taxes (4,684) (7,047) 2,157
Accumulated provision for property damage 2,308 2,572 4,227
Deferred costs of 1995 coal contract renegotiation - 1,246 10,931
Other, net 1,155 1,012 1,468
Changes in certain current assets and liabilities --
Receivables, net 11,308 (692) 391
Inventories (4,308) 10,674 12,957
Payables 823 1,398 (7,078)
Taxes accrued (7,960) 6,123 (441)
Current costs of 1995 coal contract renegotiation 812 14,146 (5,099)
Other (11,323) 2,028 5,937
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities 114,921 165,547 160,885
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (69,731) (54,289) (61,386)
Other 5,990 509 (2,786)
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities (63,741) (53,780) (64,172)
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------------
Financing Activities and Capital Contributions:
Proceeds:
Preferred securities 45,000 40,000 -
First mortgage bonds - - 55,000
Pollution control bonds - 40,930 33,275
Capital contributions from parent 522 - -
Other long-term debt 50,000 20,000 49,148
Retirements:
Preferred stock (9,455) (75,911) -
First mortgage bonds (45,000) (25,000) (50,930)
Pollution control bonds - (40,930) (33,275)
Other long-term debt (8,326) (15,972) (34,923)
Notes payable, net (15,500) 22,000 (55,500)
Payment of preferred stock dividends (792) (5,370) (5,749)
Payment of common stock dividends (67,200) (64,600) (48,300)
Miscellaneous (4,167) (3,014) (5,332)
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------------
Net cash used for financing activities (54,918) (107,867) (96,586)
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents (3,738) 3,900 127
Cash and Cash Equivalents at Beginning of Year 4,707 807 680
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 969 $ 4,707 $ 807
====================================================================================================================================
Supplemental Cash Flow Information:
Cash paid during the year for --
Interest (net of amount capitalized) $28,044 $26,558 $26,050
Income taxes $38,782 $36,010 $25,858
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------------
( ) Denotes use of cash.
The accompanying notes are an integral part of these statements.
II-135
BALANCE SHEETS
At December 31, 1998 and 1997
Gulf Power Company 1998 Annual Report
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
ASSETS 1998 1997
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Utility Plant:
Plant in service (Notes 1 and 6) $ 1,809,901 $ 1,762,244
Less accumulated provision for depreciation 784,111 737,767
--------------------------------------------------------------------------------------------------------------------------------
1,025,790 1,024,477
Construction work in progress 34,863 31,030
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Total 1,060,653 1,055,507
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Other Property and Investments 588 622
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Current Assets:
Cash and cash equivalents 969 4,707
Receivables-
Customer accounts receivable 49,067 57,057
Other accounts and notes receivable 3,514 2,744
Affiliated companies 3,442 7,329
Accumulated provision for uncollectible accounts (996) (796)
Fossil fuel stock, at average cost 24,213 19,296
Materials and supplies, at average cost (Note 1) 28,025 28,634
Deferred coal contract costs (Note 5) - 4,456
Regulatory clauses under recovery (Note 1) 9,737 1,675
Prepayments 5,690 2,171
Vacation pay deferred 4,035 4,057
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Total 127,696 131,330
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets:
Deferred charges related to income taxes (Note 8) 25,308 26,586
Debt expense and loss, being amortized 21,448 22,941
Prepaid pension costs (Note 2) 13,770 10,385
Deferred storm charges (Note 1) - 703
Miscellaneous 18,438 17,538
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Total 78,964 78,153
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Total Assets $ 1,267,901 $ 1,265,612
================================================================================================================================
The accompanying notes are an integral part of these statements.
II-136
BALANCE SHEETS
At December 31, 1998 and 1997
Gulf Power Company 1998 Annual Report
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
CAPITALIZATION AND LIABILITIES 1998 1997
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Capitalization (See accompanying statements):
Common stock equity (Note 11) $ 427,652 $ 428,718
Preferred stock 4,236 13,691
Company obligated mandatorily redeemable preferred securities of
subsidiary trusts holding Company Junior Subordinated Notes (Note 9) 85,000 40,000
Long-term debt 317,341 296,993
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Total 834,229 779,402
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Current Liabilities:
Long-term debt due within one year (Note 10) 27,000 53,327
Notes payable 31,500 47,000
Accounts payable-
Affiliated companies 19,756 14,334
Other 23,697 20,205
Customer deposits 12,560 13,778
Taxes accrued 7,432 8,258
Interest accrued 5,184 7,227
Regulatory clauses over recovery (Note 1) 6,037 5,062
Vacation pay accrued 4,035 4,057
Dividends declared 54 10,210
Miscellaneous 3,960 8,739
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Total 141,215 192,197
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes (Note 8) 166,118 166,302
Deferred credits related to income taxes (Note 8) 52,465 56,935
Accumulated deferred investment tax credits 29,632 31,552
Accumulated provision for postretirement benefits (Note 2) 23,534 20,491
Accumulated provision for property damage (Note 1) 1,605 -
Miscellaneous 19,103 18,733
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Total 292,457 294,013
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Commitments and Contingent Matters (Notes 1, 2, 3, 4, 5, and 7)
Total Capitalization and Liabilities $ 1,267,901 $ 1,265,612
================================================================================================================================
The accompanying notes are an integral part of these statements.
II-137
STATEMENTS OF CAPITALIZATION
At December 31, 1998 and 1997
Gulf Power Company 1998 Annual Report
-----------------------------------------------------------------------------------------------------------------------------
1998 1997 1998 1997
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
Common Stock Equity:
Common stock, without par value --
Authorized and outstanding --
992,717 shares in 1998 and 1997 $ 38,060 $ 38,060
Paid-in capital 218,960 218,438
Premium on preferred stock 12 12
Retained earnings (Note 11) 170,620 172,208
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Total common stock equity 427,652 428,718 51.3 % 55.0 %
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Cumulative Preferred Stock:
$10 par value --
Authorized -- 10,000,000 shares
Outstanding -- 0 shares in 1998 and 377,989 shares in 1997
$25 stated capital --
6.72% - 8,661
Adjustable Rate - 789
$100 par value --
Authorized -- 801,626 shares
Outstanding -- 42,361 shares in 1998 and 42,411 shares in 1997
4.64% 1,250 1,255
5.16% 1,357 1,357
5.44% 1,629 1,629
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Total (annual dividend requirement -- $217,000) 4,236 13,691 0.5 1.8
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Company Obligated Mandatorily
Redeemable Preferred Securities (Note 9):
$25 Liquidation Value --
7.00% 45,000 -
7.625% 40,000 40,000
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Total (annual distribution requirement--$6,200,000) 85,000 40,000 10.2 5.1
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
II-138
STATEMENTS OF CAPITALIZATION (continued)
At December 31, 1998 and 1997
Gulf Power Company 1998 Annual Report
-----------------------------------------------------------------------------------------------------------------------------
1998 1997 1998 1997
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
Long-term Debt:
First mortgage bonds --
Maturity Interest Rates
April 1, 1998 5.55% - 15,000
July 1, 1998 5.00% - 30,000
July 1, 2003 6.125% 30,000 30,000
November 1, 2006 6.50% 25,000 25,000
January 1, 2026 6.875% 30,000 30,000
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Total first mortgage bonds 85,000 130,000
Pollution control revenue bonds--
Collateralized:
Maturity Interest Rates
April 1, 2006 5.25% 12,075 12,075
July 1, 2022 Variable - 5.10% at 1/1/99 40,930 40,930
April 1, 2023 6.20% 13,000 13,000
June 1, 2023 5.80% 32,550 32,550
November 1, 2023 5.70% 7,875 7,875
September 1, 2024 6.30% 22,000 22,000
September 1, 2024 Variable - 5.15% at 1/1/99 20,000 20,000
February 1, 2026 5.50% 21,200 21,200
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Total pollution control revenue bonds 169,630 169,630
Other long-term debt--
Maturity Interest Rates
Bank notes--
February 1, 1998 5.2125% - 5,754
April 1, 1998 6.44% - 2,573
November 20, 1999 Variable - 5.7163% at 1/1/99 13,500 13,500
November 20, 1999 Variable - 5.7163% at 1/1/99 13,500 13,500
Junior subordinated notes--
June 30, 2037 7.50% 20,000 20,000
Senior insured quarterly notes--
June 30, 2038 6.70% 50,000 -
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Total other long-term debt 97,000 55,327
Unamortized debt discount (7,289) (4,637)
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
requirement -- $21,365,000) 344,341 350,320
Less amount due within one year (Note 10) 27,000 53,327
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Long-term debt excluding amount due within one year 317,341 296,993 38.0 38.1
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Total Capitalization $ 834,229 $ 779,402 100.0 % 100.0 %
=============================================================================================================================
The accompanying notes are an integral part of these statements.
II-139
STATEMENTS OF RETAINED EARNINGS
For the Years Ended December 31, 1998, 1997, and 1996
Gulf Power Company 1998 Annual Report
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
1998 1997 1996
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
(in thousands)
Balance at Beginning of Year $ 172,208 $ 179,179 $ 179,663
Net income after dividends on preferred stock 56,521 57,610 57,845
Dividends on common stock (57,200) (64,600) (58,300)
Preferred stock transactions, net (909) 19 (29)
============================================================================================================================
Balance at End of Year (Note 11) $ 170,620 $ 172,208 $ 179,179
===========================================================================================================================
STATEMENTS OF PAID-IN CAPITAL
For the Years Ended December 31, 1998, 1997, and 1996
Gulf Power Company 1998 Annual Report
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
1998 1997 1996
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
(in thousands)
Balance at Beginning of Year $ 218,438 $ 218,438 $ 218,438
Capital contributions from parent 522 - -
===========================================================================================================================
Balance at End of Year $ 218,960 $ 218,438 $ 218,438
===========================================================================================================================
The accompanying notes are an integral part of these statements.
II-140
NOTES TO FINANCIAL STATEMENTS
Gulf Power Company 1998 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING
POLICIES
General
Gulf Power Company is a wholly owned subsidiary of Southern Company, which is
the parent company of five operating companies, a system service company,
Southern Communications Services (Southern LINC), Southern Company Energy
Solutions, Southern Energy, Inc. (Southern Energy), Southern Nuclear Operating
Company (Southern Nuclear), and other direct and indirect subsidiaries. The
operating companies (Alabama Power, Georgia Power, Gulf Power, Mississippi
Power, and Savannah Electric) provide electric service in four southeastern
states. Gulf Power Company provides electric service to the northwest panhandle
of Florida. Contracts among the operating 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) and/or the Securities and Exchange Commission. The system
service company provides, at cost, specialized services to Southern Company and
subsidiary companies. Southern LINC provides digital wireless communications
services to the operating companies and also markets these services to the
public within the Southeast. Southern Company Energy Solutions develops new
business opportunities related to energy products and services. Worldwide,
Southern Energy develops and manages electricity and other energy related
projects, including domestic energy trading and marketing. Southern Nuclear
provides services to Southern Company's nuclear power plants.
Southern Company is registered as a holding company under the Public Utility
Holding Company Act of 1935 (PUHCA). Both Southern Company and its subsidiaries
are subject to the regulatory provisions of the PUHCA. The Company is also
subject to regulation by the FERC and the Florida Public Service Commission
(FPSC). The Company follows generally accepted accounting principles and
complies with the accounting policies and practices prescribed by the FPSC. The
preparation of financial statements in conformity with generally accepted
accounting principles requires the use of estimates, and the actual results may
differ from those estimates.
Certain prior years' data presented in the financial statements have been
reclassified to conform with current year presentation.
Regulatory Assets and Liabilities
The Company is subject to the provisions of Financial Accounting Standards Board
(FASB) Statement No. 71, Accounting for the Effects of Certain Types of
Regulation. Regulatory assets represent probable future revenues to the Company
associated with certain costs that are expected to be recovered from customers
through the ratemaking process. Regulatory liabilities represent probable future
reductions in revenues associated with amounts that are expected to be credited
to customers through the ratemaking process. Regulatory assets and (liabilities)
reflected in the Balance Sheets at December 31 relate to the following:
1998 1997
--------------------------
(in thousands)
Deferred income tax debits $ 25,308 $ 26,586
Deferred loss on reacquired debt 18,883 20,494
Environmental remediation 7,076 7,338
Current & deferred
coal contract costs - 4,456
Vacation pay 4,035 4,057
Accumulated provision for
property damage (1,605) -
Deferred storm charges - 703
Regulatory clauses under (over)
recovery, net 3,700 (3,387)
Deferred income tax credits (52,465) (56,935)
Other, net (480) (629)
- - - - - - - ------------------------------------------------------------------
Total $ 4,452 $ 2,683
==================================================================
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 net regulatory assets and liabilities that are not specifically
recoverable through regulated rates. In addition, the Company would be required
to determine any impairment to other assets, including plant, and write down the
assets, if impaired, to their fair value.
II-141
NOTES (continued)
Gulf Power Company 1998 Annual Report
Revenues and Regulatory Cost Recovery Clauses
The Company currently operates as a vertically integrated utility providing
electricity to retail customers within its service area located in northwest
Florida and to wholesale customers in the Southeast. Revenues, less affiliated
transactions, by type of service were as follows:
1998 1997 1996
-------------------------------------
(in thousands)
Retail $509,118 $521,620 $530,729
Wholesale 61,893 63,697 63,201
Other operating 36,865 23,779 22,673
- - - - - - - ---------------------------------------------------------------
Total $607,876 $609,096 $616,603
===============================================================
The Company accrues revenues for service rendered but unbilled at the end of
each fiscal period. The Company has a diversified base of customers and no
single customer or industry comprises 10 percent or more of revenues. For all
periods presented, uncollectible accounts averaged significantly less than 1
percent of revenues.
Fuel costs are expensed as the fuel is used. The Company's electric rates
include provisions to periodically adjust billings for fluctuations in fuel
costs, the energy component of purchased power costs, and certain other costs.
The Company also has similar cost recovery clauses for energy conservation
costs, purchased power capacity costs, and environmental compliance costs.
Revenues are adjusted monthly for differences between recoverable costs and
amounts actually reflected in current rates.
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 1998 and 3.6 percent in 1997 and 1996. The increase in 1998 is
attributable to new depreciation rates, which were approved by the FPSC in 1998.
When property subject to depreciation is retired or otherwise disposed of in the
normal course of business, its cost -- together with the cost of removal, less
salvage -- is charged to the accumulated provision for depreciation. Minor items
of property included in the original cost of the plant are retired when the
related property unit is retired. Also, the provision for depreciation expense
includes an amount for the expected cost of removal of facilities.
Income Taxes
The Company uses the liability method of accounting for income taxes and
provides deferred income taxes for all significant income tax temporary
differences. Investment tax credits utilized are deferred and amortized to
income over the average lives of the related property. The Company is included
in the consolidated federal income tax return of Southern Company.
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
Temporary cash investments are considered cash equivalents. Temporary cash
investments are securities with original maturities of 90 days or less.
Financial Instruments
The Company's financial instruments for which the carrying amount did not equal
fair value at December 31 were as follows:
Carrying Fair
Amount Value
---------------------------
(in thousands)
Long-term debt:
At December 31, 1998 $344,341 $357,100
At December 31, 1997 $350,320 $356,766
Capital trust preferred
securities:
At December 31, 1998 $85,000 $89,400
At December 31, 1997 $40,000 $40,800
- - - - - - - --------------------------------------------------------------
The fair values for long-term debt and preferred securities were based on
either closing market prices or closing prices of comparable instruments.
II-142
NOTES (continued)
Gulf Power Company 1998 Annual Report
Materials and Supplies
Generally, materials and supplies include the cost of transmission,
distribution, and generating plant materials. Materials are charged to inventory
when purchased and then expensed or capitalized to plant, as appropriate, when
installed.
Provision for Injuries and Damages
The Company is subject to claims and suits arising in the ordinary course of
business. As permitted by regulatory authorities, the Company provides for the
uninsured costs of injuries and damages by charges to income amounting to $1.2
million annually. The expense of settling claims is charged to the provision to
the extent available. The accumulated provision of $1.3 million and $1.4 million
at December 31, 1998 and 1997, respectively, is included in miscellaneous
current liabilities in the accompanying Balance Sheets.
Provision for Property Damage
The Company provides for the cost of repairing damages from major storms and
other uninsured property damages. This includes the full cost of storm and other
damages to its transmission and distribution lines and the cost of uninsured
damages to its generation and other property. The expense of such damages is
charged to the provision account. At December 31, 1998, the accumulated
provision for property damage was $1.6 million. In 1995, the FPSC approved the
Company's request to increase the amount of its annual accrual to the
accumulated provision for property damage account from $1.2 million to $3.5
million and approved a target level for the accumulated provision account
between $25.1 and $36.0 million. The FPSC has also given the Company the
flexibility to increase its annual accrual amount above $3.5 million, when the
Company believes it is in a position to do so, until the account balance reaches
$12 million. The Company accrued $6.5 million in 1998 and $3.9 million in 1997
to the accumulated provision for property damage. Charges to the provision
account during 1998 totaled $4.2 million, which included $3.4 million related to
Hurricane Georges.
2. RETIREMENT BENEFITS
The Company has a defined benefit, trusteed, non-contributory pension plan that
covers substantially all regular employees. The Company provides certain medical
care and life insurance benefits for retired employees. Substantially all
employees may become eligible for these benefits when they retire. Trusts are
funded to the extent deductible under federal income tax regulations or to the
extent required by the Company's regulatory commissions. In 1998, the Company
adopted FASB Statement No. 132, Employers' Disclosure about Pensions and Other
Postretirement Benefits. The measurement date is September 30 for each year.
Pension Plan
Changes during the year in the projected benefit obligations and in the fair
value of plan assets were as follows:
Projected
Benefit Obligations
---------------------------
1998 1997
- - - - - - - ---------------------------------------------------------------
(in thousands)
Balance at beginning of year $130,794 $123,467
Service cost 4,107 3,897
Interest cost 9,572 9,301
Benefits paid (6,663) (4,852)
Actuarial loss (gain) and
employee transfers 5,202 (1,019)
- - - - - - - ---------------------------------------------------------------
Balance at end of year $143,012 $130,794
===============================================================
Plan Assets
---------------------------
1998 1997
- - - - - - - ---------------------------------------------------------------
(in thousands)
Balance at beginning of year $222,196 $191,152
Actual return on plan assets 1,310 35,886
Benefits paid (6,663) (4,852)
Employee transfers (3,909) 10
- - - - - - - ---------------------------------------------------------------
Balance at end of year $212,934 $222,196
===============================================================
II-143
NOTES (continued)
Gulf Power Company 1998 Annual Report
The accrued pension costs recognized in the Balance Sheet were as follows:
1998 1997
- - - - - - - ---------------------------------------------------------------
(in thousands)
Funded status $ 69,922 $ 91,402
Unrecognized transition
obligation (5,043) (5,764)
Unrecognized prior
service cost 4,869 5,244
Unrecognized net gain (55,978) (80,497)
- - - - - - - ---------------------------------------------------------------
Prepaid asset recognized
in the Balance Sheets $ 13,770 $ 10,385
===============================================================
Components of the plan's net periodic cost were as follows:
1998 1997 1996
- - - - - - - -----------------------------------------------------------------
Service cost $ 4,107 $ 3,897 $ 3,880
Interest cost 9,572 9,301 9,129
Expected return on
plan assets (14,827) (13,675) (13,410)
Recognized net gain (1,891) (1,656) (1,248)
Net amortization (347) (347) (443)
- - - - - - - -----------------------------------------------------------------
Net pension income $ (3,386) $ (2,480) $ (2,092)
=================================================================
The weighted average rates assumed in the actuarial calculations for both the
pension plan and postretirement benefits were:
1998 1997
- - - - - - - ----------------------------------------------------------
Discount 6.75% 7.50%
Annual salary increase 4.25% 5.00%
Long-term return on plan
assets 8.50% 8.50%
- - - - - - - ----------------------------------------------------------
Postretirement Benefits
Changes during the year in the projected benefit obligations and in the fair
value of plan assets were as follows:
Projected
Benefit Obligations
---------------------------
1998 1997
- - - - - - - ---------------------------------------------------------------
(in thousands)
Balance at beginning of year $39,669 $33,656
Service cost 946 896
Interest cost 3,123 2,845
Benefits paid (1,068) (1,077)
Actuarial loss and employee
transfers 3,614 3,349
Amendments 3,019 -
- - - - - - - ---------------------------------------------------------------
Balance at end of year $49,303 $39,669
===============================================================
Plan Assets
---------------------------
1998 1997
- - - - - - - ---------------------------------------------------------------
(in thousands)
Balance at beginning of year $9,455 $7,996
Actual return on plan assets 54 1,407
Employer contributions 1,162 1,129
Benefits paid (1,068) (1,077)
- - - - - - - ---------------------------------------------------------------
Balance at end of year $9,603 $9,455
===============================================================
The accrued postretirement costs recognized in the Balance Sheet were as
follows:
1998 1997
- - - - - - - ---------------------------------------------------------------
(in thousands)
Funded status $(39,700) $(30,214)
Unrecognized transition
obligation 5,079 5,435
Unrecognized prior
service cost 2,900 -
Unrecognized net loss 8,187 4,288
- - - - - - - ---------------------------------------------------------------
Accrued liability recognized
in the Balance Sheets $(23,534) $(20,491)
===============================================================
II-144
NOTES (continued)
Gulf Power Company 1998 Annual Report
Components of the plan's net periodic cost were as follows:
1998 1997 1996
- - - - - - - ---------------------------------------------------------------
Service cost $ 946 $ 896 $ 939
Interest cost 3,123 2,845 2,330
Expected return on
plan assets (717) (641) (565)
Transition obligation 356 356 356
Prior service cost 119 - -
Recognized net loss 128 184 86
- - - - - - - ---------------------------------------------------------------
Net postretirement cost $3,955 $3,640 $3,146
===============================================================
An additional assumption used in measuring the accumulated postretirement
benefit obligations was a weighted average medical care cost trend rate of 8.30
percent for 1998, decreasing gradually to 4.75 percent through the year 2005,
and remaining at that level thereafter. An annual increase or decrease in the
assumed medical care cost trend rate of 1 percent would affect the accumulated
benefit obligation and the service and interest cost components at December 31,
1998 as follows (in thousands):
1 Percent 1 Percent
Increase Decrease
- - - - - - - ------------------------------------------------- -------------
Benefit obligation $3,808 $(3,218)
Service and interest costs $319 $(261)
===============================================================
Work Force Reduction Programs
The Company recorded costs related to work force reduction programs of $2.8
million in 1998, $1.4 million in 1997, and $1.2 million in 1996. The Company has
also incurred its pro rata share for the costs of affiliated companies'
programs. The costs related to these programs were $0.2 million for 1998, $1.3
million for 1997, and $2.1 million for 1996. The Company has expensed all costs
related to these work force reduction programs.
3. LITIGATION AND REGULATORY MATTERS
FERC Review of Equity Returns
On September 21, 1998, the FERC entered separate orders affirming the outcome of
the administrative law judge's opinions in two proceedings in which the return
on common equity component of formula rates contained in substantially all of
the Company's wholesale power contracts was being challenged as unreasonably
high. These orders resulted in no change in the wholesale power contracts that
were the subject of such proceedings. The FERC also dismissed a complaint filed
by three customers under long-term power sales agreements seeking to lower the
equity return component in such agreements. These customers have filed
applications for rehearing regarding each FERC order. In response to a
requirement of the September 1998 FERC order, Southern Company filed a new
equity return component on the long-term power sales contracts, to be effective
January 5, 1999. The proposed equity return was lowered from 13.75 percent to
12.50 percent. The estimated impact on the Company's revenues at a 12.50% equity
return would be approximately $0.8 million annually. The FERC placed the new
rates into effect subject to refund. Also, this filing was consolidated with the
new proceeding discussed below.
On December 28, 1998, the FERC staff filed a motion asking the FERC to
initiate a new proceeding regarding the equity return and other issues involving
the Company's formula rate contracts. The motion was submitted pursuant to
review procedures applicable to these contracts, and would be applicable to
billings under such contracts on and after January 1, 1999.
Environmental Cost Recovery
In April 1993, the Florida Legislature adopted legislation for an Environmental
Cost Recovery Clause (ECRC), which allows a utility to petition the FPSC for
recovery of all prudent environmental compliance costs that are not being
recovered through base rates or any other recovery mechanism. Such environmental
costs include operation and maintenance expense, emission allowance expense,
depreciation, and a return on invested capital.
In January 1994, the FPSC approved the Company's initial petition under the
ECRC for recovery of environmental costs. Initially, recovery under the ECRC was
determined semi-annually. The FPSC approved annual recovery periods beginning
with the October 1996 through September 1997 period. As of January 1999, the
annual recovery period will be on a calendar-year basis as approved by the FPSC
in May 1998. Recovery includes a true-up of the prior period and a projection of
the ensuing period. During 1998 and 1997, the Company recorded ECRC revenues of
$15.1 million and $10.2 million, respectively.
II-145
NOTES (continued)
Gulf Power Company 1998 Annual Report
At December 31, 1998, the Company's liability for the estimated costs of
environmental remediation projects for known sites was $7.1 million. These
estimated costs are expected to be expended from 1999 through 2005. These
projects have been approved by the FPSC for recovery through the ECRC discussed
above. Therefore, the Company recorded $1.7 million in current assets and
current liabilities and $5.4 million in deferred assets and liabilities
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 $72 million in 1999, $100 million in 2000, and
$262 million in 2001. 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, 1998, significant purchase commitments were outstanding in
connection with the construction program. The Company has budgeted $263.6
million for the years 1999 through 2002 for the estimated cost of a 532 megawatt
combined cycle gas unit to be located in the eastern portion of its service
area. The unit is expected to have an in-service date of June 2002, subject to
regulatory approval. The Company will continue its construction program 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
from operations; the sale of additional first mortgage bonds, long-term
unsecured debt, pollution control bonds, and preferred securities; bank notes;
and capital contributions from Southern Company. In addition, the Company may
issue additional long-term debt and preferred securities primarily for debt
maturities and redemptions of higher-cost securities.
Bank Credit Arrangements
At December 31, 1998, the Company had $41.5 million of lines of credit with
banks subject to renewal June 1 of each year, of which $35.5 million remained
unused. In addition, the Company has two unused committed lines of credit
totaling $61.9 million that were established for liquidity support of its
variable rate pollution control bonds. In connection with these credit lines,
the Company has agreed to pay commitment fees and/or to maintain compensating
balances with the banks. The compensating balances, which represent
substantially all of the cash of the Company except for daily working funds and
like items, are not legally restricted from withdrawal. In addition, the Company
has bid-loan facilities with thirteen major money center banks that total $205
million, of which $25.5 million was committed at December 31, 1998.
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.
II-146
NOTES (continued)
Gulf Power Company 1998 Annual Report
Fuel Commitments
To supply a portion of the fuel requirements of its generating plants, the
Company has entered into long-term commitments for the procurement of fuel. In
most cases, these contracts contain provisions for price escalations, minimum
purchase levels, and other financial commitments. Total estimated long-term
obligations at December 31, 1998, including the Company's portion relating to
jointly owned facilities, were as follows:
Year Fuel
--------- ----------------
(in millions)
1999 $132
2000 88
2001 79
2002 78
2003 83
2004 - 2008 359
----------------------------------------------------------
Total commitments $819
==========================================================
In 1988, the Company made an advance payment of $60 million to a coal
supplier under an arrangement to lower the cost of future coal purchased under
an existing contract. This payment was fully amortized to expense on a per ton
basis as of March 1998.
In December 1995, the Company made another payment of $22 million to the same
coal supplier under an arrangement to lower the cost of future coal and/or to
suspend the purchase of coal under an existing contract for 25 months. This
payment was fully amortized to expense on a per ton basis as of March 1998.
The amortization expense of these contract renegotiations was recovered
through the fuel cost recovery clause discussed under "Revenues and Regulatory
Cost Recovery Clauses" in Note 1.
Lease Agreements
In 1989, the Company and Mississippi Power jointly entered into a twenty-two
year operating lease agreement for the use of 495 aluminum railcars. In 1994, a
second lease agreement for the use of 250 additional aluminum railcars was
entered into for twenty-two years. Both of these leases are for the
transportation of coal to Plant Daniel. At the end of each lease term, the
Company has the option to renew the lease. In 1997, three additional lease
agreements for 120 cars each were entered into for three years, with a monthly
renewal option for up to an additional nine months.
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 inventories was $2.8 million in 1998, and $2.3 million in 1997.
The annual amounts for 1999 through 2003 are expected to be $2.8 million, $2.1
million, $1.7 million, $1.7 million, and $1.7 million respectively, and after
2003 are expected to total $16.1 million.
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. Plant
Scherer is a steam-electric generating plant located near Forsyth, Georgia. In
accordance with an operating agreement, Georgia Power acts as the Company's
agent with respect to the construction, operation, and maintenance of the unit.
The Company's pro rata share of expenses related to both plants is included
in the corresponding operating expense accounts in the Statements of Income.
II-147
NOTES (continued)
Gulf Power Company 1998 Annual Report
At December 31, 1998, the Company's percentage ownership and its investment
in these jointly owned facilities were as follows:
Plant Scherer Plant
Unit No. 3 Daniel
(coal-fired) (coal-fired)
-----------------------------
(in thousands)
Plant In Service $185,497(1) $224,907
Accumulated Depreciation $62,255 $113,327
Construction Work in Progress $615 $8,686
Nameplate Capacity (2)
(megawatts) 205 500
Ownership 25% 50%
- - - - - - - ------------------------------------------------------------------
(1) Includes net plant acquisition adjustment.
(2) Total megawatt nameplate capacity:
Plant Scherer Unit No. 3: 818
Plant Daniel: 1,000
7. LONG-TERM POWER SALES AGREEMENTS
The Company and the other operating affiliates have long-term contractual
agreements for the sale of capacity and energy to certain non-affiliated
utilities located outside the system's service area. The unit power sales
agreements are firm and pertain to capacity related to specific generating
units. Because the energy is generally sold at cost under these agreements,
profitability is primarily affected by revenues from capacity sales. The
capacity revenues from these sales were $22.5 million in 1998, $24.9 million in
1997, and $25.4 million in 1996. See Note 3 to the financial statements under
"FERC Review of Equity Returns."
Unit power from specific generating plants of Southern Company is currently
being sold to Florida Power Corporation (FPC), Florida Power & Light Company
(FP&L), Jacksonville Electric Authority (JEA), and the City of Tallahassee,
Florida. Under these agreements, 214 megawatts of net dependable capacity were
sold by the Company during 1998, and sales will remain at that level until the
expiration of the contracts in 2010, unless reduced by FPC, FP&L, and JEA after
2002.
Capacity and energy sales to FP&L, the Company's largest single customer,
provided revenues of $22.3 million in 1998, $25.4 million in 1997, and $27.2
million in 1996, or 3.4 percent, 4.1 percent, and 4.3 percent of operating
revenues, respectively.
8. INCOME TAXES
At December 31, 1998, the tax-related regulatory assets to be recovered from
customers were $25.3 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, 1998, the tax-related regulatory liabilities
to be credited to customers were $52.5 million. These liabilities are
attributable to deferred taxes previously recognized at rates higher than
current enacted tax law and to unamortized investment tax credits.
Details of the federal and state income tax provisions are as follows:
1998 1997 1996
------------------------------------
(in thousands)
Total provision for income taxes:
Federal--
Currently payable $31,746 $34,522 $31,022
Deferred--current year 18,485 19,297 26,072
--reversal of
prior years (22,952) (25,778) (24,780)
- - - - - - - --------------------------------------------------------------------
27,279 28,041 32,314
- - - - - - - --------------------------------------------------------------------
State--
Currently payable 5,137 5,975 4,394
Deferred--current year 2,745 2,868 3,904
--reversal of
prior years (2,962) (3,434) (3,039)
- - - - - - - --------------------------------------------------------------------
4,920 5,409 5,259
- - - - - - - --------------------------------------------------------------------
Total 32,199 33,450 37,573
Less income taxes
credited to other income (1,890) (1,584) (248)
- - - - - - - --------------------------------------------------------------------
Total income taxes charged
to operations $34,089 $35,034 $37,821
====================================================================
II-148
NOTES (continued)
Gulf Power Company 1998 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:
1998 1997
--------------------------
(in thousands)
Deferred tax liabilities:
Accelerated depreciation $155,833 $156,328
Property basis differences 20,330 19,220
Other 17,645 14,242
- - - - - - - ---------------------------------------------------------------------
Total 193,808 189,790
- - - - - - - ---------------------------------------------------------------------
Deferred tax assets:
Federal effect of state deferred taxes 9,509 9,268
Postretirement benefits 7,644 6,976
Other 10,702 10,861
- - - - - - - ---------------------------------------------------------------------
Total 27,855 27,105
- - - - - - - ---------------------------------------------------------------------
Net deferred tax liabilities 165,953 162,685
Less current portion, net (165) (3,617)
=====================================================================
Accumulated deferred income
taxes in the Balance Sheets $166,118 $166,302
=====================================================================
Deferred investment tax credits are amortized over the life of the related
property with such amortization normally applied as a credit to reduce
depreciation and amortization in the Statements of Income. Credits amortized in
this manner amounted to $1.9 million in 1998, $2.2 million in 1997, and $2.3
million in 1996. At December 31, 1998, 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:
1998 1997 1996
----------------------------
Federal statutory rate 35% 35% 35%
State income tax,
net of federal deduction 4 4 4
Non-deductible book
depreciation 1 1 1
Difference in prior years'
deferred and current tax rate (2) (1) (1)
Other, net (2) (4) (2)
- - - - - - - ----------------------------------------------------------------
Effective income tax rate 36% 35% 37%
================================================================
The Company and the other subsidiaries of Southern Company file a
consolidated federal tax return. Under a joint consolidated income tax
agreement, each subsidiary's current and deferred tax expense is computed on a
stand-alone basis. Tax benefits from losses of the parent company are allocated
to each subsidiary based on the ratio of taxable income to total consolidated
taxable income.
9. COMPANY OBLIGATED MANDATORILY
REDEEMABLE PREFERRED SECURITIES
In January 1997, Gulf Power Capital Trust I (Trust I), of which the Company owns
all of the common securities, issued $40 million of 7.625 percent mandatorily
redeemable preferred securities. Substantially all of the assets of Trust I are
$41 million aggregate principal amount of the Company's 7.625 percent junior
subordinated notes due December 31, 2036.
In January 1998, Gulf Power Capital Trust II (Trust II), of which the Company
owns all of the common securities, issued $45 million of 7.0 percent mandatorily
redeemable preferred securities. Substantially all of the assets of Trust II are
$46 million aggregate principal amount of the Company's 7.0 percent junior
subordinated notes due December 31, 2037.
The Company considers that the mechanisms and obligations relating to the
preferred securities, taken together, constitute a full and unconditional
guarantee by the Company of payment obligations with respect to the preferred
securities of Trust I and Trust II. Trust I and Trust II are subsidiaries of the
Company, and accordingly are consolidated in the Company's financial statements.
10. SECURITIES DUE WITHIN ONE YEAR
A summary of the improvement fund requirement and scheduled maturities and
redemptions of long-term debt due within one year at December 31 is as follows:
1998 1997
----------------------
(in thousands)
Bond improvement fund requirement $ 850 $1,300
Less portion to be satisfied by
certifying property additions 850 1,300
- - - - - - - -----------------------------------------------------------------
Cash requirement - -
Maturities of first mortgage bonds - 45,000
Current portion of other long-term
debt 27,000 8,327
- - - - - - - -----------------------------------------------------------------
Total $27,000 $53,327
=================================================================
The first mortgage bond improvement fund requirement amounts to 1 percent of
each outstanding series of bonds authenticated under the indenture prior to
II-149
NOTES (continued)
Gulf Power Company 1998 Annual Report
January 1 of each year, other than those issued to collateralize pollution
control revenue bond 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, 1998, retained earnings of $127 million were
restricted against the payment of cash dividends on common stock under the terms
of the mortgage indenture.
12. QUARTERLY FINANCIAL DATA (Unaudited)
Summarized quarterly financial data for 1998 and 1997 are as follows:
Net Income
After Dividends
Operating Operating on Preferred
Quarter Ended Revenues Income Stock
- - - - - - - --------------------------------------------------------------------
(in thousands)
March 1998 $140,950 $15,237 $ 6,853
June 1998 177,130 23,742 13,364
September 1998 199,377 34,070 26,989
December 1998 133,061 15,216 9,315
March 1997 $141,374 $20,212 $10,740
June 1997 145,292 19,153 10,386
September 1997 193,710 34,750 27,484
December 1997 145,480 15,068 9,000
- - - - - - - --------------------------------------------------------------------
The Company's business is influenced by seasonal weather conditions and the
timing of rate changes, among other factors.
II-150
SELECTED FINANCIAL AND OPERATING DATA
Gulf Power Company 1998 Annual Report
- - - - - - - --------------------------------------------------------------------------------------------------------------
1998 1997 1996
- - - - - - - --------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands) $650,518 $625,856 $634,365
Net Income after Dividends
on Preferred Stock (in thousands) $56,521 $57,610 $57,845
Dividends on Common Stock (in thousands) $57,200 $64,600 $58,300
Return on Average Common Equity (percent) 13.20 13.33 13.27
Total Assets (in thousands) $1,267,901 $1,265,612 $1,308,366
Gross Property Additions (in thousands) $69,731 $54,289 $61,386
- - - - - - - --------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $427,652 $428,718 $435,758
Preferred stock 4,236 13,691 65,102
Preferred stock subject to mandatory redemption - - -
Trust preferred securities 85,000 40,000 -
Long-term debt 317,341 296,993 331,880
- - - - - - - --------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $834,229 $779,402 $832,740
- - - - - - - --------------------------------------------------------------------------------------------------------------
Capitalization Ratios (percent):
Common stock equity 51.3 55.0 52.3
Preferred stock 0.5 1.8 7.8
Trust preferred securities 10.2 5.1 -
Long-term debt 38.0 38.1 39.9
- - - - - - - --------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0 100.0
==============================================================================================================
First Mortgage Bonds (in thousands):
Issued - - 55,000
Retired 45,000 25,000 50,930
Preferred Stock (in thousands):
Issued - - -
Retired 9,455 75,911 -
- - - - - - - --------------------------------------------------------------------------------------------------------------
Security Ratings:
First Mortgage Bonds -
Moody's A1 A1 A1
Standard and Poor's AA- AA- A+
Duff & Phelps AA- AA- AA-
Preferred Stock -
Moody's a2 a2 a2
Standard and Poor's A A A
Duff & Phelps A+ A+ A+
- - - - - - - --------------------------------------------------------------------------------------------------------------
Customers (year-end):
Residential 307,077 300,257 291,196
Commercial 46,370 44,589 43,196
Industrial 257 267 278
Other 268 264 162
- - - - - - - --------------------------------------------------------------------------------------------------------------
Total 353,972 345,377 334,832
==============================================================================================================
Employees (year-end) 1,328 1,328 1,384
II-151
SELECTED FINANCIAL AND OPERATING DATA
Gulf Power Company 1998 Annual Report
- - - - - - - ----------------------------------------------------------------------------------------------------------------------------
1995 1994 1993 1992
- - - - - - - ----------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands) $619,077 $578,813 $583,142 $570,902
Net Income after Dividends
on Preferred Stock (in thousands) $57,154 $55,229 $54,311 $54,090
Dividends on Common Stock (in thousands) $46,400 $44,000 $41,800 $39,900
Return on Average Common Equity (percent) 13.27 13.15 13.29 13.62
Total Assets (in thousands) $1,341,859 $1,315,542 $1,307,809 $1,062,699
Gross Property Additions (in thousands) $63,113 $78,869 $78,562 $64,671
- - - - - - - ----------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $436,242 $425,472 $414,196 $403,190
Preferred stock 89,602 89,602 89,602 74,662
Preferred stock subject to mandatory redemption - - 1,000 2,000
Trust preferred securities - - - -
Long-term debt 323,376 356,393 369,259 382,047
- - - - - - - ----------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $849,220 $871,467 $874,057 $861,899
- - - - - - - ----------------------------------------------------------------------------------------------------------------------------
Capitalization Ratios (percent):
Common stock equity 51.4 48.8 47.4 46.8
Preferred stock 10.5 10.3 10.4 8.9
Trust preferred securities - - - -
Long-term debt 38.1 40.9 42.2 44.3
- - - - - - - ----------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0 100.0 100.0
============================================================================================================================
First Mortgage Bonds (in thousands):
Issued - - 75,000 25,000
Retired 1,750 48,856 88,809 117,693
Preferred Stock (in thousands):
Issued - - 35,000 29,500
Retired 1,000 1,000 21,060 15,500
- - - - - - - ----------------------------------------------------------------------------------------------------------------------------
Security Ratings:
First Mortgage Bonds -
Moody's A1 A2 A2 A2
Standard and Poor's A+ A A A
Duff & Phelps A+ A+ A+ A
Preferred Stock -
Moody's a2 a2 a2 a2
Standard and Poor's A A- A- A-
Duff & Phelps A A A A-
- - - - - - - ----------------------------------------------------------------------------------------------------------------------------
Customers (year-end):
Residential 283,421 280,859 274,194 267,591
Commercial 41,281 40,398 39,253 37,105
Industrial 278 283 274 270
Other 134 106 86 74
- - - - - - - ----------------------------------------------------------------------------------------------------------------------------
Total 325,114 321,646 313,807 305,040
============================================================================================================================
Employees (year-end) 1,501 1,540 1,565 1,613
II-152A
SELECTED FINANCIAL AND OPERATING DATA
Gulf Power Company 1998 Annual Report
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
1991 1990 1989 1988
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands) $565,207 $567,825 $527,821 $550,827
Net Income after Dividends
on Preferred Stock (in thousands) $57,796 $38,714 $37,361 $45,698
Dividends on Common Stock (in thousands) $38,000 $37,000 $37,200 $35,400
Return on Average Common Equity (percent) 15.17 10.51 10.32 13.41
Total Assets (in thousands) $1,095,736 $1,084,579 $1,093,430 $1,097,225
Gross Property Additions (in thousands) $64,323 $62,462 $70,726 $67,042
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock 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
Trust preferred securities - - - -
Long-term debt 434,648 475,284 484,608 497,069
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $888,291 $910,881 $916,241 $923,291
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Capitalization Ratios (percent):
Common stock equity 44.0 40.8 39.9 38.8
Preferred stock 7.1 7.1 7.2 7.4
Trust preferred securities - - - -
Long-term debt 48.9 52.1 52.9 53.8
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0 100.0 100.0
===========================================================================================================================
First Mortgage Bonds (in thousands):
Issued 50,000 - - 35,000
Retired 32,807 6,455 9,344 9,369
Preferred Stock (in thousands):
Issued - - - -
Retired 2,500 1,750 1,250 1,750
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Security Ratings:
First Mortgage Bonds -
Moody's A2 A2 A1 A1
Standard and Poor's A A A A
Duff & Phelps A A AA- 4
Preferred Stock -
Moody's a2 a2 a1 a1
Standard and Poor's A- A- A- A-
Duff & Phelps A- A- A+ 5
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Customers (year-end):
Residential 261,210 256,111 251,341 246,450
Commercial 34,685 34,019 33,678 33,030
Industrial 264 252 240 206
Other 72 67 67 61
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Total 296,231 290,449 285,326 279,747
===========================================================================================================================
Employees (year-end) 1,598 1,615 1,614 1,601
II-152B
SELECTED FINANCIAL AND OPERATING DATA (continued)
Gulf Power Company 1998 Annual Report
- - - - - - - ----------------------------------------------------------------------------------------------------------------------------------
1998 1997 1996
- - - - - - - ----------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $276,208 $277,609 $285,498
Commercial 160,960 164,435 164,181
Industrial 69,850 77,492 78,994
Other 2,100 2,084 2,056
- - - - - - - ----------------------------------------------------------------------------------------------------------------------------------
Total retail 509,118 521,620 530,729
Sales for resale - non-affiliates 61,893 63,697 63,201
Sales for resale - affiliates 42,642 16,760 17,762
- - - - - - - ----------------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 613,653 602,077 611,692
Other revenues 36,865 23,779 22,673
- - - - - - - ----------------------------------------------------------------------------------------------------------------------------------
Total $650,518 $625,856 $634,365
==================================================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 4,437,558 4,119,492 4,159,924
Commercial 3,111,933 2,897,887 2,808,634
Industrial 1,833,575 1,903,050 1,808,086
Other 18,952 18,101 17,815
- - - - - - - ----------------------------------------------------------------------------------------------------------------------------------
Total retail 9,402,018 8,938,530 8,794,459
Sales for resale - non-affiliates 1,341,990 1,531,179 1,534,097
Sales for resale - affiliates 1,758,150 848,135 709,647
- - - - - - - ----------------------------------------------------------------------------------------------------------------------------------
Total 12,502,158 11,317,844 11,038,203
==================================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 6.22 6.74 6.86
Commercial 5.17 5.67 5.85
Industrial 3.81 4.07 4.37
Total retail 5.41 5.84 6.03
Sales for resale 3.37 3.38 3.61
Total sales 4.91 5.32 5.54
Average Annual Kilowatt-Hour Use Per Residential Customer 14,577 13,894 14,457
Average Annual Revenue Per Residential Customer $907.35 $936.30 $992.17
Plant Nameplate Capacity Ratings (year-end) (megawatts) 2,188 2,174 2,174
Maximum Peak-Hour Demand - Net of SEPA (megawatts):
Winter 2,040 1,844 2,136
Summer 2,146 2,032 1,961
Annual Load Factor (percent) 55.3 55.5 51.4
Plant Availability - Fossil-Steam (percent) 87.6 91.0 91.8
- - - - - - - ----------------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 89.2 87.1 87.8
Oil and gas 2.0 0.4 0.5
Purchased power -
From non-affiliates 5.5 3.5 2.7
From affiliates 3.3 9.0 9.0
- - - - - - - ----------------------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0
==================================================================================================================================
Total Fuel Economy Data:
BTU per net kilowatt-hour generated 10,523 10,436 10,484
Cost of fuel per million BTU (cents) 160.22 190.75 192.22
Average cost of fuel per net kilowatt-hour generated (cents) 1.69 1.99 2.02
==================================================================================================================================
II-153
SELECTED FINANCIAL AND OPERATING DATA (continued)
Gulf Power Company 1998 Annual Report
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------
1995 1994 1993 1992
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $276,155 $252,598 $244,967 $235,296
Commercial 159,260 146,394 137,308 133,071
Industrial 81,606 82,169 87,526 91,320
Other 1,993 1,955 1,882 1,784
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------
Total retail 519,014 483,116 471,683 461,471
Sales for resale - non-affiliates 60,413 66,111 72,209 70,078
Sales for resale - affiliates 18,619 17,353 23,166 24,075
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 598,046 566,580 567,058 555,624
Other revenues 21,031 12,233 16,084 15,278
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------
Total $619,077 $578,813 $583,142 $570,902
==============================================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 4,014,142 3,751,932 3,712,980 3,596,515
Commercial 2,708,243 2,548,846 2,433,382 2,369,236
Industrial 1,794,754 1,847,114 2,029,936 2,179,435
Other 17,345 17,354 16,944 16,649
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------
Total retail 8,534,484 8,165,246 8,193,242 8,161,835
Sales for resale - non-affiliates 1,396,474 1,418,977 1,460,105 1,430,908
Sales for resale - affiliates 759,341 874,050 1,029,787 1,208,771
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------
Total 10,690,299 10,458,273 10,683,134 10,801,514
==============================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 6.88 6.73 6.60 6.54
Commercial 5.88 5.74 5.64 5.62
Industrial 4.55 4.45 4.31 4.19
Total retail 6.08 5.92 5.76 5.65
Sales for resale 3.67 3.64 3.83 3.57
Total sales 5.59 5.42 5.31 5.14
Average Annual Kilowatt-Hour Use Per Residential Customer 14,148 13,486 13,671 13,553
Average Annual Revenue Per Residential Customer $973.35 $907.92 $901.96 $886.66
Plant Nameplate Capacity Ratings (year-end) (megawatts) 2,174 2,174 2,174 2,174
Maximum Peak-Hour Demand - Net of SEPA (megawatts):
Winter 1,732 1,801 1,571 1,533
Summer 2,040 1,795 1,898 1,828
Annual Load Factor (percent) 53.0 56.7 54.5 55.0
Plant Availability - Fossil-Steam (percent) 84.0 92.2 88.9 91.2
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 86.8 87.2 84.5 87.7
Oil and gas 0.4 0.2 0.5 0.1
Purchased power -
From non-affiliates 4.0 2.8 1.5 0.8
From affiliates 8.8 9.8 13.5 11.4
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0 100.0
==============================================================================================================================
Total Fuel Economy Data:
BTU per net kilowatt-hour generated 10,609 10,614 10,390 10,347
Cost of fuel per million BTU (cents) 196.62 189.55 197.37 200.30
Average cost of fuel per net kilowatt-hour generated (cents) 2.09 2.01 2.05 2.07
==============================================================================================================================
II-154A
SELECTED FINANCIAL AND OPERATING DATA (continued)
Gulf Power Company 1998 Annual Report
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
1991 1990 1989 1988
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $231,220 $217,843 $203,781 $184,036
Commercial 130,691 124,066 118,897 107,615
Industrial 92,300 91,041 84,671 72,634
Other 1,860 1,805 1,586 1,402
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Total retail 456,071 434,755 408,935 365,687
Sales for resale - non-affiliates 69,636 73,855 67,554 117,466
Sales for resale - affiliates 29,343 38,563 39,244 48,277
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 555,050 547,173 515,733 531,430
Other revenues 10,157 20,652 12,088 19,397
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Total $565,207 $567,825 $527,821 $550,827
===========================================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 3,455,100 3,360,838 3,293,750 3,154,541
Commercial 2,272,690 2,217,568 2,169,497 2,088,598
Industrial 2,117,408 2,177,872 2,094,670 1,968,091
Other 17,118 18,866 17,209 16,257
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Total retail 7,862,316 7,775,144 7,575,126 7,227,487
Sales for resale - non-affiliates 1,550,018 1,775,703 1,640,355 1,911,759
Sales for resale - affiliates 1,236,223 1,435,558 1,461,036 2,326,238
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Total 10,648,557 10,986,405 10,676,517 11,465,484
===========================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 6.69 6.48 6.19 5.83
Commercial 5.75 5.59 5.48 5.15
Industrial 4.36 4.18 4.04 3.69
Total retail 5.80 5.59 5.40 5.06
Sales for resale 3.55 3.50 3.44 3.91
Total sales 5.21 4.98 4.83 4.64
Average Annual Kilowatt-Hour Use Per Residential Customer 13,320 13,173 13,173 12,883
Average Annual Revenue Per Residential Customer $891.38 $853.86 $815.00 $751.60
Plant Nameplate Capacity Ratings (year-end) (megawatts) 2,174 2,174 2,174 2,174
Maximum Peak-Hour Demand - Net of SEPA (megawatts):
Winter 1,418 1,310 1,814 1,395
Summer 1,740 1,778 1,691 1,613
Annual Load Factor (percent) 57.0 55.2 52.6 56.5
Plant Availability - Fossil-Steam (percent) 92.2 89.2 89.1 88.2
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 82.0 69.8 78.3 93.2
Oil and gas 0.1 0.5 0.2 0.4
Purchased power -
From non-affiliates 0.5 0.6 0.4 0.4
From affiliates 17.4 29.1 21.1 6.0
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0 100.0
===========================================================================================================================
Total Fuel Economy Data:
BTU per net kilowatt-hour generated 10,636 10,765 10,621 10,461
Cost of fuel per million BTU (cents) 203.60 206.06 193.70 178.00
Average cost of fuel per net kilowatt-hour generated (cents) 2.17 2.22 2.06 1.86
===========================================================================================================================
II-154B
MISSISSIPPI POWER COMPANY
FINANCIAL SECTION
II-155
MANAGEMENT'S REPORT
Mississippi Power Company 1998 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/ Dwight H. Evans
Dwight H. Evans
President and Chief Executive Officer
/s/ Michael W. Southern
Michael W. Southern
Vice President, Secretary, Treasurer and
Chief Financial Officer
February 10, 1999
II-156
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To 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 Southern Company) as of December 31, 1998 and 1997, 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, 1998. 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-167 through II-182)
referred to above present fairly, in all material respects, the financial
position of Mississippi Power Company as of December 31, 1998 and 1997, and the
results of its operations and its cash flows for each of the three years in the
period ended December 31, 1998, in conformity with generally accepted
accounting principles.
/s/ Arthur Andersen LLP
Arthur Andersen LLP
Atlanta, Georgia
February 10, 1999
11-157
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Mississippi Power Company 1998 Annual Report
RESULTS OF OPERATIONS
Earnings
Mississippi Power Company's 1998 net income after dividends on preferred stock
was $55.1 million, reflecting a 2.0 percent or $1.1 million increase over the
prior year. This change is primarily attributable to higher retail and wholesale
revenues. In 1997, earnings were $54.0 million, up $1.3 million from the prior
year. This earnings increase resulted primarily from lower operating expenses.
Revenues
The following table summarizes the factors impacting operating revenues for the
past three years:
Increase (Decrease)
From Prior Year
-------------------------------------
1998 1997 1996
-------------------------------------
(in thousands)
Retail --
Change in base
rates (PEP and
ECO Plan) $ 335 $ 3,177 $ (402)
Sales growth 4,787 109 11,187
Weather 7,091 (1,118) (5,585)
Fuel cost
recovery
and other 13,112 948 (1,255)
-----------------------------------------------------------------
Total retail 25,325 3,116 3,945
---------------------------------------------------- ------------
Sales for resale --
Non-affiliates 16,084 5,464 7,776
Affiliates 8,142 (11,606) 14,139
-----------------------------------------------------------------
Total sales for
resale 24,226 (6,142) 21,915
Other operating
revenues 1,992 2,585 1,616
-----------------------------------------------------------------
Total operating
revenues $51,543 $ (441) $27,476
=================================================================
Percent change 9.5% (0.1)% 5.3%
-----------------------------------------------------------------
Retail revenues of $443 million in 1998 increased 6.1 percent from 1997.
Continued growth in the service area and the positive impact of weather on
energy sales were the predominant factors contributing to the rise in revenues.
Retail revenues for 1997 reflected a 0.8 percent increase over the prior year
due to the 1996 Performance Evaluation Plan (PEP) retail rate increase and the
January 1997 Environmental Compliance Overview Plan (ECO Plan) retail rate
increase. Changes in base rates reflect any rate changes made under the PEP and
ECO Plan.
Fuel revenues generally represent the direct recovery of fuel expense
including purchased power. Therefore, changes in recoverable fuel expenses are
offset with corresponding changes in fuel revenues and have no effect on net
income.
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.
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 9.8 percent in 1998 and
3.6 percent in 1997, with the related revenues rising 11.3 percent and 1.6
percent, respectively. The customer demand experienced by these utilities is
determined by factors very similar to Mississippi Power's. Revenues from other
sales outside the service area increased in 1998 and 1997 primarily due to power
marketing activities. These increases were primarily offset by increases in
purchased power from non-affiliates and, as a result, had no significant effect
on net income.
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.
11-158
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 1998 Annual Report
Below is a breakdown of kilowatt-hour sales for 1998 and the percent change
for the last three years:
1998 Percent Change
----------- ------------------------------
KWH 1998 1997 1996
(in millions)
Residential 2,249 10.3% (2.0)% 1.9%
Commercial 2,623 9.0 4.0 3.3
Industrial 3,729 (6.4) 0.6 3.8
Other 40 - 2.6 1.9
----------
Total retail 8,641 2.0 0.9 3.2
Sales for
Resale --
Non-affiliates 3,158 9.1 6.2 9.4
Affiliates 552 15.2 (31.0) 184.7
----------
Total 12,351 4.3 0.2 8.7
==================================================================
Residential and commercial sales increased in 1998 10.3 percent and 9.0
percent respectively, and industrial sales decreased 6.4 percent. The increases
can be attributed primarily to sales growth and hotter temperatures in the
summer months. The decrease in industrial sales was due primarily to a large
industrial customer being out of service because of damages incurred from
Hurricane Georges. Residential sales in 1997 declined 2.0 percent while sales to
commercial and industrial customers increased by 4.0 percent and 0.6 percent,
respectively. Milder-than-normal temperatures experienced in 1997 contributed to
the moderate sales.
The Company anticipates continued growth in energy sales as the economy
improves within its service area. The casino industry and ancillary services,
such as lodging, food, transportation, etc., are some of the factors that may
influence the economy of the Company's service area. Also, energy demand is
expected to grow as a result of a larger and more fully employed population.
Expenses
Total operating expenses were $515 million in 1998 reflecting an increase of
$49.1 million or 10.6 percent over the prior year. The increase was due
primarily to higher fuel expenses, higher maintenance and higher other operation
costs. In 1997, total operating expenses decreased by 0.3 percent from the prior
year due primarily to lower administrative and general expenses.
Fuel costs are the single largest expense for the Company. Fuel
expenses in 1998 increased 10.2 percent due to a 3.1 percent increase in
generation and a higher average cost of fuel. In 1998, expenses related to
purchased power from non-affiliates increased 133.0 percent and expenses related
to purchased power from affiliates decreased 4.6 percent. The increased
generation was due to higher demand for energy across the Southern electric
system. Further, the higher demand for energy resulted in higher purchased power
costs from non-affiliates.
In 1997, fuel costs increased because of a 1.1 percent increase in
generation caused by the higher demand for energy in the retail sector. Expenses
related to purchased power from non-affiliates decreased and expenses related to
purchased power from affiliates increased due to the availability of energy
within the Southern electric system.
Purchased power expense increased $18 million (128.4 percent) to meet higher
territorial energy demands and power marketing activities. Energy purchased for
power marketing activities was resold to non-affiliated third parties and had no
significant effect on net income. 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 amount and sources of generation and the average cost of fuel per
net kilowatt-hour generated were as follows:
1998 1997 1996
----------------------------
Total generation
(millions of kilowatt hours) 10,610 10,289 10,180
Sources of generation
(percent) --
Coal 80 85 85
Gas 20 15 15
Average cost of fuel per net
kilowatt-hour generated
(cents) -- 1.62 1.54 1.57
==============================================================
Other operation expenses increased 7.5 percent in 1998 primarily due to
continuing expenses related to a new customer service system, modification of
certain information systems for year 2000 readiness discussed below, and costs
related to work force reduction programs. In 1997, other operation expense
decreased 3.5 percent due to lower administrative and general expenses.
II-159
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 1998 Annual Report
Maintenance expenses increased 6.6 percent in 1998 due to scheduled
maintenance performed at Plants Daniel and Watson, as well as other projects.
In 1998, depreciation and amortization expenses increased 4.1 percent
primarily due to additional plant investment and increased amortization of
regulatory assets.
Comparisons of taxes other than income taxes for 1998 and 1997 show
increases of 4.4 percent and 1.1 percent, respectively, due to higher municipal
franchise taxes resulting from higher retail revenues.
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 energy sales growth to a
less regulated more competitive environment. Expenses are subject to constant
review and cost control programs. See Note 2 to the financial statements under
"Workforce Reduction Programs" for information regarding the Company's workforce
reduction plan of 1997.
The Company currently operates as a vertically integrated company providing
electricity to customers within its traditional service area located in
southeastern Mississippi. Prices for electricity provided by the Company to
retail customers are set by the MPSC under cost-based regulatory principles.
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
aggressively controlling the construction budget.
Operating revenues will be affected by any changes in rates under the PEP,
the Company's performance based ratemaking plan, and the ECO Plan. PEP has
proven to be a stabilizing force on electric rates, with only moderate changes
in rates taking place. The ECO Plan provides for recovery of costs (including
costs of capital) associated with environmental projects approved by the
Mississippi Public Service Commission (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 the Company's
wholesale rate schedules, power sales contracts and transmission facilities. The
FERC is currently reviewing the rate of return on common equity included in
certain contracts and may require such returns to be lowered, possibly
retroactively.
Further discussion of PEP, the ECO Plan, and proceedings before the FERC is
found in Note 3 to the financial statements herein.
Future earnings in the near term will depend upon growth in energy sales,
which is subject to a number of factors. These factors include weather,
competition, changes in contracts with neighboring utilities, energy
conservation practiced by customers, the elasticity of demand, and the rate of
economic growth in Mississippi Power's service area.
The electric utility industry in the United States is currently undergoing a
period of dramatic change as a result of regulatory and competitive factors.
Among the primary agents of change has been the Energy Policy Act of 1992
(Energy Act). The Energy Act allows Independent Power Producers (IPPs) to access
a utility's transmission network in order to sell electricity to other
utilities. This enhances the incentive for IPPs to build cogeneration plants for
II-160
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 1998 Annual Report
a utility's large industrial and commercial customers and sell energy generation
to other utilities. Also, electricity sales for resale rates are being driven
down by wholesale transmission access and numerous potential new energy
suppliers, including power marketers and brokers. The Company is aggressively
working to maintain and expand its share of wholesale sales in the Southeastern
power markets.
Although the Energy Act does not permit retail transmission access, it was a
major catalyst for the current restructuring and consolidation taking place
within the utility industry. Numerous federal and state initiatives are in
various stages to promote wholesale and retail competition. Among other things,
these initiatives allow customers to choose their electricity provider. As these
initiatives materialize, the structure of the utility industry could radically
change. Restructuring initiatives are being discussed in Mississippi; none have
been enacted to date. Enactment would require numerous issues to be resolved,
including significant ones relating to transmission pricing and recovery of any
stranded investments. 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 that are not specifically
recoverable, and determine if any other assets have been impaired. See Note 1 to
the financial statements under "Regulatory Assets and Liabilities" for
additional information. The inability of Mississippi Power to recover its
investment, including regulatory assets, could have a material adverse effect on
the financial condition of the Company.
The Company is attempting to minimize or reduce its cost exposure.
Continuing to be a low-cost producer could provide significant opportunities to
increase market share and profitability in markets that evolve with changing
regulation. Conversely, 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. The Company is subject
to the provisions of FASB Statement 71, Accounting for the Effects of Certain
Types of Regulation. In the event that a portion of the Company's operation is
no longer subject to these provisions, the Company would be required to write
off related regulatory assets and liabilities that are not specifically
recoverable, and determine if any other assets have been impaired. See Note 1
to the financial statements under "Regulatory Assets and Liabilities" for
additional information.
Exposure to Market Risks
Due to cost-based rate regulation, the Company has limited exposure to market
volatility in interest rates and prices of electricity. To mitigate residual
risks relative to movements in electricity prices, the Company enters into fixed
price contracts for the purchase and sale of electricity through the wholesale
electricity market. Realized gains and losses are recognized in the income
statements as incurred. At December 31, 1998, exposure from these activities was
not material to the Company's financial position, results of operation, or cash
flow. Also, based on the Company's overall interest rate exposure at December
31, 1998, a near-term 100 basis point change in interest rates would not
materially affect the financial statements.
New Accounting Standards
The FASB has issued Statement No.133, Accounting for Derivative Instruments and
Hedging Activities, which must be adopted by the year 2000. This statement
establishes accounting and reporting standards for derivative instruments -
including certain derivative instruments embedded in other contracts - and for
hedging activities. The Company has not yet quantified the impact of adopting
this statement on its financial statements; however, the adoption could increase
volatility in earnings and other comprehensive income.
In March 1998, the American Institute of Certified Public Accountants
(AICPA) issued a new Statement of Position, Accounting for the Costs of Computer
Software Developed or Obtained for Internal Use. This statement requires
capitalization of certain costs of internal-use software. The Company adopted
this statement in January 1999, and it is not expected to have a material impact
on the financial statements.
In April 1998, the AICPA issued a new Statement of Position, Reporting on
the Cost of Start-up Activities. This statement requires that the costs of
start-up activities and organizational costs be expensed as incurred. Any of
these costs previously capitalized by a company must be written off in the year
of adoption. The Company adopted this statement in January 1999, and it is not
expected to have a material impact on the financial statements.
II-161
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 1998 Annual Report
In December 1998, the Emerging Issues Task Force (EITF) of the FASB issued
EITF No. 98-10, Accounting for Contracts Involved in Energy Trading and Risk
Management Activities. The EITF requires that energy trading contracts must be
marked to market through the income statement, reflecting gains and losses
rather than revenues and purchased power expense. Energy trading contracts are
defined as energy contracts entered into with the objective of generating
profits on or from exposure to shifts or changes in market prices. The Company
adopted the required accounting in January 1999, and it is not expected to have
a material impact on the financial statements.
Year 2000
Year 2000 Challenge
In order to save storage space, computer programmers in the 1960s and 1970s
shortened the year portion of date entries to just two digits. Computers
assumed, in effect, that all years began with "19." This practice was widely
adopted and hard wired into computer chips and processors found in some
equipment. This approach, intended to save processing time and storage space was
used until the mid-1990s. Unless corrected before the year 2000, affected
software systems and devices containing a chip or microprocessor with date and
time function could incorrectly process dates or the systems may cease to
function.
The Company depends on complex computer systems for many aspects of its
operations, which include generation, transmission, and distribution of
electricity, as well as other business support activities. The Company's goal is
to have critical devices or software that are required to maintain operations to
be Year 2000 ready by June 1999. Year 2000 ready means that a system or
application is determined suitable for continued use through the Year 2000 and
beyond. Critical systems include, but are not limited to, safe shutdown systems,
turbine generator systems, control center computer systems, customer service
systems, energy management systems, and telephone switches and equipment.
Year 2000 Program and Status
The Company's executive management recognizes the seriousness of the Year 2000
challenge and has dedicated adequate resources to address the issue. The
Millennium Project is a team of employees, IBM consultants, and other
contractors whose progress is reviewed on a monthly basis by a steering
committee of Southern Company executives.
The Company's Year 2000 Program was divided into two phases. Phase I
began in 1996 and consisted of identifying and assessing corporate assets
related to software systems and devices that contain a computer chip or clock.
The first phase was completed in June 1997. Phase 2 consists of testing and
remediating high priority systems and devices. Also, contingency planning is
included in the phase. Completion of Phase 2 is targeted for June 1999. The
Millennium Project will continue to monitor the affected computer systems,
devices and applications into the year 2000.
The Southern Company has completed more than 70 percent of the activities in
its work plan. The percentage of completion and projected completion by function
is as follows:
Work Plan
- - - - - - - --------------------------------------------------------------------------
Remediation Project
Inventory Assessment Testing Completion
- - - - - - - --------------------------------------------------------------------------
Generation 100% 100% 70% 6/99
Energy
Management 100 100 90 6/99
Transmission and
Distribution 100 100 100 1/99
Telecommunications 100 100 50 6/99
Corporate
Applications 100 100 90 3/99
- - - - - - - --------------------------------------------------------------------------
Year 2000 Costs
Current projected costs for Year 2000 readiness are approximately $4.9 million.
These costs include labor necessary to identify, test, and renovate affected
devices and systems. From its inception through December 31, 1998, the year 2000
program costs, recognized as expense, amounted to $3.2 million.
II-162
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 1998 Annual Report
Year 2000 Risks
The Company is implementing a detailed process to minimize the possibility of
service interruptions related to Year 2000. The Company believes, based on
current tests, that the system can provide customers with electricity. These
tests increase confidence, but do not guarantee error-free operations. The
Company is taking what it believes to be prudent steps to prepare for the Year
2000, and it expects any interruption in service that may occur within the
service territory to be isolated and short in duration.
The Company expects the risks associated with Year 2000 to be no more severe
than the scenarios that its electric system is routinely prepared to handle. The
most likely worst case scenario consists of the service loss of one of the
largest generating units and/or the loss of any single bulk transmission element
in its service territory. The Company has followed a proven methodology for
identifying and assessing software and devices containing potential Year 2000
challenges. Remediation and testing of those devices are in progress. Following
risk assessment, the Company is preparing contingency plans as appropriate and
is participating in North American Electric Reliability Council-coordinated
national drills during 1999.
The Company is currently reviewing the Year 2000 readiness of material third
parties that provide goods and services crucial to the Company's operations.
Among such critical third parties are fuel, transportation, telecommunication,
water, chemical, and other suppliers. Contingency plans based on the assessment
of each third party's ability to continue supplying critical goods and services
to the Company is being developed.
There is a potential for some earnings erosion caused by reduced electrical
demand by customers because of their Year 2000 issues.
Year 2000 Contingency Plans
Because of experience with hurricanes and other storms, the Company is skilled
at developing and using contingency plans in unusual circumstances.
As part of Year 2000 business continuity and contingency planning, the Company
is drawing on that experience to make risk assessments and developing additional
plans to deal specifically with situations that could arise relative to Year
2000 challenges. The Company is identifying critical operational location, and
key employees will be on duty at those locations during the Year 2000
transition. In September 1999, drills are scheduled to be conducted to test
contingency plans. Because of the level of detail of the contingency planning
process, management feels that the contingency plans will keep any service
interruptions that may occur within the service territory isolated and short in
duration.
FINANCIAL CONDITION
Overview
The principal change in Mississippi Power's financial condition during 1998 was
gross property additions to utility plant of $68 million. Funding for gross
property additions and other capital requirements has been provided from
operating activities, principally earnings and the non-cash charges to income of
depreciation and amortization. The Statements of Cash Flows provide additional
details.
Financing Activity
The Company continued to improve its financial position by issuing pollution
control bonds and retiring higher-cost issues in 1998. The Company sold $13.5
million of pollution control bonds and increased unsecured debt by $90 million.
Retirements, including maturities during 1998, totaled $75 million of first
mortgage bonds and $13 million of pollution control bonds. See the Statements of
Cash Flows for further details.
Composite financing rates for the years 1996 through 1998 as of year-end
were as follows:
1998 1997 1996
----------------------------
Composite interest rate on
long-term debt 6.14% 6.16% 6.03%
Composite preferred stock
dividend rate 6.33% 6.33% 6.58%
Composite interest rate on
preferred securities 7.75% 7.75% -
============================================================
II-163
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 1998 Annual Report
The decrease in the composite dividend rate on preferred stock in 1997 was
primarily the result of retirements.
Capital Structure
At year-end 1998, the Company's ratio of common equity to total capitalization,
excluding long-term debt due within one year, remained at the same level as in
1997 at 52.1 percent.
Capital Requirements for Construction
The Company's projected construction expenditures for the next three years total
$164 million ($67 million in 1999, $52 million in 2000, and $45 million in
2001). The major emphasis within the construction program will be on the upgrade
of existing facilities.
In February 1999, the Company signed an interim construction agency
agreement with Escatawpa Funding ("Escatawpa"), a limited partnership, that
calls for the Company to design and construct, as agent for Escatawpa, a 1064
megawatt natural gas combined cycle facility. On or before April 30, 1999,
Escatawpa and the Company anticipate entering into an Agreement for Lease (which
will supersede the interim construction agency agreement), and a Lease
Agreement. It is anticipated that the total project will cost approximately $406
million, and upon project completion, the Company will lease the facility from
Escatawpa. If the anticipated lease arrangement is not reached, the Company will
either exercise its purchase option or Escatawpa will sell the facility to a
third party.
Revisions to projected construction expenditures may be necessary because of
factors such as changes in business conditions, revised load projections, the
availability and cost of capital, and changes in environmental regulations, and
alternatives such as leasing.
Other Capital Requirements
In addition to the funds required for the Company's construction program,
approximately $80.1 million will be required by the end of 2001 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 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 -- significantly
affected Mississippi Power and the other operating companies of Southern
Company. Specific reductions in sulfur dioxide and nitrogen oxide emissions from
fossil-fired generating plants are required in two phases. Phase I compliance
began in 1995 and initially affected 28 generating plants in the Southern
electric system. As a result of Southern Company's compliance strategy, an
additional 22 generating units were brought into compliance with Phase I
requirements. Phase II compliance is required in 2000, and all fossil-fired
generating plants will be affected.
Southern Company achieved Phase I sulfur dioxide compliance at the affected
plants by switching to low-sulfur coal, which required some equipment upgrades.
Construction expenditures for Phase I compliance totaled approximately $65
million for Mississippi Power.
For Phase II sulfur dioxide compliance, Southern Company could use emission
allowances, increase fuel switching, and/or install flue gas desulfurization
equipment at selected plants. Current compliance strategy for Phase II could
require total estimated construction expenditures of approximately $70 million,
of which $16 million remains to be spent. Phase II compliance is not expected to
have a material impact on Mississippi Power.
Mississippi Power's ECO Plan is designed to allow recovery of costs of
compliance with the Clean Air Act, as well as other environmental statutes and
regulations. The MPSC reviews environmental projects and the Company's
environmental policy through the ECO Plan. Under the ECO Plan, any increase in
the annual revenue requirement is limited to 2 percent of retail revenues.
Mississippi Power's management believes that the ECO Plan provides for recovery
of the Clean Air Act costs. See Note 3 to the financial statements under
"Environmental Compliance Overview Plan" for additional information.
A significant portion of costs related to the acid rain provision of the
Clean Air Act is expected to be recovered through existing ratemaking
II-164
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 1998 Annual Report
provisions. However, there can be no assurance that all Clean Air Act costs will
be recovered.
In July 1997, the Environmental Protection Agency (EPA) revised the national
ambient air quality standards for ozone and particulate matter. This revision
makes the standards significantly more stringent. In September 1998, the EPA
issued the final regional nitrogen oxide rules to the states for implementation.
The states have one year to adopt and implement the new rules. The final rules
affect 22 states that at present does not include Mississippi. The EPA is
presently evaluating whether or not to bring an additional 15 states under this
regional haze rule. Misssissippi is one of those new 15 states. The EPA rules
are being challenged in the courts by several states and industry groups.
Implementation of the final state rules could require substantial further
reductions in nitrogen oxide emissions from fossil-fired generating facilities
and other industry in these states. Implementation of the standards could result
in significant additional compliance costs and capital expenditures that cannot
be determined until the results of legal challenges are known and the states
have adopted their final rules.
The EPA and state environmental regulatory agencies are reviewing and
evaluating various matters including: emission control strategies for ozone
non-attainment areas; additional controls for hazardous air pollutant emissions;
and hazardous waste disposal requirements. The impact of new standards will
depend on the development and implementation of applicable regulations.
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 has been investigated for potential
remediation. Remediation is scheduled for 1999. See Note 3 to the financial
statements under "Environmental Compliance Overview Plan" for additional
information.
Several major pieces of environmental legislation are being considered for
reauthorization or amendment by Congress. These include: the Clean Air Act; the
Clean Water Act; the Comprehensive Environmental Response, Compensation, and
Liability Act; the Resource Conservation and Recovery Act; and the Endangered
Species Act. Changes to these laws could affect many areas of the Company's
operations. The full impact of any such changes cannot be determined at this
time.
Compliance with possible additional legislation related to global climate
change, electromagnetic fields, and other environmental and health concerns
could significantly affect the Company. The impact of new legislation -- if any
- - - - - - - -- will depend on the subsequent development and implementation of applicable
regulations. In addition, the potential exists for lawsuits alleging damages
caused by electromagnetic fields. The likelihood or outcome of such potential
lawsuits cannot be determined at this time.
Sources of Capital
At December 31, 1998, the Company had $76.3 million of unused committed credit
agreements. The Company had $13 million of short term notes payable
outstanding at year end 1998.
It is anticipated that the funds required for construction and other
purposes, including compliance with environmental regulations, will be derived
from sources similar to those used in the past. These sources were primarily the
issuances of first mortgage bonds and preferred securities, in addition to
pollution control revenue bonds issued for the Company's benefit by public
authorities. The Company issued unsecured debt in 1998. In this regard,
Mississippi Power sought and obtained stockholder approval in 1997 to amend its
corporate charter eliminating restrictions on the amounts of unsecured
indebtedness the Company may incur.
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
II-165
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 1998 Annual Report
permitted to issue in the future will depend upon market conditions and other
factors prevailing at that time.
Cautionary Statement Regarding Forward-Looking
Information
This annual report, including the foregoing Management's Discussion and
Analysis, contains forward-looking and historical information. The Company
cautions that there are various important factors that could cause actual
results to differ materially from those indicated in the forward-looking
information; accordingly, there can be no assurance that such indicated results
will be realized. These factors include legislative and regulatory initiatives
regarding deregulation and restructuring of the electric utility industry; the
extent and timing of the entry of additional competition in the Company's
markets; potential business strategies -- including acquisitions or dispositions
of assets or internal restructuring -- that may be pursued by the Company; state
and federal rate regulation; changes in or application of environmental and
other laws and regulations to which the Company is subject; political, legal and
economic conditions and developments; financial market conditions and the
results of financing efforts; changes in commodity prices and interest rates;
weather and other natural phenomena; and other factors discussed in the reports
(including Form 10-K) filed from time to time by the Company with the SEC.
II-166
STATEMENTS OF INCOME
For the Years Ended December 31, 1998, 1997, and 1996
Mississippi Power Company 1998 Annual Report
===========================================================================================================================
1998 1997 1996
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Revenues (Notes 1, 3, and 7):
Revenues $ 576,846 $ 533,445 $ 522,199
Revenues from affiliates 18,285 10,143 21,830
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Total operating revenues 595,131 543,588 544,029
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation--
Fuel 156,539 142,059 141,532
Purchased power from non-affiliates 33,872 14,536 17,960
Purchased power from affiliates 36,037 37,794 33,245
Other 109,993 102,365 106,061
Maintenance 50,404 47,302 47,091
Depreciation and amortization 47,450 45,574 44,906
Taxes other than income taxes 45,965 44,034 43,545
Federal and state income taxes (Note 8) 34,499 31,968 32,618
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Total operating expenses 514,759 465,632 466,958
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Operating Income 80,372 77,956 77,071
Other Income (Expense):
Interest income 947 857 239
Other, net 2,498 2,368 4,145
Income taxes applicable to other income (165) 588 (932)
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Income Before Interest and Other Charges 83,652 81,769 80,523
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Interest and Other Charges:
Interest on long-term debt 20,567 19,856 19,898
Interest on notes payable 943 96 1,416
Amortization of debt discount, premium, and expense, net 1,446 1,577 1,547
Other interest charges 790 574 40
Distributions on preferred securities of subsidiary trust 2,796 2,369 -
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Interest and other charges, net 26,542 24,472 22,901
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Net Income 57,110 57,297 57,622
Dividends on Preferred Stock 2,005 3,287 4,899
- - - - - - - --------------------------------------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred Stock $ 55,105 $ 54,010 $ 52,723
===========================================================================================================================
The accompanying notes are an integral part of these statements.
II-167
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1998, 1997, and 1996
Mississippi Power Company 1998 Annual Report
================================================================================================================================
1998 1997 1996
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Activities:
Net income $ 57,110 $ 57,297 $ 57,622
Adjustments to reconcile net income to net
cash provided by operating activities--
Depreciation and amortization 51,517 49,661 50,551
Deferred income taxes 11,620 (1,809) 74
Other, net (12,175) 3,206 9,443
Changes in certain current assets and liabilities--
Receivables, net (5,486) (8,583) 5,118
Inventories (5,050) 3,148 4,973
Payables (389) 8,357 2,077
Taxes accrued (2,457) 2,515 532
Other (1,604) 1,465 (240)
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities 93,086 115,257 130,150
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (68,231) (55,375) (61,314)
Other (324) (489) (2,258)
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities (68,555) (55,864) (63,572)
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Financing Activities:
Proceeds--
Capital contribution 85 - 27
Pollution control bonds 13,520 - -
Preferred securities - 35,000 -
Other long-term debt 90,000 - 80,000
Retirements--
Preferred stock (87) (42,518) -
First mortgage bonds (75,000) - (45,447)
Pollution control bonds (13,020) (10) (10)
Other long-term debt - - (55,000)
Increase (decrease) in notes payable, net 13,000 - -
Payment of preferred stock dividends (2,005) (3,287) (4,899)
Payment of common stock dividends (51,700) (49,400) (43,900)
Miscellaneous (2,429) (1,804) (2,932)
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Net cash used for financing activities (27,636) (62,019) (72,161)
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents (3,105) (2,626) (5,583)
Cash and Cash Equivalents at Beginning of Year 4,432 7,058 12,641
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 1,327 $ 4,432 $ 7,058
================================================================================================================================
Supplemental Cash Flow Information:
Cash paid during the period for--
Interest (net of amount capitalized) $ 26,133 $ 22,297 $ 21,467
Income taxes 26,847 33,450 34,072
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
( ) Denotes use of cash.
The accompanying notes are an integral part of these statements.
II-168
BALANCE SHEETS
At December 31, 1998 and 1997
Mississippi Power Company 1998 Annual Report
=============================================================================================================================
ASSETS 1998 1997
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
(in thousands)
Utility Plant:
Plant in service, at original cost (Notes 1 and 6) $ 1,553,112 $ 1,518,402
Less accumulated provision for depreciation 583,957 559,098
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
969,155 959,304
Construction work in progress 51,517 41,083
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Total 1,020,672 1,000,387
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Other Property and Investments 979 650
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Current Assets:
Cash and cash equivalents 1,327 4,432
Receivables--
Customer accounts receivable 29,829 32,220
Regulatory clauses under recovery 8,042 7,619
Other accounts and notes receivable 12,495 8,666
Affiliated companies 10,946 7,398
Accumulated provision for uncollectible accounts (621) (698)
Fossil fuel stock, at average cost 16,418 10,651
Materials and supplies, at average cost 18,735 19,452
Current portion of accumulated deferred income taxes 4,248 8,379
Prepayments 1,651 1,791
Vacation pay deferred 4,717 5,030
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Total 107,787 104,940
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Deferred Charges:
Debt expense and loss, being amortized 13,713 12,234
Deferred charges related to income taxes (Note 8) 22,697 21,906
Long-term notes receivable 2,072 2,837
Workforce Reduction Plan 12,748 18,236
Miscellaneous 8,937 5,639
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Total 60,167 60,852
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Total Assets $ 1,189,605 $ 1,166,829
=============================================================================================================================
The accompanying notes are an integral part of these statements.
II-169
BALANCE SHEETS (continued)
At December 31, 1998 and 1997
Mississippi Power Company 1998 Annual Report
=============================================================================================================================
CAPITALIZATION AND LIABILITIES 1998 1997
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
(in thousands)
Capitalization (See accompanying statements):
Common stock equity $ 391,231 $ 387,824
Preferred stock 31,809 31,896
Company obligated mandatorily redeemable preferred securities of
subsidiary trust holding Company Junior Subordinated Notes (Note 9) 35,000 35,000
Long-term debt 292,744 291,665
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Total 750,784 746,385
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Current Liabilities:
Long-term debt due within one year (Note 10) 50,020 35,020
Notes payable 13,000 -
Accounts payable--
Affiliated companies 8,788 8,548
Regulatory clauses over recovery 4,412 15,476
Other 47,113 34,065
Customer deposits 3,272 3,225
Taxes accrued--
Federal and state income 1,124 1,101
Other 31,379 33,859
Interest accrued 2,955 4,098
Miscellaneous 11,753 12,797
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Total 173,816 148,189
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes (Note 8) 143,852 134,645
Accumulated deferred investment tax credits 25,913 27,121
Deferred credits related to income taxes (Note 8) 37,277 38,203
Postretirement benefits other than pension 25,869 25,145
Accumulated provision for property damage (Note 1) 910 13,991
Workforce Reduction Plan 13,051 15,700
Miscellaneous 18,133 17,450
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Total 265,005 272,255
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Commitments and Contingent Matters (Notes 2, 3, 4, and 5)
Total Capitalization and Liabilities $ 1,189,605 $ 1,166,829
=============================================================================================================================
The accompanying notes are an integral part of these statements.
II-170
STATEMENTS OF CAPITALIZATION
At December 31, 1998 and 1997
Mississippi Power Company 1998 Annual Report
===========================================================================================================================
1998 1997 1998 1997
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
Common Stock Equity:
Common stock, without par value --
Authorized -- 1,130,000 shares
Outstanding -- 1,121,000 shares in
1998 and 1997 $ 37,691 $ 37,691
Paid-in capital 179,474 179,389
Premium on preferred stock 326 327
Retained earnings (Note 11) 173,740 170,417
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Total common stock equity 391,231 387,824 52.1 % 52.0 %
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Cumulative Preferred Stock:
$100 par value --
Authorized -- 1,244,139 shares
Outstanding -- 318,090 shares in 1998 and
318,955 shares in 1997
4.40% to 4.72% 3,421 3,492
6.32% to 7.00% 28,388 28,404
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Total (annual dividend requirement -- $2,013,000) 31,809 31,896 4.2 4.3
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Company Obligated Mandatorily
Redeemable Preferred Securities (Note 9):
$25 liquidation value -- 7.75% 35,000 35,000
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Total (annual dividend requirement -- $2,713,000) 35,000 35,000 4.7 4.7
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Long-Term Debt:
First mortgage bonds --
Maturity Interest Rates
1998 5.38% - 35,000
2000 6.63% - 40,000
2004 6.60% 35,000 35,000
2023 7.45% 35,000 35,000
2025 6.88% 30,000 30,000
Pollution control obligations --
Collateralized:
5.65% to 5.80% due 2007-2023 26,805 39,825
4.00% to 5.25% due 2020-2025 33,900 33,900
Non-collateralized:
Variable rate (5.25% at 1/1/99) due 2028 13,520 -
Other long-term notes payable--
6.05% due 2003 35,000 -
6.75% due 2038 55,000 -
Adjustable rates (5.71% to 5.79%) due 1999-2000 80,000 80,000
Unamortized debt premium (discount), net (1,461) (2,040)
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
requirement--$21,131,000) 342,764 326,685
Less amount due within one year (Note 10) 50,020 35,020
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Long-term debt excluding amount due within one year 292,744 291,665 39.0 39.0
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Total Capitalization $ 750,784 $ 746,385 100.0 % 100.0 %
===========================================================================================================================
The accompanying notes are an integral part of these statements.
II-171
STATEMENTS OF RETAINED EARNINGS
For the Years Ended December 31, 1998, 1997, and 1996
Mississippi Power Company 1998 Annual Report
======================================================================================================================
1998 1997 1996
- - - - - - - ----------------------------------------------------------------------------------------------------------------------
(in thousands)
Balance at Beginning of Period $ 170,417 $ 166,282 $ 157,459
Net income after dividends on preferred stock 55,105 54,010 52,723
Cash dividends on common stock (51,700) (49,400) (43,900)
Preferred stock transactions and other, net (82) (475) -
- - - - - - - ----------------------------------------------------------------------------------------------------------------------
Balance at End of Period (Note 11) $ 173,740 $ 170,417 $ 166,282
======================================================================================================================
STATEMENTS OF PAID-IN CAPITAL
For the Years Ended December 31, 1998, 1997, and 1996
======================================================================================================================
1998 1997 1996
- - - - - - - ----------------------------------------------------------------------------------------------------------------------
(in thousands)
Balance at Beginning of Period $ 179,389 $ 179,389 $ 179,362
Contributions to capital by parent company 85 - 27
- - - - - - - ----------------------------------------------------------------------------------------------------------------------
Balance at End of Period $ 179,474 $ 179,389 $ 179,389
======================================================================================================================
The accompanying notes are an integral part of these statements.
II-172
NOTES TO FINANCIAL STATEMENTS
Mississippi Power Company 1998 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING
POLICIES
General
Mississippi Power Company is a wholly owned subsidiary of Southern Company,
which is the parent company of five operating companies, Southern Company
Services (SCS), Southern Communications Services (Southern LINC), Southern
Energy, Inc. (Southern Energy), Southern Nuclear Operating Company (Southern
Nuclear), and Southern Energy Solutions, and other direct and indirect
subsidiaries. The operating companies (Alabama Power Company, Georgia Power
Company, Gulf Power Company, Mississippi Power Company, and Savannah Electric
and Power Company) provide electric service in four southeastern states.
Contracts among the companies--dealing with jointly owned generating facilities,
interconnecting transmission lines, and the exchange of electric power--are
regulated by the Federal Energy Regulatory Commission (FERC) and/or the
Securities and Exchange Commission. SCS provides, at cost, specialized services
to Southern Company and to the subsidiary companies. Southern LINC provides
digital wireless communications services to the operating companies and also
markets these services to the public within the Southeast. Worldwide, Southern
Energy develops and manages electricity and other energy related projects,
including domestic energy trading and marketing. Southern Nuclear provides
services to Southern Company's nuclear power plants. Southern Energy Solutions
develops new business opportunities related to energy products and services.
Southern Company is registered as a holding company under the Public Utility
Holding Company Act of 1935 (PUHCA). Both Southern Company and its subsidiaries
are subject to the regulatory provisions of the PUHCA. Mississippi Power is also
subject to regulation by the FERC and the Mississippi Public Service Commission
(MPSC). The Company follows generally accepted accounting principles and
complies with the accounting policies and practices prescribed by the respective
commissions. The preparation of financial statements in conformity with
generally accepted accounting principles requires the use of estimates and the
actual results may differ from those estimates.
Certain prior years' data presented in the financial statements have been
reclassified to conform with current year presentation.
Regulatory Assets and Liabilities
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 expected to be credited
to customers through the ratemaking process. Regulatory assets and (liabilities)
reflected in the Balance Sheets as of December 31 relate to:
1998 1997
-------------------------
(in thousands)
Deferred income taxes $ 22,697 $ 21,906
Vacation pay 4,717 5,030
Workforce reduction plan of
1997 12,748 18,236
Premium on reacquired debt 9,304 9,508
Deferred environmental costs 1,500 1,583
Property damage reserve (910) (13,991)
Deferred income tax credits (37,277) (38,203)
Other, net (2,538) (2,982)
- - - - - - - ----------------------------------------------------------------
Total $ 10,241 $ 1,087
================================================================
In the event that a portion of the Company's operations is no longer subject
to the provisions of FASB Statement No. 71, the Company would be required to
write off the net regulatory assets and liabilities related to that portion of
operations that are not specifically recoverable through regulated rates. In
addition, the Company would be required to determine any impairment to other
assets, including plant, and write down the assets, if impaired, to their fair
value.
Revenues
The Company currently operates as a vertically integrated utility providing
electricity to retail customers within its traditional service area located
within the state of Mississippi, and to wholesale customers in the southeast.
II-173
NOTES (continued)
Mississippi Power Company 1998 Annual Report
Revenues, less affiliated transactions, by type of service were as follows:
1998 1997 1996
--------------------------------------
(in thousands)
Retail $442,567 $417,242 $414,126
Wholesale 121,225 105,141 99,596
Other 13,054 11,062 8,477
- - - - - - - -----------------------------------------------------------------
Total $576,846 $533,445 $522,199
- - - - - - - -----------------------------------------------------------------
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 costs, the energy
component of purchased power costs and certain other costs. Retail rates also
include provisions to adjust billings for fluctuations in costs for ad valorem
taxes and certain qualifying environmental 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 comprises 10 percent or more of revenues. For all periods presented,
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 3.3 percent
in 1998, 1997, and 1996. 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 removal of
facilities.
Income Taxes
Mississippi Power uses the liability method of accounting for deferred income
taxes and provides deferred income taxes for all significant income tax
temporary differences. Investment tax credits utilized are deferred and
amortized to income over the average lives of the related property.
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. If applicable, 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
The Company's financial instruments for which the carrying amount did not equal
fair value at December 31 were as follows:
Carrying Fair
Amount Value
---------------------------
(in millions)
Long-term debt
At December 31, 1998 $343 $348
At December 31, 1997 $327 $330
Capital trust preferred
securities:
At December 31, 1998 $35 $36
At December 31, 1997 35 36
- - - - - - - --------------------------------------------------------------
The fair value for long-term debt and preferred securities 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-174
NOTES (continued)
Mississippi Power Company 1998 Annual Report
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 $1.5 million in each of the
years 1998, 1997 and 1996. 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. Effective January 1995, regulatory
treatment by the MPSC allowed a maximum accumulated provision of $18 million.
Hurricane Georges struck Mississippi's service area on September 28, 1998,
causing power outages and widespread flooding in certain counties. Current
estimates place the cost of repairing Mississippi's damaged facilities at
approximately $16.4 million, of which $1.5 million is expected to be recovered
from insurance. Substantially all of the cost ($13.9 million) was charged to the
property damage reserve; income will not be significantly affected by these
restoration costs. As of December 31, 1998, the accumulated provision amounted
to $0.9 million.
2. RETIREMENT BENEFITS
Mississippi Power has a defined benefit, trusteed, pension plan that covers
substantially all regular employees. The Company provides certain medical care
and life insurance benefits for retired employees. Substantially all these
employees may become eligible for such benefits when they retire. The Company
funds trusts to the extent deductible under federal income tax regulations or to
the extent required by the MPSC. In 1998, the Company adopted FASB Statement No.
132 Employers' Disclosure about Pensions and Other Postretirement Benefits The
measurement date is September 30 for each year.
Pension Plan
Changes during the year in the projected benefit obligations and in the fair
value of plan assets were as follows:
Projected
Benefit Obligations
----------------------------
1998 1997
- - - - - - - -----------------------------------------------------------------
(in thousands)
Balance at beginning of year $132,131 $127,834
Service cost 3,848 4,015
Interest cost 9,613 9,407
Benefits paid (7,845) (5,384)
Actuarial (gain) loss and
employee transfers 5,060 (3,571)
Effect of workforce reduction - (170)
- - - - - - - -----------------------------------------------------------------
Balance at end of year $142,807 $132,131
=================================================================
Plan Assets
----------------------------
1998 1997
- - - - - - - -----------------------------------------------------------------
(in thousands)
Balance at beginning of year $207,457 $179,658
Actual return on plan assets 1,252 33,718
Benefits paid (7,845) (5,385)
Employee transfers (2,764) (534)
- - - - - - - -----------------------------------------------------------------
Balance at end of year $198,100 $207,457
=================================================================
The accrued pension costs recognized in the Balance Sheets
were as follows:
1998 1997
- - - - - - - --------------------------------------------------------------------
(in thousands)
Funded status $ 55,293 $ 75,326
Unrecognized transition obligation (4,359) (4,903)
Unrecognized prior service cost 5,405 5,818
Unrecognized net gain (56,590) (78,936)
- - - - - - - --------------------------------------------------------------------
Accrued liability recognized in the
Balance Sheets $ (251) $ 2,695
====================================================================
II-175
NOTES (continued)
Mississippi Power Company 1998 Annual Report
Components of the plans' net periodic cost were as follows:
1998 1997 1996
- - - - - - - ------------------------------------------------------------------
(in thousands)
Service cost $ 3,848 $ 4,015 $ 3,842
Interest cost 9,613 9,407 9,310
Expected return on
Plan assets (13,817) (12,805) (12,562)
Recognized net gain (1,956) (1,729) (1,202)
Net amortization (131) (119) (232)
- - - - - - - -------------------------------------------------------------------
Net pension income $ (2,443) $ (1,231) $ (844)
===================================================================
The weighted average rates assumed in the actuarial calculations for both
the pension plans and postretirement benefits were:
1998 1997
---------------------------------------------------------------
Discount 6.75% 7.50%
Annual salary increase 4.25 5.00
Long-term return on plan assets 8.50 8.50
---------------------------------------------------------------
Postretirement Benefits
Changes during the year in the projected benefit obligations and in the fair
value of plan assets were as follows:
Projected
Benefit Obligations
----------------------------
1998 1997
- - - - - - - -----------------------------------------------------------------
(in thousands)
Balance at beginning of year $43,417 $41,108
Service cost 806 867
Interest cost 3,162 2,922
Benefits paid (2,302) (1,495)
Actuarial loss and
employee transfers 2,177 2,824
Effect of work force reduction - (2,809)
- - - - - - - -----------------------------------------------------------------
Balance at end of year $47,260 $43,417
=================================================================
Plan Assets
----------------------------
1998 1997
- - - - - - - -----------------------------------------------------------------
(in thousands)
Balance at beginning of year $12,189 $10,210
Actual return on plan assets 176 1,661
Employer contributions 2,716 1,813
Benefits paid (2,302) (1,495)
- - - - - - - -----------------------------------------------------------------
Balance at end of year $12,779 $12,189
=================================================================
The accrued postretirement costs recognized in the Balance Sheets were as
follows:
1998 1997
- - - - - - - --------------------------------------------------------------------
(in thousands)
Funded status $(34,481) $(31,228)
Unrecognized transition obligation 4,967 5,313
Unrecognized net loss (gain) 1,010 (1,980)
Fourth quarter contributions 577 728
- - - - - - - --------------------------------------------------------------------
Accrued liability recognized in the
Balance Sheets $(27,927) $(27,167)
======================================================================
Components of the plans' net periodic cost were as follows:
1998 1997 1996
- - - - - - - ------------------------------------------------------------------
(in thousands)
Service cost $ 806 $ 867 $ 958
Interest cost 3,162 2,922 2,830
Expected return on
plan assets (989) (815) (696)
Recognized net (gain) loss - (7) 18
Net amortization 346 362 362
- - - - - - - ------------------------------------------------------------------
Net postretirement cost $3,325 $3,329 $3,472
==================================================================
II-176
NOTES (continued)
Mississippi Power Company 1998 Annual Report
An additional assumption used in measuring the accumulated postretirement
benefit obligation was a weighted average medical care cost trend rate of 8.30
percent for 1998, decreasing gradually to 4.75 percent through the year 2005 and
remaining at that level thereafter. An annual increase or decrease in the
assumed medical care cost trend rate of 1 percent would increase the accumulated
benefit obligation and the service and interest cost components at December 31,
1998 as follows:
1 Percent 1 Percent
Increase Decrease
- - - - - - - -------------------------------------------------- --------------
(in thousands)
Benefit obligation $3,128 $(2,652)
Service and interest costs 281 (236)
- - - - - - - -----------------------------------------------------------------
Workforce Reduction Programs
In 1997, approximately one hundred employees of Mississippi Power accepted
the terms of a workforce reduction plan. The total cost to be incurred in
connection with this voluntary plan is expected to be $18.2 million, including a
$2.5 million pension and postretirement benefits curtailment loss. The MPSC
approved the deferral and amortization of these program costs over a period not
to exceed 60 months beginning no later than July 1998. The unamortized balance
of this program was $12.7 million at December 31, 1998.
3. LITIGATION AND REGULATORY MATTERS
Retail Rate Adjustment Plans
Mississippi Power's retail base rates are set under a Performance Evaluation
Plan (PEP) approved by the MPSC in 1994. PEP was designed with the objective
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
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
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 will remain in effect until the MPSC modifies or
terminates the plan. In September 1996, the MPSC under PEP approved a retail
revenue increase of $4.5 million (1.06 percent of annual retail revenue) which
became effective in October 1996. There were no PEP retail revenue changes for
1998 or 1997.
FERC Reviews Equity Returns
On September 21, 1998, the FERC entered separate orders affirming the
outcome of its administrative law judge's opinions in two proceedings in which
the return on common equity component contained in substantially all of the
operating companies' wholesale formula rate contracts was being challenged as
unnecessarily high. These orders resulted in no change in the wholesale
contracts. The FERC also dismissed a complaint filed by the three customers
under long-term power sales agreements seeking to lower the equity return
component in such agreements. These customers have filed applications for
rehearing regarding each FERC order. In response to a requirement of the
September 1998 FERC orders, Southern Company filed a new equity return component
on the long-term power sales contracts, to be effective January 5, 1999. The
proposed equity return was lowered from 13.75 percent to 12.5 percent. The FERC
placed the new rates into effect subject to refund. Also this filing was
consolidated with the new proceeding discussed below.
On December 28, 1998, the FERC staff filed a motion asking the FERC to
initiate a new proceeding regarding the equity return and other issues involving
the operating companies' formula rate contracts. The motion was submitted
pursuant to review procedures applicable to these contracts, and would be
applicable to billings under such contracts on and after January 1, 1999.
Environmental Compliance Overview Plan
The MPSC approved Mississippi Power's Environmental Compliance Overview Plan
(ECO) in 1992. The plan establishes procedures to facilitate the MPSC's overview
of the Company's environmental strategy and provides for recovery of costs
(including costs of capital) 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. In 1997, the Company's filing with the MPSC under the ECO Plan
resulted in an annual retail rate increase of $0.9 million. The 1998 ECO filing
resulted in a small decrease in customer prices.
11-177
NOTES (continued)
Mississippi Power Company 1998 Annual Report
Mississippi Power conducts studies, when possible, to determine the extent
of any required environmental remediation. Should such 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 being investigated for potential remediation. In recognition of
probable remediation, the Company in 1995 recorded a liability and a deferred
debit (regulatory asset) of $1.8 million, including feasibility study costs. The
Company recognizes such costs as they are incurred and recovers them under the
ECO Plan as provided in the Company's 1995 ECO order. As of December 31, 1998,
the balance in the liability and regulatory asset accounts was $1.5 million. The
remedial investigation has been approved by the Mississippi Department of
Environmental Quality. The site is scheduled to be remediated in 1999. The
Company currently estimates the remediation costs to be approximately $1.5
million before recovery from potentially responsible parties.
Approval for New Capacity
In January of 1998, the Company was granted a Certificate of Public
Convenience and Necessity by the MPSC to build approximately 1,000 megawatts of
combined cycle generation at the Company's Plant Daniel site, to be placed in
service by June 2001. In December 1998, the Company requested approval to
transfer the ownership rights under the certificate to Escatawpa Funding,
Limited Partnership, which will lease the facility to the Company (see Note 4,
Construction Program). The Company also requested approval from the MPSC to
exclude the costs of the new facility from retail rate base and to assign the
Company's existing generating capacity to its retail business, beginning in
2001. In January 1999, the Company and Mississippi Public Utility Staff entered
a stipulation covering the details of cost allocation and ratemaking to effect
this change. In February 1999, the Commission held hearings on this matter and
subsequently granted the Company's request, as modified by the stipulation.
4. CONSTRUCTION PROGRAM
Mississippi Power is engaged in continuous construction programs, the costs of
which are currently estimated to total $67 million in 1999, $52 million in 2000,
and $45 million in 2001.
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. Significant construction
will continue related to transmission and distribution facilities, the upgrading
of generating plants, and the addition of combined cycle generation.
In February 1999, the Company signed an interim construction agency
agreement with Escatawpa Funding ("Escatawpa"), a limited partnership, that
calls for the Company to design and construct, as agent for Escatawpa, a 1064
megawatt natural gas combined cycle facility. On or before April 30, 1999,
Escatawpa and the Company anticipate entering into an Agreement for Lease (which
will supersede the interim construction agency agreement), and a Lease
Agreement. It is anticipated that the total project will cost approximately $406
million. Upon project completion, the Company will lease the facility from
Escatawpa. If the anticipated lease arrangement is not reached, the Company will
either exercise its purchase option or Escatawpa will sell the facility to a
third party.
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 securities and the receipt of capital contributions from Southern
Company.
The amounts of first mortgage bonds and preferred stock that can be issued
in the future will be contingent upon market conditions, adequate earnings
levels, regulatory authorizations and other factors.
At December 31, 1998, Mississippi Power had total committed credit
agreements with banks for $96.3 million. At year-end 1998, the unused portion of
these committed credit agreements was $76.3 million. These credit agreements
expire at various dates in 1999 and in 2000. Some of 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
11-178
NOTES (continued)
Mississippi Power Company 1998 Annual Report
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. At December 31, 1998, the
Company had $13 million of short-term borrowings outstanding.
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 of the Company's fixed
property and franchises.
Lease Agreements
In 1984, Mississippi Power and Gulf States Utilities (now Entergy) entered into
a forty-year transmission facilities agreement whereby Entergy 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 1998 use fees collected under this
agreement, net of related expenses, amounted to $3.4 million each year, and are
included within Other Income in the Statements of Income.
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. The Company has the option to purchase the 745
railcars at the greater of lease termination value or fair market value, or to
renew the leases at the end of the lease term. In 1997, a third lease agreement
for the use of 360 railcars was also entered into for three years, with a
monthly renewal option for up to an additional nine months. All of these leases,
totaling 1,105 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, charged to fuel
inventory, was $2.8 million in 1998, $2.0 million in 1997, and $1.7 million in
1996. The Company's annual lease payments for 1999 through 2003 will average
approximately $2.2 million and after 2003, lease payments total in aggregate
approximately $16 million.
Fuel and Purchased Power 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 at December 31, 1998, were as follows:
Year Fuel
-------- --------------
(in millions)
1999 $111
2000 80
- - - - - - - ----------------------------------------------------------
Total commitments $191
- - - - - - - ----------------------------------------------------------
Additional commitments for fuel will be required in the future to supply the
Company's fuel needs.
In 1996, Mississippi Power entered into agreements to purchase options for
summer peaking power for the years 1997 through 2000. The Company has purchased
options from power marketers for up to 250 megawatts of peaking power in 1997;
300 megawatts in 1998; 250 megawatts in 1999; and 400 megawatts in 2000. In
1997and 1998, Mississippi Power exercised its option to purchase 250 megawatts
and 300 megawatts of peaking capacity respectively. In June 1997, the MPSC
approved Mississippi Power's request that it be allowed to earn a return on the
capacity portion of this agreement. Mississippi Power expects to exercise its
option to purchase 250 megawatts of summer peaking capacity in 1999.
11-179
NOTES (continued)
Mississippi Power Company 1998 Annual Report
6. JOINT OWNERSHIP AGREEMENTS
Mississippi Power and Alabama Power own as tenants in common Units 1 and 2 at
Greene County Electric Generating Plant located in Alabama; and Mississippi
Power and Gulf Power own as tenants in common Daniel Electric Generating Plant
located in Mississippi.
At December 31, 1998, 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
Units 1 and 2 500 40% $ 60,868 $27,767
Daniel 1,000 50% 219,082 99,006
--------------------------------------------------------------------------
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
Mississippi Power and the other operating affiliates of Southern Company have
long-term contractual agreements for the sale of capacity and energy to certain
non-affiliated utilities located outside the system's service area. Because the
energy is generally sold at cost under these agreements, profitability is
primarily affected by revenues from capacity sales. The capacity revenues have
been $10,389 in 1998; $8,000 in 1997; and none in 1996.
8. INCOME TAXES
At December 31, 1998, the tax-related regulatory assets and liabilities were $23
million and $37 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 shown below:
1998 1997 1996
----------------------------------
(in thousands)
Total provision for
income taxes
Federal --
Currently payable $20,500 $27,651 $29,888
Deferred --current year 7,007 8,171 13,816
--reversal of
prior years 2,435 (9,236) (14,913)
-----------------------------------------------------------------
29,942 26,586 28,791
-----------------------------------------------------------------
State --
Currently payable 2,544 5,537 3,588
Deferred --current year 1,568 1,756 4,727
--reversal of
prior years 610 (2,499) (3,556)
-----------------------------------------------------------------
4,722 4,794 4,759
-----------------------------------------------------------------
Total 34,664 31,380 33,550
Less income taxes charged
to other income 165 (588) 932
-----------------------------------------------------------------
Federal and state
income taxes charged
to operations $34,499 $31,968 $32,618
=================================================================
11-180
NOTES (continued)
Mississippi Power Company 1998 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:
1998 1997
----------------------------
(in thousands)
Deferred tax liabilities:
Accelerated depreciation $153,768 $149,941
Basis differences 9,642 10,037
Other 26,038 25,097
---------------------------------------------------------------
Total 189,448 185,075
---------------------------------------------------------------
Deferred tax assets:
Other property
basis differences 22,391 23,139
Pension and
other benefits 9,441 9,803
Property insurance 1,526 5,351
Unbilled fuel 2,080 802
Other 14,406 19,714
---------------------------------------------------------------
Total 49,844 58,809
---------------------------------------------------------------
Net deferred tax
liabilities 139,604 126,266
Portion included in
current assets, net 4,248 8,379
---------------------------------------------------------------
Accumulated deferred
income taxes in the
Balance Sheets $143,852 $134,645
===============================================================
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 $1.2 million in 1998, $1.2 million in 1997, and $1.4 million in
1996. At December 31, 1998, 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:
1998 1997 1996
----------------------------------
Federal statutory rate 35.00% 35.00% 35.00%
State income tax, net of
federal deduction 3.34 3.51 3.39
Non-deductible book
depreciation .47 .47 .46
Other (1.04) (3.60) (2.05)
------------------------------------------------------------------
Effective income tax rate 37.77% 35.38% 36.80%
==================================================================
Southern Company files a consolidated federal income tax return. Under a
joint consolidated income tax agreement, each subsidiary's current and deferred
tax expense is computed on a stand-alone basis. Tax benefits from losses of the
parent company are allocated to each subsidiary based on the ratio of taxable
income to total consolidated taxable income.
9. COMPANY OBLIGATED MANDATORILY
REDEEMABLE PREFERRED SECURITIES
In February 1997, Mississippi Power Capital Trust I (Trust I), of which the
Company owns all the common securities, issued $35 million of 7.75 percent
mandatorily redeemable preferred securities. Substantially all of the assets of
Trust I are $36 million aggregate principal amount of the Company's 7.75 percent
junior subordinated notes due February 15, 2037.
The Company considers that the mechanisms and obligations relating to the
preferred securities, taken together, constitute a full and unconditional
guarantee by Mississippi Power Capital Trust for the obligation with respect to
the preferred securities.
The Trust is a subsidiary of the Company, and accordingly is consolidated in
the Company's financial statements.
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:
1998 1997
-------------------
(in thousands)
Bond improvement fund requirement $ 1,000 $1,750
Less: Portion to be satisfied by
certifying property additions 1,000 1,750
---------------------------------------------------------------
Cash sinking fund requirement - -
Redemptions of first mortgage bonds - 35,000
Current portion of other long-term debt 50,000
Pollution control bond cash
sinking fund requirements 20 20
---------------------------------------------------------------
Total $50,020 $35,020
===============================================================
II-181
NOTES (continued()
Mississippi Power Company 1998 Annual Report
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, 1998,
approximately $118 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 1998 and 1997 are as follows:
Net Income
After Dividends
Operating Operating On Preferred
Quarter Ended Revenues Income Stock
- - - - - - - --------------------------------------------------------------------
(in thousands)
March 1998 $122,156 $15,367 $8,388
June 1998 156,612 20,123 13,713
September 1998 191,699 34,167 28,309
December 1998 124,664 10,715 4,696
March 1997 $116,903 $17,132 $10,645
June 1997 128,915 19,340 12,618
September 1997 171,874 30,441 25,163
December 1997 125,896 11,043 5,584
- - - - - - - --------------------------------------------------------------------
Mississippi Power's business is influenced by seasonal weather conditions
and the timing of rate changes.
II-182
SELECTED FINANCIAL AND OPERATING DATA
Mississippi Power Company 1998 Annual Report
===========================================================================================================================
1998 1997 1996
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands) $595,131 $543,588 $544,029
Net Income after Dividends
on Preferred Stock (in thousands) $55,105 $54,010 $52,723
Cash Dividends on Common Stock (in thousands) $51,700 $49,400 $43,900
Return on Average Common Equity (percent) 14.2 14.0 13.9
Total Assets (in thousands) $1,189,605 $1,166,829 $1,142,327
Gross Property Additions (in thousands) $68,231 $55,375 $61,314
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $391,231 $387,824 $383,734
Preferred stock 31,809 31,896 74,414
Preferred stock subject to mandatory redemption - - -
Company obligated mandatorily redeemable preferred securities 35,000 35,000 -
Long-term debt 292,744 291,665 326,379
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $750,784 $746,385 $784,527
===========================================================================================================================
Capitalization Ratios (percent):
Common stock equity 52.1 52.0 48.9
Preferred stock 4.2 4.3 9.5
Company obligated mandatorily redeemable preferred securities 4.7 4.7 -
Long-term debt 39.0 39.0 41.6
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0 100.0
===========================================================================================================================
First Mortgage Bonds (in thousands):
Issued - - -
Retired 75,000 - 45,447
Preferred Stock (in thousands):
Issued - - -
Retired 87 42,518 -
Company Obligated Mandatorily Redeemable
Preferred Securities (in thousands):
Issued - 35,000 -
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Security Ratings:
First Mortgage Bonds -
Moody's Aa3 Aa3 Aa3
Standard and Poor's AA- AA- A+
Duff & Phelps AA- AA- AA-
Preferred Stock -
Moody's a1 a1 a1
Standard and Poor's A A A
Duff & Phelps A+ A+ A+
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Customers (year-end):
Residential 156,530 156,650 154,630
Commercial 31,319 31,667 30,366
Industrial 587 642 639
Other 200 200 200
- - - - - - - ----------------------------------------------------------------------------------------------------------------------------
Total 188,636 189,159 185,835
===========================================================================================================================
Employees (year-end) 1,230 1,245 1,363
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
II-183
SELECTED FINANCIAL AND OPERATING DATA
Mississippi Power Company 1998 Annual Report
==============================================================================================================================
1995 1994 1993 1992
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands) $516,553 $499,162 $474,883 $434,447
Net Income after Dividends
on Preferred Stock (in thousands) $52,531 $49,157 $42,436 $36,790
Cash Dividends on Common Stock (in thousands) $39,400 $34,100 $29,000 $28,000
Return on Average Common Equity (percent) 14.26 14.38 14.09 13.27
Total Assets (in thousands) $1,148,953 $1,123,711 $1,050,334 $791,283
Gross Property Additions (in thousands) $67,570 $104,014 $139,976 $68,189
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $374,884 $361,753 $321,768 $280,640
Preferred stock 74,414 74,414 74,414 74,414
Preferred stock subject to mandatory redemption - - - -
Company obligated mandatorily redeemable preferred securities - - - -
Long-term debt 288,820 306,522 250,391 238,650
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $738,118 $742,689 $646,573 $593,704
==============================================================================================================================
Capitalization Ratios (percent):
Common stock equity 50.8 48.7 49.8 47.3
Preferred stock 10.1 10.0 11.5 12.5
Company obligated mandatorily redeemable preferred securities - - - -
Long-term debt 39.1 41.3 38.7 40.2
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0 100.0 100.0
==============================================================================================================================
First Mortgage Bonds (in thousands):
Issued 30,000 35,000 70,000 40,000
Retired 1,625 32,628 51,300 104,703
Preferred Stock (in thousands):
Issued - - 23,404 35,000
Retired - - 23,404 -
Company Obligated Mandatorily Redeemable
Preferred Securities (in thousands):
Issued - - - -
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------
Security Ratings:
First Mortgage Bonds -
Moody's Aa3 Aa3 A1 A1
Standard and Poor's A+ A+ A+ A+
Duff & Phelps AA- A+ A+ A+
Preferred Stock -
Moody's a1 a1 a1 a1
Standard and Poor's A A A A
Duff & Phelps A+ A A A
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------
Customers (year-end):
Residential 154,014 152,891 151,692 150,248
Commercial 29,903 29,276 28,648 28,056
Industrial 642 650 570 573
Other 194 189 190 189
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------
Total 184,753 183,006 181,100 179,066
==============================================================================================================================
Employees (year-end) 1,421 1,535 1,586 1,619
- - - - - - - ------------------------------------------------------------------------------------------------------------------------------
11-184A
SELECTED FINANCIAL AND OPERATING DATA
Mississippi Power Company 1998 Annual Report
============================================================================================================================-
1991 1990 1989 1988
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands) $432,386 $446,871 $442,650 $437,939
Net Income after Dividends
on Preferred Stock (in thousands) $22,627 $34,176 $38,576 $36,081
Cash Dividends on Common Stock (in thousands) $28,500 $27,500 $27,000 $27,600
Return on Average Common Equity (percent) 8.17 12.36 14.43 14.03
Total Assets (in thousands) $790,641 $800,026 $786,570 $779,319
Gross Property Additions (in thousands) $53,675 $49,009 $43,916 $54,550
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock 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
Company obligated mandatorily redeemable preferred securities - - - -
Long-term debt 304,150 270,724 277,693 287,525
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $617,419 $593,721 $594,764 $593,662
=============================================================================================================================
Capitalization Ratios (percent):
Common stock equity 44.4 47.1 45.9 44.1
Preferred stock 6.4 7.3 7.4 7.5
Company obligated mandatorily redeemable preferred securities - - - -
Long-term debt 49.2 45.6 46.7 48.4
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0 100.0 100.0
=============================================================================================================================
First Mortgage Bonds (in thousands):
Issued 50,000 - - -
Retired - 4,000 3,823 -
Preferred Stock (in thousands):
Issued - - - -
Retired 4,118 750 750 1,500
Company Obligated Mandatorily Redeemable
Preferred Securities (in thousands):
Issued - - - -
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Security Ratings:
First Mortgage Bonds -
Moody's A1 A1 A1 A1
Standard and Poor's A+ A+ A+ A+
Duff & Phelps A+ A+ A+ 5
Preferred Stock -
Moody's a1 a1 a1 a1
Standard and Poor's A A A A
Duff & Phelps A A A 6
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Customers (year-end):
Residential 148,978 147,738 147,308 146,750
Commercial 27,441 27,134 26,867 26,751
Industrial 562 574 525 478
Other 400 411 404 399
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Total 177,381 175,857 175,104 174,378
=============================================================================================================================
Employees (year-end) 1,630 1,842 1,750 1,831
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
11-184B
SELECTED FINANCIAL AND OPERATING DATA (continued)
Mississippi Power Company 1998 Annual Report
- - - - - - - -------------------------------------------------------------------------------------------------------------------------
1998 1997 1996
- - - - - - - -------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $157,642 $138,608 $137,055
Commercial 145,677 134,208 131,734
Industrial 135,039 140,233 141,324
Other 4,209 4,193 4,013
- - - - - - - -------------------------------------------------------------------------------------------------------------------------
Total retail 442,567 417,242 414,126
Sales for resale - non-affiliates 121,225 105,141 99,596
Sales for resale - affiliates 18,285 10,143 21,830
- - - - - - - -------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 582,077 532,526 535,552
Other revenues 13,054 11,062 8,477
- - - - - - - --------------------------------------------------------------------------------------------------------- --------------
Total $595,131 $543,588 $544,029
=========================================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 2,248,915 2,039,042 2,079,611
Commercial 2,623,276 2,407,520 2,315,860
Industrial 3,729,166 3,981,875 3,960,243
Other 39,772 40,508 39,297
- - - - - - - -------------------------------------------------------------------------------------------------------------------------
Total retail 8,641,129 8,468,945 8,395,011
Sales for resale - non-affiliates 3,157,837 2,895,182 2,726,993
Sales for resale - affiliates 552,142 478,884 693,510
- - - - - - - -------------------------------------------------------------------------------------------------------------------------
Total 12,351,108 11,843,011 11,815,514
=========================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 7.01 6.80 6.59
Commercial 5.55 5.57 5.69
Industrial 3.62 3.52 3.57
Total retail 5.12 4.93 4.93
Total sales 4.71 4.50 4.53
Residential Average Annual Kilowatt-Hour Use Per Customer 14,375 13,132 13,469
Residential Average Annual Revenue Per Customer $1,007.68 $892.68 $887.66
Plant Nameplate Capacity Ratings (year-end) (megawatts) 2,086 2,086 2,086
Maximum Peak-Hour Demand (megawatts):
Winter 1,740 1,922 2,030
Summer 2,339 2,209 2,117
Annual Load Factor (percent) 58.0 59.1 60.7
Plant Availability - Fossil-Steam (percent) 90.0 92.4 91.8
- - - - - - - -------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 66.0 70.0 70.4
Oil and gas 15.0 13.0 12.0
Purchased power -
From non-affiliates 8.0 3.0 6.5
From affiliates 11.0 14.0 11.1
- - - - - - - -------------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0
=========================================================================================================================
Total Fuel Economy Data:
BTU per net kilowatt-hour generated 10,261 10,078 10,038
Cost of fuel per million BTU (cents) 157.93 153.32 156.08
Average cost of fuel per net kilowatt-hour generated (cents) 1.62 1.54 1.57
- - - - - - - -------------------------------------------------------------------------------------------------------------------------
11-185
SELECTED FINANCIAL AND OPERATING DATA (continued)
Mississippi Power Company 1998 Annual Report
===========================================================================================================================
1995 1994 1993 1992
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $134,286 $124,257 $118,793 $109,781
Commercial 131,034 124,716 115,152 107,131
Industrial 140,947 142,268 130,198 117,010
Other 3,914 3,882 3,760 3,533
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Total retail 410,181 395,123 367,903 337,455
Sales for resale - non-affiliates 91,820 88,122 83,511 80,213
Sales for resale - affiliates 7,691 9,538 15,519 10,055
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 509,692 492,783 466,933 427,723
Other revenues 6,861 6,379 7,950 6,724
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Total $516,553 $499,162 $474,883 $434,447
===========================================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 2,040,608 1,922,217 1,929,835 1,804,858
Commercial 2,242,163 2,100,625 1,933,685 1,811,042
Industrial 3,813,456 3,847,011 3,623,543 3,536,634
Other 38,559 38,147 38,357 38,261
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Total retail 8,134,786 7,908,000 7,525,420 7,190,795
Sales for resale - non-affiliates 2,493,519 2,555,914 2,544,982 2,687,917
Sales for resale - affiliates 243,554 174,342 426,919 280,443
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Total 0,871,859 10,638,256 10,497,321 10,159,155
===========================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 6.58 6.46 6.16 6.08
Commercial 5.84 5.94 5.96 5.92
Industrial 3.70 3.70 3.59 3.31
Total retail 5.04 5.00 4.89 4.69
Total sales 4.69 4.63 4.45 4.21
Residential Average Annual Kilowatt-Hour Use Per Customer 13,307 12,611 12,780 12,066
Residential Average Annual Revenue Per Customer $875.69 $815.21 $786.71 $733.90
Plant Nameplate Capacity Ratings (year-end) (megawatts) 2,086 2,086 2,011 2,011
Maximum Peak-Hour Demand (megawatts):
Winter 1,637 1,636 1,401 1,386
Summer 2,095 1,874 1,872 1,755
Annual Load Factor (percent) 60.0 63.4 60.0 60.8
Plant Availability - Fossil-Steam (percent) 92.1 85.4 88.0 92.0
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 58.0 56.0 63.5 60.4
Oil and gas 15.2 10.2 7.6 5.8
Purchased power -
From non-affiliates 2.4 1.2 1.3 1.2
From affiliates 24.4 32.6 27.6 32.6
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0 100.0
===========================================================================================================================
Total Fuel Economy Data:
BTU per net kilowatt-hour generated 10,249 10,295 10,075 9,888
Cost of fuel per million BTU (cents) 160.48 165.96 170.13 162.27
Average cost of fuel per net kilowatt-hour generated (cents) 1.64 1.71 1.71 1.60
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
II-186A
SELECTED FINANCIAL AND OPERATING DATA (continued)
Mississippi Power Company 1998 Annual Report
===========================================================================================================================
1991 1990 1989 1988
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $103,820 $102,243 $100,068 $96,711
Commercial 103,666 103,352 103,403 98,772
Industrial 116,972 123,754 128,983 123,038
Other 5,869 6,078 5,992 5,874
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Total retail 330,327 335,427 338,446 324,395
Sales for resale - non-affiliates 78,826 86,194 82,111 75,525
Sales for resale - affiliates 18,044 20,157 16,938 33,747
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 427,197 441,778 437,495 433,667
Other revenues 5,189 5,093 5,155 4,272
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Total $432,386 $446,871 $442,650 $437,939
===========================================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 1,832,266 1,804,838 1,741,855 1,686,722
Commercial 1,768,441 1,718,074 1,686,302 1,607,988
Industrial 3,297,247 3,311,460 3,204,208 2,879,457
Other 89,375 85,938 87,611 86,049
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Total retail 6,987,329 6,920,310 6,719,976 6,260,216
Sales for resale - non-affiliates 2,706,320 2,883,581 2,798,086 2,280,341
Sales for resale - affiliates 617,696 714,365 527,970 1,100,808
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Total 0,311,345 10,518,256 10,046,032 9,641,365
===========================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 5.67 5.66 5.74 5.73
Commercial 5.86 6.02 6.13 6.14
Industrial 3.55 3.74 4.03 4.27
Total retail 4.73 4.85 5.04 5.18
Total sales 4.14 4.20 4.35 4.50
Residential Average Annual Kilowatt-Hour Use Per Customer 12,338 12,228 11,842 11,499
Residential Average Annual Revenue Per Customer $699.11 $692.70 $680.32 $659.30
Plant Nameplate Capacity Ratings (year-end) (megawatts) 2,011 1,998 1,998 1,966
Maximum Peak-Hour Demand (megawatts):
Winter 1,267 1,201 1,556 1,284
Summer 1,682 1,724 1,682 1,621
Annual Load Factor (percent) 61.5 59.0 58.8 57.6
Plant Availability - Fossil-Steam (percent) 89.8 93.3 94.0 93.0
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 64.1 62.6 63.4 86.3
Oil and gas 8.1 14.0 13.5 4.8
Purchased power -
From non-affiliates 0.7 0.8 0.5 0.4
From affiliates 27.1 22.6 22.6 8.5
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0 100.0
===========================================================================================================================
Total Fuel Economy Data:
BTU per net kilowatt-hour generated 10,142 10,319 10,159 10,220
Cost of fuel per million BTU (cents) 177.52 183.27 178.38 185.13
Average cost of fuel per net kilowatt-hour generated (cents) 1.80 1.89 1.81 1.89
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------
II-186B
<
SAVANNAH ELECTRIC AND POWER COMPANY
FINANCIAL SECTION
II-187
MANAGEMENT'S REPORT
Savannah Electric and Power Company 1998 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/ G. Edison Holland, Jr.
G. Edison Holland, Jr.
President
and Chief Executive Officer
/s/ K. R. Willis
K. R. Willis
Vice-President
Treasurer, Chief Financial Officer
and Assistant Secretary
February 10, 1999
II-188
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To 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 Southern Company) as of December 31, 1998 and 1997, and the
related statements of income, retained earnings, and cash flows for each of the
three years in the period ended December 31, 1998. 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 11-198 through II-210)
referred to above present fairly, in all material respects, the financial
position of Savannah Electric and Power Company as of December 31, 1998 and
1997, and the results of its operations and its cash flows for each of the
three years in the period ended December 31, 1998, in conformity with generally
accepted accounting principles.
/s/ Arthur Andersen LLP
Arthur Andersen LLP
Atlanta, Georgia
February 10, 1999
II-189
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Savannah Electric and Power Company 1998 Annual Report
RESULTS OF OPERATIONS
Earnings
Savannah Electric and Power Company's net income after dividends on preferred
stock for 1998 totaled $23.6 million, representing a $0.2 million decrease from
the prior year. This 0.9 percent decline in earnings from 1997 is principally
the result of a decrease in other income, net.
In 1997, earnings were $23.8 million, representing a $0.1 million, or 0.4
percent decrease from the prior year. This was principally the result of an
increase in other operation expense, partially offset by an increase in other
income, net.
Revenues
Total revenues for 1998 were $254.5 million, reflecting a 12.5 percent increase
compared to 1997. The following table summarizes the factors affecting operating
revenues for the 1996-1998 period:
Increase (Decrease)
From Prior Year
--------------------------------------
1998 1997 1996
--------------------------------------
Retail -- (in thousands)
Sales growth $ (479) $ 7,664 $ 3,679
Weather 8,336 (6,186) (2,813)
Fuel cost recovery
and other 15,012 (10,002) 12,365
--------------------------------------------------------------------
Total retail 22,869 (8,524) 13,231
--------------------------------------------------------------------
Sales for resale--
Non-affiliates 1,081 1,469 147
Affiliates 964 (1,078) (4,070)
--------------------------------------------------------------------
Total sales for resale 2,045 391 (3,923)
--------------------------------------------------------------------
Other operating revenues 3,264 336 (963)
--------------------------------------------------------------------
Total operating revenues $28,178 $ (7,797) $ 8,345
====================================================================
Percent change 12.5% (3.3)% 3.7%
--------------------------------------------------------------------
Retail revenues increased 10.4 percent in 1998, compared to a decline of
3.7 percent in 1997. The increase in 1998 retail revenues is primarily
attributable to the unusually hot summer weather, which led to the increases in
the residential and commercial classes. The base rate decrease to the small
business customer class, ordered by the Georgia Public Service Commission (GPSC)
effective July 1998, more than offset the sales growth in all classes. See Note
3 to the financial statements for additional information. The number of
customers was also up in both the residential and commercial categories.
The decline in 1997 retail revenues was attributable to the mild summer
weather and a decrease in fuel cost recovery revenues, somewhat offset by
customer growth and increased industrial energy sales. Industrial energy sales
were higher primarily due to an increase in the demand of a major customer.
Under the Company's fuel cost recovery provisions, fuel revenues--including
the fuel component of purchased energy--generally equal fuel expense and have no
effect on earnings.
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 revenues remained unchanged
in 1998. The capacity and energy components were as follows:
1998 1997 1996
--------------------------------------
(in thousands)
Capacity $ 2 $ 2 $ 2
Energy 401 746 1,329
- - - - - - - -----------------------------------------------------------
Total $403 $748 $1,331
===========================================================
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 do not have a significant impact on
earnings.
Energy Sales
Changes in revenues are influenced heavily by the amount of energy sold each
year. Kilowatt-hour (KWH) sales for 1998 and the percent change by year were as
follows:
KWH Percent Change
------------ -----------------------------
1998 1998 1997 1996
------------ -----------------------------
(in millions)
Residential 1,540 7.8% (1.9)% 3.9%
Commercial 1,236 6.9 1.3 3.8
Industrial 900 2.1 5.1 (5.5)
Other 131 5.3 (1.4) 0.1
------------
Total retail 3,807 6.0 0.8 1.4
Sales for resale--
Non-affiliates 53 (43.5) 2.9 4.4
Affiliates 59 7.2 30.4 (34.4)
------------
Total 3,919 4.8% 1.2% 0.8%
=====================================================================
II-190
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 1998 Annual Report
Total retail energy sales were up 6.0% in 1998, the strongest showing since
1995. Both residential and commercial energy sales reflected the impact of the
hotter-than-normal weather. Industrial energy sales reflected high demand from
one industrial customer.
Expenses
Total operating expenses for 1998 were $216.6 million, reflecting a $27.6
million increase from 1997. Major components of this increase include a $17.5
million increase in fuel, a $7.1 million increase in purchased power from
non-affiliates, and a $5.5 million increase in maintenance expense. These
increases were partially offset by a decrease of $6.4 million in purchased power
from affiliates. The increase in fuel expense was primarily attributable to
higher demand for energy. The increase in purchased power from non-affiliates
primarily resulted from increased power marketing activities. Maintenance
expenses were higher primarily due to scheduled turbine dismantle inspection
costs. The decline in purchased power from affiliates was due primarily to an
increase in internal generation reflecting system load growth.
In 1997, total operating expenses were $189.1 million, reflecting a $6.1
million decrease from 1996. This decrease includes a $16.5 million reduction in
purchased power from affiliates, partially offset by increases of $6.4 million
in fuel and $3.7 million in other operation expenses. The decrease in purchased
power from affiliates was due to an increase in internal generation and to an
adjustment in affiliated billings. The increase in fuel expense was primarily
attributable to higher generation and to fuel mix. The increase in other
operation expense primarily resulted from a one-time charge for work force
reductions of $1.9 million, and expenses associated with the implementation of a
new computer software system.
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 and the total average cost of
energy supply were as follows:
1998 1997 1996
--------------------------
Total energy supply
(millions of KWHs) 4,182 3,964 3,917
Sources of energy supply
(percent) --
Coal 42 34 28
Oil 1 - -
Gas 12 5 3
Purchased Power 45 61 69
Total average cost of
energy supply (cents) 2.35 2.02 2.30
- - - - - - - -----------------------------------------------------------------
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 utility plant with long economic life. 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 securities. Any
recognition of inflation by regulatory authorities is reflected in the rate of
return allowed.
11-191
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 1998 Annual Report
Future Earnings Potential
The results of operations for the past three years are not necessarily
indicative of future earnings potential. The level of future earnings depends on
numerous factors ranging from energy sales growth to a less regulated, more
competitive environment.
Savannah Electric currently operates as a vertically integrated utility
providing electricity to customers within the traditional service area of
southeastern Georgia. Prices for electricity provided by the Company to retail
customers are set by the GPSC. Prices for electricity relating to jointly owned
generating facilities, interconnecting transmission lines, and the exchange of
electric power are set by the Federal Energy Regulatory Commission (FERC).
Future earnings in the near term will depend upon growth in energy sales,
which is subject to a number of factors. These factors include weather,
competition, changes in contracts with neighboring utilities, energy
conservation practiced by customers, the elasticity of demand, and the rate of
economic growth in the Company's service area.
The electric utility industry in the United States is currently undergoing
a period of dramatic change as a result of regulatory and competitive factors.
Among the primary agents of change has been the Energy Policy Act of 1992
(Energy Act). The Company is positioning the business to meet the challenge of
this major change in the traditional practice of selling electricity. The Energy
Act allows independent power producers (IPPs) to access the Company's
transmission network in order to sell electricity to other utilities. This
enhances the incentive for IPPs to build cogeneration plants for industrial and
commercial customers and sell energy generation to other utilities. Also,
electricity sales for resale rates are being driven down by wholesale
transmission access and numerous potential new energy suppliers, including power
marketers and brokers.
Although the Energy Act does not permit retail customer access, it was a
major catalyst for the current restructuring and consolidation taking place
within the utility industry. Numerous federal and state initiatives are in
varying stages to promote wholesale and retail competition. Among other things,
these initiatives allow customers to choose their electricity provider. As these
initiatives materialize, the structure of the utility industry could radically
change. Some states have approved initiatives that result in a separation of the
ownership and/or operation of generating facilities from the ownership and/or
operation of transmission and distribution facilities. While various
restructuring and competition initiatives have been or are being discussed in
Georgia, none have been enacted to date. Enactment would require numerous issues
to be resolved, including significant ones relating to transmission pricing and
recovery of any stranded investments. The inability of the Company to recover
its investments, including the regulatory assets described in Note 1 to the
financial statements, could have a material adverse effect on the financial
condition of the Company. The Company is attempting to minimize or reduce its
cost exposure.
Continuing to be a low-cost producer could provide significant
opportunities to increase market share and profitability in markets that evolve
with changing regulation. Conversely, 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.
Compliance costs related to current and future environmental laws and
regulations 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."
Rates to retail customers served by the Company are regulated by the GPSC.
As part of the Company's rate settlement in 1992, it was informally agreed that
the Company's earned rate of return on common equity should be 12.95 percent. In
June 1998, the GPSC issued a four-year accounting order which settled its review
of the Company's earnings. See Note 3 to the financial statements 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 that are not specifically recoverable, and
determine if any other assets have been impaired. See Note 1 to the financial
statements under "Regulatory Assets and Liabilities" for additional information.
11-192
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 1998 Annual Report
Exposure to Market Risks
Due to cost-based rate regulation, the Company has limited exposure to market
volatility in interest rates and prices of electricity. To mitigate residual
risks relative to movements in electricity prices, the Company enters into fixed
price contracts for the purchase and sale of electricity through the wholesale
electricity market. Realized gains and losses are recognized in the income
statement as incurred. At December 31, 1998, exposure from these activities was
not material to the Company's financial statements. Also, based on the Company's
overall interest rate exposure at December 31, 1998, a near-term 100 basis point
change in interest rates would not materially affect the financial statements.
New Accounting Standards
The FASB has issued Statement No. 133, Accounting for Derivative Instruments and
Hedging Activities, which must be adopted by the year 2000. This statement
establishes accounting and reporting standards for derivative instruments --
including certain derivative instruments embedded in other contracts -- and for
hedging activities. The Company has not yet quantified the impact of adopting
this statement on its financial statements; however, the adoption could increase
volatility in earnings.
In March 1998, the American Institute of Certified Public Accountants
(AICPA) issued a new Statement of Position, Accounting for the Costs of Computer
Software Developed or Obtained for Internal Use. This statement requires
capitalization of certain costs of internal-use software. The Company adopted
this statement in January 1999, and it is not expected to have a material impact
on the financial statements.
In April 1998, the AICPA issued a new Statement of Position, Reporting on
the Cost of Start-up Activities. This statement requires that the costs of
start-up activities and organizational costs be expensed as incurred. Any of
these costs previously capitalized by a company must be written off in the year
of adoption. The Company adopted this statement in January 1999, and it is not
expected to have a material impact on the financial statements.
In December 1998, the Emerging Issues Task Force (EITF) of the FASB issued
EITF No. 98-10, Accounting for Contracts Involved in Energy Trading and Risk
Management Activities. The EITF requires that energy trading contracts must be
marked to market through the income statement, with gains and losses reflected
rather than revenues and purchased power. Energy trading contracts are defined
as energy contracts entered into with the objective of generating profits on or
from exposure to shifts or changes in market prices. The Company adopted the
required accounting in January 1999, and it is not expected to have a material
impact on the financial statements.
Year 2000
Year 2000 Challenge
In order to save storage space, computer programmers in the 1960s and 1970s
shortened the year portion of date entries to just two digits. Computers
assumed, in effect, that all years began with "19." This practice was widely
adopted and hard-coded into computer chips and processors found in some
equipment. This approach, intended to save processing time and storage space,
was used until the mid-1990s. Unless corrected before the Year 2000, affected
software systems and devices containing a chip or microprocessor with date and
time functions could incorrectly process dates or the systems may cease to
function.
The Company depends on complex computer systems for many aspects of its
operations, which include generation, transmission, and distribution of
electricity, as well as other business support activities. The Company's goal is
to have critical devices or software that are required to maintain operations to
be Year 2000 ready by June 1999. Year 2000 ready means that a system or
application is determined suitable for continued use through the Year 2000 and
beyond. Critical systems include, but are not limited to, safe shutdown systems,
turbine generator systems, control center computer systems, customer service
systems, energy management systems, and telephone switches and equipment.
Year 2000 Program and Status
The Company's executive management recognizes the seriousness of the Year 2000
challenge and has dedicated what it believes to be adequate resources to address
the issue. The Millennium Project is a team of employees, IBM consultants, and
other contractors whose progress is reviewed on a monthly basis by a steering
committee of Southern Company executives.
11-193
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 1998 Annual Report
The Company's Year 2000 program was divided into two phases. Phase I began
in 1996 and consisted of identifying and assessing corporate assets related to
software systems and devices that contain a computer chip or clock. The first
phase was completed in June 1997. Phase 2 consists of testing and remediating
high priority systems and devices. Also, contingency planning is included in
this phase. Completion of Phase 2 is targeted for June 1999. The Millennium
Project will continue to monitor the affected computer systems, devices, and
applications into the Year 2000.
Southern Company has completed more than 70 percent of the activities
contained in its work plan. The percentage of completion and projected
completion by function are as follows:
- - - - - - - -------------------------------------------------------------------------
Work Plan
------------------------------------------------
Remediation Project
Inventory Assessment Testing Completion
- - - - - - - -------------------------------------------------------------------------
Generation 100% 100% 70% 6/99
- - - - - - - -------------------------------------------------------------------------
Energy Management 100 100 90 6/99
- - - - - - - -------------------------------------------------------------------------
Transmission and
Distribution 100 100 100 1/99
- - - - - - - -------------------------------------------------------------------------
Telecommunications 100 100 50 6/99
- - - - - - - -------------------------------------------------------------------------
Corporate Applications 100 100 90 3/99
- - - - - - - ------------------------------------------------------------------------
Year 2000 Costs
Current projected total costs for Southern Company for Year 2000 readiness are
approximately $91 million, which includes $6 million of cost billed to
non-affiliated companies. These costs include labor necessary to identify, test,
and remediate affected devices and systems. From its inception through December
31, 1998, the Year 2000 program costs for Southern Company, recognized as
expense, amounted to $56 million. The Company's total estimated costs related to
the project are approximately $1.2 million. Year 2000 costs of $0.5 million and
$0.2 million were expensed in 1998 and 1997, respectively. The Company's
estimated cost of completion is $0.5 million.
Year 2000 Risks
The Company is implementing a detailed process to minimize the possibility of
service interruptions related to the Year 2000. The Company believes, based on
current tests, that the system can provide customers with electricity. These
tests increase confidence, but do not guarantee error-free operations. The
Company is taking what it believes to be prudent steps to prepare for the Year
2000, and it expects any interruptions in service that may occur within the
service territory to be isolated and short in duration.
The Company expects the risks associated with Year 2000 to be no more
severe than the scenarios that its electric system is routinely prepared to
handle. The most likely worst case scenario consists of the service loss of one
of the largest generating units and/or the service loss of any single bulk
transmission element in its service territory. The Company has followed a proven
methodology for identifying and assessing software and devices containing
potential Year 2000 challenges. Remediation and testing of those devices are in
progress. Following risk assessment, the Company is preparing contingency plans
as appropriate and is participating in North American Electric Reliability
Council-coordinated national drills during 1999.
The Company is currently reviewing the Year 2000 readiness of material
third parties that provide goods and services crucial to the Company's
operations. Among such critical third parties are fuel, transportation,
telecommunications, water, chemical, and other suppliers. Contingency plans
based on the assessment of each third party's ability to continue supplying
critical goods and services to the Company are being developed.
There is a potential for some earnings erosion caused by reduced electrical
demand by customers because of their own Year 2000 issues.
Year 2000 Contingency Plans
Because of experience with hurricanes and other storms, the Company is skilled
at developing and using contingency plans in unusual circumstances. As part of
Year 2000 business continuity and contingency planning, the Company is drawing
on that experience to make risk assessments and developing additional plans to
deal specifically with situations that could arise relative to Year 2000
challenges. The Company is identifying critical operational locations, and key
employees will be on duty at those locations during the Year 2000 transition. In
September 1999, drills are scheduled to be conducted to test contingency plans.
Because of the level of detail of the contingency planning process, management
feels that the contingency plans will keep any service interruptions that may
occur within the service territory isolated and short in duration.
11-194
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 1998 Annual Report
FINANCIAL CONDITION
Overview
The principal change in the Company's financial condition in 1998 was the
addition of $18.1 million to utility plant. The funds needed for gross property
additions are currently provided from operating activities, principally from
earnings and non-cash charges to income such as depreciation and deferred income
taxes and from financing activities. See Statements of Cash Flows for additional
information.
Capital Structure
As of December 31, 1998, the Company's capital structure consisted of 46.4
percent common stock equity, 10.5 percent trust preferred securities, and 43.1
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 48 percent, preferred securities at 10 percent and
debt at 42 percent.
In March 1998, the Company issued $30 million of Series A 6 5/8% senior
retail intermediate bonds maturing in 2015. The Company used these proceeds to
redeem the remaining amount of its 8.30% first mortgage bonds due in 2022.
Maturities and retirements of long-term debt were $30 million in 1998, $14
million in 1997, and $29 million in 1996.
In November 1998, the Company redeemed all of its 1,400,000 shares of 6.64%
Series Preferred Stock at a redemption price of $25 per share, plus accrued
dividends through the date of redemption.
In December 1998, Savannah Electric Capital Trust I, of which the Company
owns all of the common securities, issued $40 million of 6.85% mandatorily
redeemable preferred securities.
The composite interest rates and dividend rates for the years 1996 through
1998 as of year-end were as follows:
1998 1997 1996
-------------------------------
Composite interest rates
on long-term debt 6.5% 6.9% 7.0%
Preferred stock dividend rate -% 6.6% 6.6%
Trust preferred securities
dividend rate 6.9% -% -%
==================================================================
Capital Requirements for Construction
The Company's projected construction expenditures for the next three years total
$92 million ($29 million in 1999, $32 million in 2000, and $31 million in 2001).
Actual construction costs may vary from this estimate because of factors such as
changes in: business conditions; environmental regulations; load projections;
the cost and efficiency of construction labor, equipment and materials; and the
cost of capital. In addition, there can be no assurance that costs related to
capital expenditures will be fully recovered. In early 1999, the Company will
issue a Request for Proposal for bids to provide its capacity requirements for
2002. These bids will be compared to self-build options to identify the least
cost supply option. The supply decision should be made by late summer.
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
$31.9 million will be needed by the end of 2001 for maturities of long-term debt
and present sinking fund requirements.
11-195
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 1998 Annual Report
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--significantly affected
the Company and other subsidiaries of Southern Company. Specific reductions in
sulfur dioxide and nitrogen oxide emissions from fossil-fired generating plants
are required in two phases. Phase I compliance began in 1995 and initially
affected 28 generating units of Southern Company. As a result of Southern
Company's compliance strategy, an additional 22 generating units, which included
four of the Company's units, were brought into compliance with Phase I
requirements. Phase II compliance is required in 2000, and all fossil-fired
generating plants will be affected.
Southern Company achieved Phase I sulfur dioxide compliance at the affected
plants by switching to low-sulfur coal, which required some equipment upgrades.
This compliance strategy resulted in unused emission allowances being banked for
later use. Construction expenditures for Phase I compliance totaled
approximately $2 million for Savannah Electric.
For Phase II sulfur dioxide compliance, Southern Company could use emission
allowances, increase fuel switching, and/or install flue gas desulfurization
equipment at selected plants. Also, equipment to control nitrogen oxide
emissions will be installed on additional system fossil-fired plants as
necessary to meet Phase II limits. Current compliance strategy for Phase II and
ozone non-attainment could require total estimated construction expenditures for
Southern Company of approximately $70 million, of which $16 million remains to
be spent. Phase II compliance is not expected to have a material impact on
Savannah Electric.
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.
In July 1997, the Environmental Protection Agency (EPA) revised the
national ambient air quality standards for ozone and particulate matter. This
revision makes the standards significantly more stringent. In September 1998,
the EPA issued the final regional nitrogen oxide rules to the states for
implementation. The states have one year to adopt and implement the rules. The
final rules affect 22 states including Georgia. The EPA rules are being
challenged in the courts by several states and industry groups. Implementation
of the final state rules could require substantial further reductions in
nitrogen oxide emissions from fossil-fired generating facilities and other
industry in these states. Implementation of the standards could result in
significant additional compliance costs and capital expenditures that cannot be
determined until the results of legal challenges are known, and the states have
adopted their final rules.
The EPA and state environmental regulatory agencies are reviewing and
evaluating various other matters including: nitrogen oxide emission control
strategies for ozone non-attainment areas; additional controls for hazardous air
pollutant emissions; control strategies to reduce regional haze; and hazardous
waste disposal requirements. The impact of new standards will depend on the
development and implementation of applicable regulations.
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 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 Air Act; the
Clean Water Act; the Comprehensive Environmental Response, Compensation, and
Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances
Control Act; and the Endangered Species Act. Changes to these laws could affect
many areas of Southern Company's operations. The full impact of any such changes
cannot be determined at this time.
Compliance with possible additional legislation related to global climate
change, electromagnetic fields, and other environmental and health concerns
could significantly affect 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.
11-196
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 1998 Annual Report
Sources of Capital
At December 31, 1998, the Company had $6.0 million of cash and $40.5 million of
unused short-term credit arrangements with banks to meet its short-term cash
needs. Revolving credit arrangements of $20 million, which expire December 31,
2001, are also used to meet short-term cash needs and to provide additional
interim funding for the Company's construction program. Of the revolving credit
arrangements, $20 million remained unused at December 31, 1998.
It is anticipated that the funds required for construction and other
purposes, including compliance with environmental regulation, will be derived
from sources similar to those used in the past. These sources were primarily
from the issuances of first mortgage bonds, other long-term debt, and preferred
stock, in addition to pollution control revenue bonds issued for the Company's
benefit by public authorities, to meet long-term external financing
requirements. Recently, the Company's financings have consisted of unsecured
debt and trust preferred securities. The Company is required to meet certain
earnings 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 to permit, at present interest rate
levels, any foreseeable security sales. In December 1998, the Company obtained
stockholder approval to amend the corporate charter including the elimination of
the restrictions on the amount of unsecured indebtedness allowed. 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.
Cautionary Statement Regarding Forward-Looking Information
Savannah Electric and Power Company's 1998 Annual Report contains
forward-looking and historical information. The Company cautions that there are
various important factors that could cause actual results to differ materially
from those indicated in the forward-looking information; accordingly, there can
be no assurance that such indicated results will be realized. These factors
include legislative and regulatory initiatives regarding deregulation and
restructuring of the electric utility industry; the extent and timing of the
entry of additional competition in the Company's markets; potential business
strategies--including acquisitions or dispositions of assets or internal
restructuring--that may be pursued by the Company; state and federal rate
regulation; Year 2000 issues; changes in or application of environmental and
other laws and regulations to which the Company is subject; political, legal and
economic conditions and developments; financial market conditions and the
results of financing efforts; changes in commodity prices and interest rates;
weather and other natural phenomena; and other factors discussed in the
reports--including Form 10-K--filed from time to time by the Company with the
Securities and Exchange Commission.
11-197
STATEMENTS OF INCOME
For the Years Ended December 31, 1998, 1997, and 1996
Savannah Electric and Power Company 1998 Annual Report
================================================================================================================================
1998 1997 1996
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Revenues (Note 1):
Revenues $ 251,439 $ 224,225 $ 230,944
Revenues from affiliates 3,016 2,052 3,130
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Total operating revenues 254,455 226,277 234,074
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
Fuel 53,021 35,563 29,139
Purchased power from non-affiliates 9,460 2,347 2,350
Purchased power from affiliates 35,687 42,107 58,591
Other 49,055 47,735 44,007
Maintenance 18,711 13,236 14,140
Depreciation and amortization (Notes 1 and 3) 22,032 20,152 19,113
Taxes other than income taxes 12,342 11,494 11,675
Federal and state income taxes (Notes 1 and 6) 16,335 16,419 16,175
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Total operating expenses 216,643 189,053 195,190
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Operating Income 37,812 37,224 38,884
Other Income (Expense):
Allowance for equity funds used during construction 83 239 317
Interest income 384 279 201
Other, net (1,781) (781) (1,756)
Income taxes applicable to other income (Notes 1 and 6) 1,234 1,233 1,034
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Income Before Interest Charges 37,732 38,194 38,680
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Interest and Other Charges:
Interest on long-term debt 10,383 10,907 11,563
Allowance for debt funds used during construction (133) (164) (333)
Interest on notes payable 278 172 229
Amortization of debt discount, premium, and expense, net 853 739 579
Distributions on preferred securities of subsidiary trust 167 - -
Other interest charges 474 369 378
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Interest and other charges, net 12,022 12,023 12,416
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Net Income 25,710 26,171 26,264
Dividends on Preferred Stock 2,066 2,324 2,324
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred Stock $ 23,644 $ 23,847 $ 23,940
================================================================================================================================
STATEMENTS OF RETAINED EARNINGS
For the Years Ended December 31, 1998, 1997, and 1996
================================================================================================================================
1998 1997 1996
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Balance at Beginning of Year $ 112,720 $ 109,373 $ 105,033
Net income after dividends on preferred stock 23,644 23,847 23,940
Cash dividends on common stock (23,500) (20,500) (19,600)
Preferred stock transactions, net and other adjustments 90 - -
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Balance at End of Year (Note 9) $ 112,954 $ 112,720 $ 109,373
================================================================================================================================
The accompanying notes are an integral part of these statements.
11-198
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1998, 1997, and 1996
Savannah Electric and Power Company 1998 Annual Report
================================================================================================================================
1998 1997 1996
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Activities:
Net income $ 25,710 $ 26,171 $ 26,264
Adjustments to reconcile net income to net
cash provided from operating activities --
Depreciation and amortization 23,531 21,083 20,246
Deferred income taxes and investment tax credits, net 7,011 3,841 7,482
Allowance for equity funds used during construction (83) (239) (317)
Other, net (6) (2,577) (641)
Changes in certain current assets and liabilities --
Receivables, net (9,969) (3,239) (641)
Inventories 705 1,720 410
Payables 470 (1,608) 4,242
Taxes accrued (434) 2,310 (569)
Other (4,331) 2,357 (4,038)
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities 42,604 49,819 52,438
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (18,071) (18,846) (28,950)
Other 1,617 (1,418) (3,173)
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities (16,454) (20,264) (32,123)
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Financing Activities and Capital Contributions:
Proceeds:
Preferred securities 40,000 - -
First mortgage bonds - - 20,000
Pollution control notes - 13,870 -
Other long-term debt 30,000 - 17,000
Retirements:
Preferred stock (35,000) - -
First mortgage bonds (30,000) - (29,400)
Pollution control bonds - (13,870) -
Other long-term debt (478) (433) (397)
Notes payable, net - (5,000) 1,000
Payment of preferred stock dividends (2,556) (2,324) (2,324)
Payment of common stock dividends (23,500) (20,500) (19,600)
Miscellaneous (4,798) (368) (2,257)
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Net cash used for financing activities (26,332) (28,625) (15,978)
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents (182) 930 4,337
Cash and Cash Equivalents at Beginning of Year 6,144 5,214 877
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 5,962 $ 6,144 $ 5,214
================================================================================================================================
Supplemental Cash Flow Information:
Cash paid during the year for-
Interest (net of amount capitalized) $12,198 $11,619 $12,960
Income taxes 9,666 11,150 10,926
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
( ) Denotes use of cash.
The accompanying notes are an integral part of these statements.
11-199
BALANCE SHEETS
At December 31, 1998 and 1997
Savannah Electric and Power Company 1998 Annual Report
============================================================================================================================
Assets 1998 1997
- - - - - - - ----------------------------------------------------------------------------------------------------------------------------
(in thousands)
Utility Plant:
Plant in service, at original cost (Notes 1, 4, 5, and 8) $ 781,964 $ 760,694
Less accumulated provision for depreciation 341,930 321,509
- - - - - - - ----------------------------------------------------------------------------------------------------------------------------
440,034 439,185
Construction work in progress 2,908 7,709
- - - - - - - ----------------------------------------------------------------------------------------------------------------------------
Total 442,942 446,894
- - - - - - - ----------------------------------------------------------------------------------------------------------------------------
Other Property and Investments 1,420 1,783
- - - - - - - ----------------------------------------------------------------------------------------------------------------------------
Current Assets:
Cash and cash equivalents 5,962 6,144
Special deposits - 94
Receivables-
Customer accounts receivable 18,030 21,148
Other accounts and notes receivable 3,543 720
Affiliated companies 1,388 1,128
Accumulated provision for uncollectible accounts (284) (354)
Fuel cost under recovery 17,628 7,694
Fossil fuel stock, at average cost 4,984 5,205
Materials and supplies, at average cost (Note 1) 6,496 6,980
Prepayments 4,772 5,922
- - - - - - - ----------------------------------------------------------------------------------------------------------------------------
Total 62,519 54,681
- - - - - - - ----------------------------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets:
Deferred charges related to income taxes (Note 6) 17,130 17,267
Debt issue expense, being amortized 3,554 2,255
Premium on reacquired debt, being amortized 8,570 7,121
Prepaid pension costs (Note 2) 3,281 3,424
Cash surrender value of life insurance for deferred compensation plans 14,179 12,130
Miscellaneous 2,204 1,797
- - - - - - - ----------------------------------------------------------------------------------------------------------------------------
Total 48,918 43,994
- - - - - - - ----------------------------------------------------------------------------------------------------------------------------
Total Assets $ 555,799 $ 547,352
============================================================================================================================
The accompanying notes are an integral part of these statements.
II-200
BALANCE SHEETS
At December 31, 1998 and 1997
Savannah Electric and Power Company 1998 Annual Report
============================================================================================================================
Capitalization and Liabilities 1998 1997
- - - - - - - ----------------------------------------------------------------------------------------------------------------------------
(in thousands)
Capitalization (See accompanying statements):
Common stock equity $ 175,865 $ 175,631
Preferred stock - 35,000
Company obligated mandatorily redeemable preferred securities of
subsidiary trust holding company junior subordinated notes (Note 7) 40,000 -
Long-term debt 163,443 142,846
- - - - - - - ----------------------------------------------------------------------------------------------------------------------------
Total 379,308 353,477
- - - - - - - ----------------------------------------------------------------------------------------------------------------------------
Current Liabilities:
Amount of securities due within one year (Note 8) 689 21,764
Accounts payable-
Affiliated companies 5,014 6,025
Other 10,833 7,862
Customer deposits 5,224 5,541
Taxes accrued-
Federal and state income 2,467 534
Other 2,891 2,791
Interest accrued 3,815 4,963
Vacation pay accrued 1,978 1,893
Miscellaneous 6,700 9,031
- - - - - - - ----------------------------------------------------------------------------------------------------------------------------
Total 39,611 60,404
- - - - - - - ----------------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes (Note 6) 82,778 80,697
Accumulated deferred investment tax credits (Note 6) 11,943 12,607
Deferred credits related to income taxes (Note 6) 21,349 21,469
Deferred compensation plans 9,788 9,272
Postretirement benefits (Note 2) 6,434 6,011
Miscellaneous 4,588 3,415
- - - - - - - ----------------------------------------------------------------------------------------------------------------------------
Total 136,880 133,471
- - - - - - - ----------------------------------------------------------------------------------------------------------------------------
Commitments and Contingent Matters (Notes 1, 2, 3, 4, 5, and 8)
Total Capitalization and Liabilities $ 555,799 $ 547,352
============================================================================================================================
The accompanying notes are an integral part of these statements.
II-201
STATEMENTS OF CAPITALIZATION
At December 31, 1998 and 1997
Savannah Electric and Power Company 1998 Annual Report
================================================================================================================================
1998 1997 1998 1997
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
Common Stock Equity (Note 9):
Common stock, par value $5 per share --
Authorized -- 16,000,000 shares
Outstanding -- 10,844,635 shares in
1998 and 1997 $ 54,223 $ 54,223
Paid-in capital 8,688 8,688
Retained earnings 112,954 112,720
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Total common stock equity 175,865 175,631 46.4 % 49.7 %
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Cumulative Preferred Stock (Note 7):
$25 par value --
Authorized -- 2,200,000 shares
6.64% Series -- Outstanding -- 1,400,000 shares
in 1997 - 35,000
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Total (annual dividend requirement -- $2,324,000) - 35,000 - 9.9
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Company Obligated Mandatorily Redeemable
Preferred Securities (Note 7):
$25 Liquidation Value -- 6.85% 40,000 -
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Total (annual distribution requirement -- $2,740,000) 40,000 - 10.5 -
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Long-Term Debt (Note 8):
First mortgage bonds --
Maturity Interest Rates
-------- --------------
July 1, 2003 6 3/8% 20,000 20,000
May 1, 2006 6.90% 20,000 20,000
July 1, 2022 8.30% - 30,000
July 1, 2023 7.40% 25,000 25,000
May 1, 2025 7 7/8% 15,000 15,000
Other long-term debt --
Pollution control revenue bonds --
Collateralized:
Variable rate (4.00% at 1/1/99) due 2016 4,085 4,085
Variable rate bank note (5.10% at 1/1/99) due 2037 13,870 13,870
Long-term notes payable --
6.88% due 2001 10,000 10,000
Variable rate (5.38% at 1/1/99) due 2001 10,000 15,000
Variable rate (5.77% at 1/1/99) due 2001 10,000 5,000
6 5/8% Retail Intermediate Bond due 2015 30,000 -
Capitalized lease obligations --
Coal unloading facility variable rate (5.80% at 1/1/99) 5,467 5,867
Transportation fleet 710 788
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
requirement -- $10,717,000) 164,132 164,610
Less amount due within one year (Note 8) 689 21,764
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Long-term debt excluding amount due within one year 163,443 142,846 43.1 40.4
- - - - - - - --------------------------------------------------------------------------------------------------------------------------------
Total Capitalization $ 379,308 $ 353,477 100.0 % 100.0 %
================================================================================================================================
The accompanying notes are an integral part of these statements.
II-202
NOTES TO FINANCIAL STATEMENTS
Savannah Electric and Power Company 1998 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING
POLICIES
General
Savannah Electric and Power Company (the Company), is a wholly owned subsidiary
of Southern Company, which is the parent company of five operating companies, a
system service company, Southern Communications Services (Southern LINC),
Southern Energy, Inc. (Southern Energy), Southern Nuclear Operating Company
(Southern Nuclear), Southern Company Energy Solutions, and other direct and
indirect subsidiaries. The operating companies provide electric service in four
southeastern states. Contracts among the companies--dealing with jointly owned
generating facilities, interconnecting transmission lines, and the exchange of
electric power--are regulated by the Federal Energy Regulatory Commission (FERC)
and/or the Securities and Exchange Commission. The system service company
provides, at cost, specialized services to Southern Company and subsidiary
companies. Southern LINC provides digital wireless communications services to
the operating companies and also markets these services to the public within the
Southeast. Worldwide, Southern Energy develops and manages electricity and other
energy related projects, including domestic energy trading and marketing.
Southern Nuclear provides services to Southern Company's nuclear power plants.
Southern Company Energy Solutions develops new business opportunities related to
energy products and services.
Southern Company is registered as a holding company under the Public
Utility Holding Company Act of 1935 (PUHCA). Both 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.
The preparation of financial statements in conformity with generally accepted
accounting principles requires the use of estimates, and the actual results may
differ from those estimates.
Certain prior years' data presented in the financial statements has been
reclassified to conform with the 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 expected to be credited
to customers through the ratemaking process. Regulatory assets and (liabilities)
reflected in the Balance Sheets at December 31 relate to:
1998 1997
---------------------------
(in thousands)
Deferred income taxes $ 17,130 $ 17,267
Premium on reacquired debt 8,570 7,121
Deferred income tax credits (21,349) (21,469)
Storm damage reserves (1,580) (1,500)
Accelerated depreciation (1,000) -
- - - - - - - ---------------------------------------------------------------
Total $ 1,771 $ 1,419
===============================================================
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 net regulatory assets and liabilities that are not
specifically recoverable through regulated rates. In addition, the Company would
be required to determine if any impairment to other assets exists, including
plant, and write down the assets, if impaired, to their fair value.
Revenues and Fuel Costs
The Company currently operates as a vertically integrated utility providing
electricity to retail customers within its traditional service area of
southeastern Georgia, and to non-affiliated customers in the Southeast.
Revenues, less affiliated transactions, by type of service were as follows:
1998 1997 1996
--------------------------------------
(in thousands)
Retail $242,327 $219,458 $227,982
Sales for resale--
Non-affiliates 4,548 3,467 1,998
Other 4,564 1,300 964
- - - - - - - ------------------------------------------------------------
Total $251,439 $224,225 $230,944
============================================================
Other revenues include rents and revenues from non-utility services.
II-203
NOTES (continued)
Savannah Electric and Power Company 1998 Annual Report
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
costs, the energy component of purchased power costs, and certain other 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 1998, uncollectible
accounts continued to average less than 1 percent of revenues.
In January 1999, the GPSC approved an increase of slightly over one-tenth of
a cent per kilowatt-hour in the Company's fuel allowance, effective in February
1999.
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 1998 and 1997 and 2.8 percent in 1996. 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
removal of certain facilities. See Note 3 to the financial statements for more
information.
Income Taxes
The Company, which is included in the consolidated federal income tax return
filed by Southern Company, uses the liability method of accounting for deferred
income taxes and provides deferred income taxes for all significant income tax
temporary differences. Investment tax credits utilized are deferred and
amortized to income over the average lives of the related property.
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 8.00 percent in 1998, 9.24 percent in 1997 and 8.69 percent in 1996.
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 AFUDC.
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 financial statements, temporary cash investments are
considered cash equivalents. Temporary cash investments are securities with
original maturities of 90 days or less.
Financial Instruments
The Company's financial instruments for which the carrying amounts did not equal
fair value at December 31 were as follows:
Carrying Fair
Amount Value
--------------------------
(in millions)
Long-term debt:
At December 31, 1998 $158 $162
At December 31, 1997 158 161
Trust preferred securities:
At December 31, 1998 $40 $40
At December 31, 1997 - -
The fair values for long-term debt and preferred securities were based on
either closing market prices or closing prices of comparable instruments.
II-204
NOTES (continued)
Savannah Electric and Power Company 1998 Annual Report
Materials and Supplies
Generally, materials and supplies include the costs of transmission,
distribution, and generating plant materials. Materials are charged to inventory
when purchased and then expensed or capitalized to plant, as appropriate, when
installed.
2. RETIREMENT BENEFITS
The Company has defined benefit, trusteed, non-contributory pension plans that
cover substantially all employees. The Company provides certain medical care and
life insurance benefits for retired employees. Substantially all these employees
may become eligible for such benefits when they retire. The Company funds trusts
to the extent deductible under federal income tax regulations or to the extent
required by the GPSC. In 1998, the Company adopted FASB Statement No. 132,
Employers' Disclosure about Pensions and Other Postretirement Benefits. The
measurement date is September 30 of each year.
The weighted average rates assumed in the actuarial calculations for both
the pension plans and postretirement benefit plans were:
1998 1997
- - - - - - - ---------------------------------------------------------------
Discount 6.75% 7.50%
Annual salary increase 4.25 5.00
Long-term return on plan assets 8.50 8.50
- - - - - - - ---------------------------------------------------------------
Pension Plan
Changes during the year in the projected benefit obligations and in the fair
value of plan assets were as follows:
Projected
Benefit Obligations
---------------------------
1998 1997
- - - - - - - ---------------------------------------------------------------
(in thousands)
Balance at beginning of year $51,720 $49,914
Service cost 1,495 1,393
Interest cost 3,806 3,556
Benefits paid (3,392) (2,403)
Actuarial (gain) loss and
employee transfers 4,343 (740)
Amendments 1,235 -
- - - - - - - ---------------------------------------------------------------
Balance at end of year $59,207 $51,720
===============================================================
Plan Assets
---------------------------
1998 1997
- - - - - - - ---------------------------------------------------------------
(in thousands)
Balance at beginning of year $50,630 $42,430
Actual return on plan assets 171 7,603
Employer contributions 2,464 3,000
Benefits paid (3,392) (2,403)
Employee transfers (243) -
- - - - - - - ---------------------------------------------------------------
Balance at end of year $49,630 $50,630
===============================================================
The accrued pension costs recognized in the Balance Sheets were as
follows:
1998 1997
- - - - - - - -----------------------------------------------------------------
(in thousands)
Funded status $(9,577) $(1,090)
Unrecognized transition
obligation 266 355
Unrecognized prior service cost 2,874 1,884
Unrecognized net loss 9,718 1,275
Fourth quarter contributions - 1,000
- - - - - - - -----------------------------------------------------------------
Prepaid asset recognized in
the Balance Sheets $ 3,281 $ 3,424
=================================================================
Components of the plans' net periodic cost were as follows:
1998 1997 1996
- - - - - - - -----------------------------------------------------------------
(in thousands)
Service cost $1,495 $1,393 $1,352
Interest cost 3,806 3,556 3,389
Expected return on plan
assets (3,992) (3,782) (3,263)
Recognized net loss 2 475 626
Net amortization 334 280 224
- - - - - - - -----------------------------------------------------------------
Net pension cost $1,645 $1,922 $2,328
=================================================================
II-205
NOTES (continued)
Savannah Electric and Power Company 1998 Annual Report
Postretirement Benefits
Changes during the year in the projected benefit obligations and in the fair
value of plan assets were as follows:
Projected
Benefit Obligations
---------------------------
1998 1997
- - - - - - - ---------------------------------------------------------------
(in thousands)
Balance at beginning of year $20,899 $20,520
Service cost 348 319
Interest cost 1,527 1,499
Benefits paid (839) (526)
Actuarial (gain) loss and
employee transfers 1,621 (913)
- - - - - - - ---------------------------------------------------------------
Balance at end of year $23,556 $20,899
===============================================================
Plan Assets
---------------------------
1998 1997
- - - - - - - ---------------------------------------------------------------
(in thousands)
Balance at beginning of year $3,110 $2,473
Actual return on plan assets 85 365
Employer contributions 1,447 798
Benefits paid (839) (526)
- - - - - - - ---------------------------------------------------------------
Balance at end of year $3,803 $3,110
===============================================================
The accrued postretirement costs recognized in the Balance Sheets were
as follows:
1998 1997
- - - - - - - -----------------------------------------------------------------
(in thousands)
Funded status $(19,753) $(17,789)
Unrecognized transition
obligation 6,913 7,407
Unrecognized net loss 5,444 3,737
Fourth quarter contributions 1,152 749
- - - - - - - -----------------------------------------------------------------
Accrued liability recognized in
the Balance Sheets $ (6,244) $(5,896)
=================================================================
Components of the plans' net periodic cost were as follows:
1998 1997 1996
- - - - - - - ----------------------------------------------------------------
(in thousands)
Service cost $ 348 $ 319 $ 360
Interest cost 1,528 1,499 1,422
Expected return on plan assets (276) (211) (129)
Recognized net loss 104 125 171
Net amortization 494 494 494
- - - - - - - -----------------------------------------------------------------
Net postretirement cost $2,198 $2,226 $2,318
================================================================
An additional assumption used in measuring the accumulated postretirement
benefit obligations was a weighted average medical care cost trend rate of 8.30
percent for 1998, decreasing gradually to 4.75 percent through the year 2005,
and remaining at that level thereafter. An annual increase or decrease in the
assumed medical care cost trend rate of 1 percent would affect the accumulated
benefit obligation and the service and interest cost components at December 31,
1998 as follows:
1 Percent 1 Percent
Increase Decrease
- - - - - - - ---------------------------------------------------------------
(in thousands)
Benefit obligation $1,301 $(1,227)
Service and interest costs 107 (101)
===============================================================
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 were $0.4 million for 1998, 1997 and 1996.
Work Force Reduction Program
In 1997, the Company incurred a $1.9 million, one-time charge to other operation
expense for costs related to the implementation of a work force reduction
program.
II-206
NOTES (continued)
Savannah Electric and Power Company 1998 Annual Report
3. REGULATORY MATTERS
Rates to retail customers served by the Company are regulated by the GPSC. As
part of the Company's rate settlement in 1992, it was informally agreed that the
Company's earned rate of return on common equity should be 12.95 percent.
In June 1998, the GPSC approved a four-year accounting order for the
Company. Under this order, the Company will reduce the electric rates of its
small business customers by approximately $11 million over the next four years.
The Company will also expense an additional $1.95 million in storm damage
accruals and accrue an additional $8 million in depreciation on generating
assets over the term of the order. The additional depreciation will be
accumulated in a regulatory liability account to be available to mitigate any
potential stranded costs. In addition, the Company has discretionary authority
to provide up to an additional $0.3 million per year in storm damage accruals
and up to an additional $4.0 million in depreciation expense over the four
years. The Company is also precluded from asking for a rate increase except upon
significant changes in economic conditions, new laws, or regulations. There will
be a quarterly monitoring of the Company's earnings performance.
4. CONSTRUCTION PROGRAM
The Company is engaged in a continuous construction program, currently estimated
to total $29 million in 1999, $32 million in 2000, and $31 million in 2001. 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 changes in cost of capital. The Company
does not have any traditional baseload generating plants under construction.
However, construction related to transmission and distribution facilities and
the upgrading of generating plants will continue.
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, preferred securities, and capital contributions from Southern Company.
The amounts of long-term debt and preferred securities that can be issued
in the future will be contingent on market conditions, the maintenance of
adequate earnings levels, regulatory authorizations, and other factors.
Bank Credit Arrangements
At the end of 1998, unused credit arrangements with six banks totaled $40.5
million and expire at various times during 1999 and 2000.
The Company's revolving credit arrangements of $20 million, all of which
remained unused as of December 31, 1998, expire December 31, 2001. These
agreements allow short-term borrowings to be converted into term loans, payable
in 12 equal quarterly installments, with the first installment due at the end of
the first calendar quarter after the applicable termination date or at an
earlier date at the Company's option.
In connection with these credit arrangements, the Company agrees to pay
commitment fees based on the unused portions of the commitments.
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. A second
lien for $10 million of bank debt is secured by a portion of the Plant Kraft
property and a second lien for $34 million in bank notes is secured by a portion
of the Plant McIntosh property.
II-207
NOTES (continued)
Savannah Electric and Power Company 1998 Annual Report
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. The Company has fuel
commitments of $12.0 million and $9.0 million for 1999 and 2000, respectively.
Operating Leases
The Company has rental agreements with various terms and expiration dates.
Rental expenses totaled $1.1 million for 1998, $1.2 million for 1997, and $1.6
million for 1996. The Company entered into a 22.5 year lease agreement effective
December 1, 1995 for 100 new aluminum rail cars at an annual cost of
approximately $0.5 million. The rail cars are used to transport coal to one of
the Company's generating plants.
At December 31, 1998, estimated future minimum lease payments for
noncancelable operating leases were as follows:
Rental Commitments
--------------------
(in thousands)
1999 $ 483
2000 483
2001 483
2002 483
2003 483
2004 and thereafter 6,969
- - - - - - - -------------------------------------------------------------
6. INCOME TAXES
At December 31, 1998, tax-related regulatory assets and liabilities were $17
million and $21 million, respectively. 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 income tax provisions are as follows:
1998 1997 1996
--------------------------------
(in thousands)
Total provision for income taxes
Federal --
Currently payable $ 6,763 $ 9,743 $ 7,084
Deferred -- current year 8,377 4,522 8,216
-- reversal of
prior years (2,565) (1,381) (1,989)
- - - - - - - ------------------------------------------------------------------
12,575 12,884 13,311
- - - - - - - ------------------------------------------------------------------
State --
Currently payable 1,327 1,603 575
Deferred -- current year 1,174 569 1,216
-- reversal of
prior years 25 130 39
- - - - - - - ------------------------------------------------------------------
2,526 2,302 1,830
- - - - - - - ------------------------------------------------------------------
Total 15,101 15,186 15,141
Less income taxes credited
to other income (1,234) (1,233) (1,034)
- - - - - - - ------------------------------------------------------------------
Total income taxes
charged to operations $16,335 $16,419 $16,175
==================================================================
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:
1998 1997
--------------------
Deferred tax liabilities: (in thousands)
Accelerated depreciation $75,187 $72,663
Property basis differences 7,591 8,034
Other 10,187 5,850
- - - - - - - ----------------------------------------------------------------
Total 92,965 86,547
- - - - - - - ----------------------------------------------------------------
Deferred tax assets:
Pension and other benefits 4,892 5,338
Other 2,828 2,957
- - - - - - - ----------------------------------------------------------------
Total 7,720 8,295
- - - - - - - ----------------------------------------------------------------
Net deferred tax liabilities 85,245 78,252
Portions included in current assets, net (2,467) 2,445
- - - - - - - ----------------------------------------------------------------
Accumulated deferred income taxes
in the Balance Sheets $82,778 $80,697
================================================================
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 1998, 1997, and 1996. At December 31, 1998, all
investment tax credits available to reduce federal income taxes payable had been
utilized.
II-208
NOTES (continued)
Savannah Electric and Power Company 1998 Annual Report
A reconciliation of the federal statutory income tax rate to the effective
income tax rate is as follows:
1998 1997 1996
---------------------------
Federal statutory tax rate 35% 35% 35%
State income tax, net of
federal income tax benefit 4 4 3
Other (2) (2) (1)
--------------------------------------------------------------
Effective income tax rate 37% 37% 37%
==============================================================
Southern Company files a consolidated federal income tax return. Under a
joint consolidated income tax agreement, each subsidiary's current and deferred
tax expense is computed on a stand-alone basis. Tax benefits from losses of the
parent company are allocated to each subsidiary based on the ratio of taxable
income to total consolidated taxable income.
7. CUMULATIVE PREFERRED STOCK AND
TRUST PREFERRED SECURITIES
In November 1998, the Company redeemed all of its 1,400,000 shares of 6.64%
Series Preferred Stock at a redemption price of $25 per share, plus accrued
dividends through the date of redemption.
In December 1998, Savannah Electric Capital Trust I, of which the Company
owns all of the common securities, issued $40 million of 6.85% mandatorily
redeemable preferred securities. Substantially all of the assets of Trust I are
$40 million aggregate principal amount of the Company's 6.85% junior
subordinated notes due December 31, 2028.
The Company considers that the mechanisms and obligations relating to the
preferred securities, taken together, constitute a full and unconditional
guarantee by the Company of payment obligations with respect to the preferred
securities of Savannah Electric Capital Trust I.
Savannah Electric Capital Trust I is a subsidiary of the Company, and
accordingly is consolidated in the Company's financial statements.
8. LONG-TERM DEBT AND LONG-TERM DEBT
DUE WITHIN ONE YEAR
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 March 1998, the Company issued $30 million of Series A 6 5/8% senior
retail intermediate bonds maturing in 2015. The Company used these proceeds to
redeem the remaining amount of its 8.30% first mortgage bonds due in 2022.
Maturities and retirements of long-term debt were $30 million in 1998, $14
million in 1997 and $29 million in 1996.
In April 1997, the Company issued $14 million in variable rate pollution
control obligations (bank note) maturing in 2037. The Company redeemed all of
its remaining outstanding 6 3/4% Pollution Control Bonds due 2022.
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.
A summary of the sinking fund requirements and scheduled maturities and
redemptions of long-term debt due within one year at December 31 is as follows:
1998 1997
---------------------
(in thousands)
Bond sinking fund requirement $800 $ 1,100
Less:
Portion to be satisfied by
certifying property additions 800 -
- - - - - - - -------------------------------------------------------------------
Cash sinking fund requirement - 1,100
Other long-term debt maturities 689 20,664
- - - - - - - -------------------------------------------------------------------
Total $689 $21,764
===================================================================
II-209
NOTES (continued)
Savannah Electric and Power Company 1998 Annual Report
The first mortgage bond improvement (sinking) fund requirements amount 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 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.
The sinking fund requirements of first mortgage bonds were satisfied by
cash redemption in 1998 and by certifying property additions in 1997. It is
anticipated that the 1999 requirement will be satisfied by certifying property
additions. Sinking fund requirements and/or maturities through 2003 applicable
to long-term debt are as follows: $0.7 million in 1999; $0.6 million in 2000;
$30.5 million in 2001; $0.5 million in 2002; and $20.4 million in 2003.
9. COMMON STOCK DIVIDEND RESTRICTIONS
The Company's Indenture contains certain limitations on the payment of cash
dividends on common stock. At December 31, 1998, approximately $68 million of
retained earnings was restricted against the payment of cash dividends on common
stock under the terms of the Indenture.
10. QUARTERLY FINANCIAL INFORMATION
(Unaudited)
Summarized quarterly financial data for 1998 and 1997 are as follows (in
thousands):
Net Income After
Operating Operating Dividends on
Quarter Ended Revenues Income Preferred Stock
- - - - - - - ------------------------------------------------------------------
March 1998 $48,381 $ 6,214 $ 2,426
June 1998 69,616 11,606 7,807
September 1998 84,224 16,056 12,518
December 1998 52,234 3,936 893
March 1997 $42,945 $ 6,117 $ 2,545
June 1997 52,516 8,626 5,136
September 1997 79,900 17,531 14,276
December 1997 50,916 4,950 1,890
- - - - - - - ------------------------------------------------------------------
The Company's business is influenced by seasonal weather conditions and a
seasonal rate structure, among other factors.
II-210
SELECTED FINANCIAL AND OPERATING DATA
Savannah Electric and Power Company 1998 Annual Report
=========================================================================================================================
1998 1997 1996 1995
- - - - - - - -------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands) $254,455 $226,277 $234,074 $225,729
Net Income after Dividends
on Preferred and Preference Stocks (in thousands) $23,644 $23,847 $23,940 $23,395
Cash Dividends on Common Stock (in thousands) $23,500 $20,500 $19,600 $17,600
Return on Average Common Equity (percent) 13.45 13.71 14.08 14.20
Total Assets (in thousands) $555,799 $547,352 $544,900 $524,662
Gross Property Additions (in thousands) $18,071 $18,846 $28,950 $26,503
- - - - - - - -------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $175,865 $175,631 $172,284 $167,812
Preferred stock - 35,000 35,000 35,000
Preferred and preference stock subject
to mandatory redemption - - - -
Trust preferred securities 40,000 - - -
Long-term debt 163,443 142,846 164,406 153,679
- - - - - - - -------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $379,308 $353,477 $371,690 $356,491
=========================================================================================================================
Capitalization Ratios (percent):
Common stock equity 46.4 49.7 46.4 47.1
Preferred and preference stock - 9.9 9.4 9.8
Trust preferred securities 10.5 - - -
Long-term debt 43.1 40.4 44.2 43.1
- - - - - - - -------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0 100.0 100.0
=========================================================================================================================
First Mortgage Bonds (in thousands):
Issued - - 20,000 15,000
Retired 30,000 - 29,400 29,250
Preferred Stock and Preferred Securities (in thousands):
Issued 40,000 - - -
Retired 35,000 - - -
- - - - - - - -------------------------------------------------------------------------------------------------------------------------
Security Ratings:
First Mortgage Bonds -
Moody's A1 A1 A1 A1
Standard and Poor's AA- AA- A+ A+
Preferred Stock -
Moody's "a2" "a2" "a2" "a2"
Standard and Poor's A A A A
- - - - - - - -------------------------------------------------------------------------------------------------------------------------
Customers (year-end):
Residential 110,437 109,092 106,657 104,624
Commercial 15,328 14,233 13,877 13,339
Industrial 63 64 65 65
Other 377 1,129 1,097 1,048
- - - - - - - -------------------------------------------------------------------------------------------------------------------------
Total 126,205 124,518 121,696 119,076
=========================================================================================================================
Employees (year-end) 542 535 571 584
II-211
SELECTED FINANCIAL AND OPERATING DATA (continued)
Savannah Electric and Power Company 1998 Annual Report
=============================================================================================================================
1994 1993 1992 1991
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands) $211,785 $218,442 $197,761 $189,646
Net Income after Dividends
on Preferred and Preference Stocks (in thousands) $22,110 $21,459 $20,512 $24,030
Cash Dividends on Common Stock (in thousands) $16,300 $21,000 $22,000 $22,000
Return on Average Common Equity (percent) 14.00 13.73 12.89 15.13
Total Assets (in thousands) $518,305 $527,187 $352,175 $352,505
Gross Property Additions (in thousands) $30,078 $72,858 $30,132 $19,478
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $161,581 $154,269 $158,376 $159,841
Preferred stock 35,000 35,000 20,000 20,000
Preferred and preference stock subject
to mandatory redemption - - - -
Trust preferred securities - - - -
Long-term debt 155,922 151,338 110,767 119,280
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $352,503 $340,607 $289,143 $299,121
=============================================================================================================================
Capitalization Ratios (percent):
Common stock equity 45.8 45.3 54.8 53.4
Preferred and preference stock 9.9 10.3 6.9 6.7
Trust preferred securities - - - -
Long-term debt 44.3 44.4 38.3 39.9
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0 100.0 100.0
=============================================================================================================================
First Mortgage Bonds (in thousands):
Issued - 45,000 30,000 30,000
Retired 5,065 - 38,750 22,500
Preferred Stock and Preferred Securities (in thousands):
Issued - 35,000 - -
Retired - 20,000 - -
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Security Ratings:
First Mortgage Bonds -
Moody's A1 A1 A1 A1
Standard and Poor's A A A A
Preferred Stock -
Moody's "a2" "a2" "a2" "a2"
Standard and Poor's A- A- A- A-
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Customers (year-end):
Residential 103,199 101,032 99,164 97,446
Commercial 13,015 12,702 12,416 12,153
Industrial 65 69 73 73
Other 1,007 957 940 897
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------
Total 117,286 114,760 112,593 110,569
=============================================================================================================================
Employees (year-end) 616 665 688 672
II-212A
SELECTED FINANCIAL AND OPERATING DATA (continued)
Savannah Electric and Power Company 1998 Annual Report
===============================================================================================================================
1990 1989 1988
- - - - - - - -------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands) $205,635 $201,799 $182,440
Net Income after Dividends
on Preferred and Preference Stocks (in thousands) $26,254 $25,535 $24,272
Cash Dividends on Common Stock (in thousands) $22,000 $20,000 $11,700
Return on Average Common Equity (percent) 16.85 16.88 17.03
Total Assets (in thousands) $340,050 $349,887 $347,051
Gross Property Additions (in thousands) $20,086 $18,831 $23,254
- - - - - - - -------------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $157,811 $153,737 $148,883
Preferred stock 20,000 22,300 22,300
Preferred and preference stock subject
to mandatory redemption - 2,884 3,075
Trust preferred securities - - -
Long-term debt 112,377 117,522 98,285
- - - - - - - -------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $290,188 $296,443 $272,543
===============================================================================================================================
Capitalization Ratios (percent):
Common stock equity 54.4 51.9 54.6
Preferred and preference stock 6.9 8.5 9.3
Trust preferred securities - - -
Long-term debt 38.7 39.6 36.1
- - - - - - - -------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0 100.0
===============================================================================================================================
First Mortgage Bonds (in thousands):
Issued - 30,000 -
Retired 9,135 18,275 12,231
Preferred Stock and Preferred Securities (in thousands):
Issued - - 20,000
Retired 5,374 6,591 553
- - - - - - - -------------------------------------------------------------------------------------------------------------------------------
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- BBB+
- - - - - - - -------------------------------------------------------------------------------------------------------------------------------
Customers (year-end):
Residential 96,452 94,766 93,486
Commercial 12,045 12,298 12,135
Industrial 76 69 69
Other 867 856 828
- - - - - - - -------------------------------------------------------------------------------------------------------------------------------
Total 109,440 107,989 106,518
===============================================================================================================================
Employees (year-end) 648 643 655
II-212B
SELECTED FINANCIAL AND OPERATING DATA (continued)
Savannah Electric and Power Company 1998 Annual Report
=================================================================================================================================
1998 1997 1996 1995
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $109,393 $96,587 $101,607 $95,208
Commercial 86,231 78,949 80,494 75,117
Industrial 37,865 35,301 37,077 36,040
Other 8,838 8,621 8,804 8,386
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------------
Total retail 242,327 219,458 227,982 214,751
Sales for resale - non-affiliates 4,548 3,467 1,998 1,851
Sales for resale - affiliates 3,016 2,052 3,130 7,200
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 249,891 224,977 233,110 223,802
Other revenues 4,564 1,300 964 1,927
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------------
Total $254,455 $226,277 $234,074 $225,729
=================================================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 1,539,792 1,428,337 1,456,651 1,402,148
Commercial 1,236,337 1,156,078 1,141,218 1,099,570
Industrial 900,012 881,261 838,753 887,141
Other 131,142 124,490 126,215 126,057
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------------
Total retail 3,807,283 3,590,166 3,562,837 3,514,916
Sales for resale - non-affiliates 53,294 94,280 91,610 87,747
Sales for resale - affiliates 58,415 54,509 41,808 63,731
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------------
Total 3,918,992 3,738,955 3,696,255 3,666,394
=================================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 7.10 6.76 6.98 6.79
Commercial 6.97 6.83 7.05 6.83
Industrial 4.21 4.01 4.42 4.06
Total retail 6.36 6.11 6.40 6.11
Sale for resale 6.77 3.71 3.84 5.98
Total sales 6.38 6.02 6.31 6.10
Residential Average Annual Kilowatt-Hour Use Per Customer 14,061 13,231 13,771 13,478
Residential Average Annual Revenue Per Customer $998.95 $894.73 $960.58 $915.15
Plant Nameplate Capacity Ratings (year-end) (megawatts) 788 788 788 788
Maximum Peak-Hour Demand (megawatts):
Winter 582 625 666 630
Summer 846 802 811 811
Annual Load Factor (percent) 54.9 54.3 53.1 52.9
Plant Availability - Fossil-Steam (percent) 72.9 93.7 77.6 83.3
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 41.6 34.4 27.7 23.9
Oil and gas 12.9 5.2 3.1 5.9
Purchased power -
From non-affiliates 3.4 1.4 2.1 2.3
From affiliates 42.1 59.0 67.1 67.9
- - - - - - - ---------------------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0 100.0
=================================================================================================================================
Total Fuel Economy Data:
BTU per net kilowatt-hour generated 11,730 11,495 11,888 12,146
Cost of fuel per million BTU (cents) 198.75 197.19 203.36 179.25
Average cost of fuel per net kilowatt-hour generated (cents) 2.33 2.27 2.42 2.18
=================================================================================================================================
II-213
SELECTED FINANCIAL AND OPERATING DATA (continued)
Savannah Electric and Power Company 1998 Annual Report
===================================================================================================================================
1994 1993 1992 1991
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $89,195 $93,883 $82,670 $80,541
Commercial 71,227 71,320 64,756 61,827
Industrial 32,906 36,180 33,171 30,492
Other 7,946 7,810 7,095 6,561
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------------
Total retail 201,274 209,193 187,692 179,421
Sales for resale - non-affiliates 4,786 6,021 7,821 7,813
Sales for resale - affiliates 6,446 2,433 1,505 1,430
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 212,506 217,647 197,018 188,664
Other revenues (721) 795 743 982
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------------
Total $211,785 $218,442 $197,761 $189,646
===================================================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 1,298,122 1,329,362 1,216,993 1,195,005
Commercial 1,045,831 1,015,935 953,840 925,757
Industrial 799,543 854,324 861,121 825,862
Other 119,593 115,969 110,270 106,683
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------------
Total retail 3,263,089 3,315,590 3,142,224 3,053,307
Sales for resale - non-affiliates 201,716 247,203 367,066 372,085
Sales for resale - affiliates 93,001 75,384 37,632 32,581
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------------
Total 3,557,806 3,638,177 3,546,922 3,457,973
===================================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 6.87 7.06 6.79 6.74
Commercial 6.81 7.02 6.79 6.68
Industrial 4.12 4.23 3.85 3.69
Total retail 6.17 6.31 5.97 5.88
Sale for resale 3.81 2.62 2.30 2.28
Total sales 5.97 5.98 5.55 5.46
Residential Average Annual Kilowatt-Hour Use Per Customer 12,686 13,269 12,369 12,323
Residential Average Annual Revenue Per Customer $871.68 $937.07 $840.23 $830.54
Plant Nameplate Capacity Ratings (year-end) (megawatts) 788 628 628 605
Maximum Peak-Hour Demand (megawatts):
Winter 617 524 533 526
Summer 729 747 695 691
Annual Load Factor (percent) 54.3 54.1 55.0 54.1
Plant Availability - Fossil-Steam (percent) 81.0 90.2 89.1 76.9
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 18.6 21.5 12.0 16.3
Oil and gas 1.8 4.5 2.9 1.7
Purchased power -
From non-affiliates 1.5 0.9 1.0 0.4
From affiliates 78.1 73.1 84.1 81.6
- - - - - - - -----------------------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0 100.0
===================================================================================================================================
Total Fuel Economy Data:
BTU per net kilowatt-hour generated 11,786 11,515 12,547 10,917
Cost of fuel per million BTU (cents) 205.03 215.97 201.50 199.42
Average cost of fuel per net kilowatt-hour generated (cents) 2.42 2.49 2.53 2.18
===================================================================================================================================
II-214A
SELECTED FINANCIAL AND OPERATING DATA (continued)
Savannah Electric and Power Company 1998 Annual Report
==================================================================================================================
1990 1989 1988
- - - - - - - -------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $87,063 $85,113 $81,098
Commercial 65,462 65,474 62,640
Industrial 30,237 28,304 26,865
Other 6,782 6,892 6,557
- - - - - - - -------------------------------------------------------------------------------------------------------------------
Total retail 189,544 185,783 177,160
Sales for resale - non-affiliates 9,482 8,814 808
Sales for resale - affiliates 5,566 6,025 3,567
- - - - - - - -------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 204,592 200,622 181,535
Other revenues 1,043 1,177 905
- - - - - - - -------------------------------------------------------------------------------------------------------------------
Total $205,635 $201,799 $182,440
===================================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 1,183,486 1,109,976 1,067,411
Commercial 892,931 839,756 806,687
Industrial 644,704 561,063 533,604
Other 103,539 101,164 97,072
- - - - - - - -------------------------------------------------------------------------------------------------------------------
Total retail 2,824,660 2,611,959 2,504,774
Sales for resale - non-affiliates 441,090 437,943 24,168
Sales for resale - affiliates 294,042 303,142 156,106
- - - - - - - -------------------------------------------------------------------------------------------------------------------
Total 3,559,792 3,353,044 2,685,048
===================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 7.36 7.67 7.60
Commercial 7.33 7.80 7.77
Industrial 4.69 5.04 5.03
Total retail 6.71 7.11 7.07
Sale for resale 2.05 2.00 2.43
Total sales 5.75 5.98 6.76
Residential Average Annual Kilowatt-Hour Use Per Customer 12,339 11,781 11,489
Residential Average Annual Revenue Per Customer $907.68 $903.37 $872.87
Plant Nameplate Capacity Ratings (year-end) (megawatts) 605 605 605
Maximum Peak-Hour Demand (megawatts):
Winter 428 548 471
Summer 648 613 574
Annual Load Factor (percent) 53.2 52.4 53.4
Plant Availability - Fossil-Steam (percent) 89.6 94.7 77.1
- - - - - - - -------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 52.8 63.5 79.8
Oil and gas 3.4 1.4 5.4
Purchased power -
From non-affiliates 0.8 1.5 5.9
From affiliates 43.0 33.6 8.9
- - - - - - - -------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0
===================================================================================================================
Total Fuel Economy Data:
BTU per net kilowatt-hour generated 10,741 10,611 10,683
Cost of fuel per million BTU (cents) 188.18 180.48 178.31
Average cost of fuel per net kilowatt-hour generated (cents) 2.02 1.92 1.90
===================================================================================================================
II-214B
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 1999
annual meeting of stockholders. The ages of directors and executive officers in
Item 10 set forth below are as of December 31, 1998.
Item 10. DIRECTORS AND EXECUTIVE
OFFICERS OF THE REGISTRANTS
ALABAMA
Identification of directors of ALABAMA.
Elmer B. Harris (1)
President and Chief Executive Officer
Age 59
Served as Director since 3-1-89
Whit Armstrong (2)
Age 51
Served as Director since 9-24-82
David J. Cooper, Sr. (2)
Age 53
Served as Director since 4-24-98
A. W. Dahlberg (2)
Age 58
Served as Director since 4-22-94
Peter V. Gregerson, Sr. (2)
Age 70
Served as Director since 10-22-93
Carl E. Jones, Jr. (2)
Age 58
Served as Director since 4-22-88
Patricia M. King (2)
Age 53
Served as Director since 7-25-97
James K. Lowder (2)
Age 49
Served as Director since 7-25-97
Wallace D. Malone, Jr. (2)
Age 62
Served as Director since 6-22-90
Thomas C. Meredith (2)
Age 57
Served as Director since 10-23-98
William V. Muse (2)
Age 59
Served as Director since 2-26-93
John T. Porter (2)
Age 67
Served as Director since 10-22-93
Robert D. Powers (2)
Age 48
Served as Director since 1-24-92
Andreas Renschler (2)
Age 40
Served as Director since 1-23-98
C. Dowd Ritter (2)
Age 51
Served as Director since 7-25-97
William J. Rushton, III (2)
Age 69
Served as Director since 9-18-70
James H. Sanford (2)
Age 54
Served as Director since 8-1-83
John C. Webb, IV (2)
Age 56
Served as Director since 4-22-77
(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 24, 1998) for one
year until the next annual meeting or until a successor is elected and
qualified, except for Dr. Meredith, who was elected on the date indicated.
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.
Identification of executive officers of ALABAMA.
Elmer B. Harris (1)
President, Chief Executive Officer and Director
Age 59
Served as Executive Officer since 3-1-89
Banks H. Farris
Executive Vice President
Age 63
Served as Executive Officer since 12-3-91
Michael D. Garrett
Executive Vice President - External Affairs
Age 49
Served as Executive Officer since 3-1-98
William B. Hutchins, III
Executive Vice President, Chief Financial Officer
and Treasurer
Age 55
Served as Executive Officer since 12-3-91
Earl B. Parsons, Jr.
Senior Vice President
Age 60
Served as Executive Officer since 6-1-98
(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 24, 1998) for
one year until the next annual meeting or until his successor is elected and
qualified, except for Mr. Parsons, who was elected 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
ALABAMA acting solely in their capacities as such.
Identification of certain significant employees.
None.
Family relationships.
None.
Business experience.
Elmer B. Harris - President and Chief Executive Officer since 1989. Director
of SOUTHERN and AmSouth Bancorporation.
Whit Armstrong - President, Chairman of the Board and Director of The Citizens
Bank, Enterprise, Alabama. Also, President, Chairman of the Board and Director
of Enterprise Capital Corporation, Inc. Director of The Enstar Group, Inc.
David J. Cooper, Sr. - President of Cooper/T. Smith Corporation, a maritime
company with a core business of stevedoring and tugboats.
Director of Cooper/T. Smith Corporation and subsidiaries. Chairman of the
Board, American Equity Underwriters, Inc., Mobile, Alabama.
A. W. Dahlberg - Chairman, President and Chief Executive Officer of SOUTHERN
since 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, Equifax, Inc., Protective Life Corporation and
SunTrust Banks, Inc.
Peter V. Gregerson, Sr. - Chairman Emeritus of Gregerson's Foods, Inc. (retail
groceries), Gadsden, Alabama.
Carl E. Jones, Jr. - President and Chief Executive Officer of Regions Financial
Corporation, Birmingham, Alabama.
Patricia M. King - President and Chief Executive Officer of King Motor Co.,
Inc., King's Highway, Inc. and King Imports, Inc.,
Anniston, Alabama. Director of Regions Bank, Anniston, Alabama.
James K. Lowder - President and Chief Executive Officer of The Colonial Company
(real estate development and sales), Montgomery, Alabama.
III-2
Wallace D. Malone, Jr. - Chairman and Chief Executive Officer of SouthTrust
Corporation, bank holding company, Birmingham, Alabama. Director of American
Cast Iron Pipe Company, Birmingham, Alabama.
Thomas C. Meredith - Chancellor of The University of Alabama System,
Tuscaloosa, Alabama. Director of ATMOS Energy Corporation, Dallas, Texas.
William V. Muse - President of Auburn University, Auburn, Alabama. Director of
SouthTrust Bank and American Cast Iron Pipe Company, Birmingham, Alabama.
John T. Porter - Pastor of Sixth Avenue Baptist Church, Birmingham, Alabama.
Director of Citizens Federal Savings Bank, Birmingham, Alabama.
Robert D. Powers - President and Director, The Eufaula Agency, Inc. (real
estate and insurance), Eufaula, Alabama.
Andreas Renschler - President and Chief Executive Officer of Mercedes-Benz U.S.
International, Inc., Tuscaloosa County, Alabama.
C. Dowd Ritter - Chairman, President, Chief Executive Officer and Director,
AmSouth Bancorporation and AmSouth Bank, Birmingham, Alabama.
William J. Rushton, III - Chairman Emeritus of Protective Life Corporation
(insurance holding company), Birmingham, Alabama. Director of SOUTHERN.
James H. Sanford - Chairman, HOME Place Farms Inc. (diversified farmers and
ginners), Prattville, Alabama. President, Autauga Quality Cotton Association.
Chairman of the Board, Sylvest Farms of Georgia, Inc., College Park, Georgia.
Chairman of the Board, Sylvest Poultry Inc., Montgomery, Alabama.
John C. Webb, IV - President, Webb Lumber Company, Inc. (wholesale lumber and
wood products sales), Demopolis, Alabama. Director of J. F. Suttle, Co.
Banks H. Farris - Executive Vice President - Customer Service since 1994.
Responsible for providing the overall management of human resources, information
resources, power delivery and marketing departments, customer service centers
and the six geographic divisions. He previously served as Senior Vice President
from 1991 to 1994.
Michael D. Garrett - Executive Vice President - External Affairs since 1998.
Responsible for governmental relations, environmental, public relations,
economic development, corporate real estate and corporate services. He
previously served as Senior Vice President - External Affairs from February 1994
to March 1998. Director of AmSouth Bank, Birmingham, Alabama.
William B. Hutchins, III - Executive Vice President, and Chief Financial Officer
since 1991. Treasurer was added to his responsibilities in 1998. Responsible for
financial and accounting operations, corporate planning and treasury operations.
He previously served as Senior Vice President and Chief Financial Officer from
1991 to 1994.
Earl B. Parsons, Jr. - Senior Vice president - Fossil and Hydro Generation
since 1995. Responsible for providing the overall management of the Fossil
Generation, Hydro Generation, Power Generation Support and Fuels Department.
He previously served as Vice President of Power Generation and Transmission at
GULF.
Involvement in certain legal proceedings.
None.
III-3
GEORGIA
Identification of directors of GEORGIA.
H. Allen Franklin
President and Chief Executive Officer
Age 54
Served as Director since 1-1-94
Warren Y. Jobe
Executive Vice President
Age 58
Served as Director since 8-1-82
Daniel P. Amos (1)
Age 47
Served as Director since 5-21-97
Juanita P. Baranco (1)
Age 49
Served as Director since 5-21-97
A. W. Dahlberg (1)
Age 58
Served as Director since 6-1-88
William A. Fickling, Jr. (1)
Age 66
Served as Director since 4-18-73
L. G. Hardman III (1)
Age 59
Served as Director since 6-25-79
James R. Lientz, Jr. (1)
Age 55
Served as Director since 7-21-93
Zell Miller (1)
Age 67
Served as Director since 2-17-99
G. Joseph Prendergast (1)
Age 53
Served as Director since 1-20-93
Herman J. Russell (1)
Age 68
Served as Director since 5-18-88
Gloria M. Shatto (1)
Age 67
Served as Director since 2-20-80
William Jerry Vereen (1)
Age 58
Served as Director since 5-18-88
Carl Ware (1) (2)
Age 55
Served as Director since 2-15-95
(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 20, 1998) for one
year until the next annual meeting or until a successor is elected and
qualified, except for Mr. Miller, who was elected 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.
Identification of executive officers of GEORGIA.
H. Allen Franklin
President, Chief Executive Officer and Director
Age 54
Served as Executive Officer since 1-1-94
Warren Y. Jobe
Executive Vice President and Director
Age 58
Served as Executive Officer since 5-19-82
William C. Archer, III
Executive Vice President - External Affairs
Age 50
Served as Executive Officer since 4-6-95
III-4
Gene R. Hodges
Executive Vice President - Customer Operations
Age 60
Served as Executive Officer since 11-19-86
David M. Ratcliffe
Executive Vice President, Treasurer and
Chief Financial Officer
Age 50
Served as Executive Officer since 3-1-98
Wayne T. Dahlke
Senior Vice President - Power Delivery
Age 57
Served as Executive Officer since 4-19-89
James K. Davis
Senior Vice President - Corporate Relations
Age 58
Served as Executive Officer since 10-1-93
Robert H. Haubein
Senior Vice President - Fossil/Hydro Power
Age 58
Served as Executive Officer since 2-19-92
Leonard J. Haynes
Senior Vice President - Marketing
Age 48
Served as Executive Office since 10-13-98
Fred R. Williams
Senior Vice President - Resource Policy & Planning
Age 54
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 20, 1998) for
one year until the next annual meeting or until his successor is elected and
qualified, except for Mr. Haynes, who was elected 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
GEORGIA acting solely in their capacities as such.
Identification of certain significant employees.
None.
Family relationships.
None.
Business experience.
H. Allen Franklin - President and Chief Executive Officer since 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 since 1982. He previously served as
Chief Financial Officer and Treasurer from 1982 to 1998. Effective February
1998, elected Senior Vice President of SOUTHERN with responsibilities for
corporate development, including customer relations and civic and community
affairs.
Daniel P. Amos - President and Chief Executive Officer, American Family Life
Assurance Company, Incorporated (AFLAC), Columbus, Georgia. Director, AFLAC
Incorporated (and subsidiaries), CIT Group and Greystone Capital Partners,
I.L.P.
Juanita P. Baranco - Business owner of Baranco Automotive Group. Director of
Federal Reserve Bank of Atlanta and John H. Harland Company, Decatur, Georgia.
A. W. Dahlberg - Chairman, President and Chief Executive Officer of SOUTHERN
since 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, Equifax, Inc., Protective Life Corporation and
SunTrust Banks, Inc.
William A. Fickling, Jr. - Chairman of the Board, Chief Executive Officer of
Beech Street Corporation (provider of managed care services) and President from
1995 to 1996. He previously served as Chairman of the Board and Chief Executive
Officer of Charter Medical Corporation (provider of psychiatric care).
L. G. Hardman III - Chairman of the Board and Chief Executive Officer of First
Commerce Bancorp, Inc. Chairman of the Board of The First National Bank of
Commerce, Georgia and Chairman of the Board, President and Treasurer of Harmony
Grove Mills, Inc. (real estate investments). Director of SOUTHERN.
III-5
James R. Lientz, Jr. - President, NationsBank, Mid-South Banking Group since
1993. He previously served as President and Chief Executive Officer of former
C&S of South Carolina (now NationsBank) from 1990 to 1993. Director of Cerulean
Companies, Inc. and Blue Cross/Blue Shield of Georgia.
Zell Miller - Former Governor of Georgia. He served two terms as Governor of the
State of Georgia, leaving office in January 1999. He previously served as
Lieutenant Governor of Georgia. Director of Albany-based Gray Communications,
Atlanta-based Post Properties, Atlanta-based Law Companies Group and United
Community Banks, Inc., Blairsville, GA.
G. Joseph Prendergast - Senior Executive Vice President, Wachovia Corporation.
Heads the banking division comprising the companies' consumer and corporate
banking activities and Wachovia Bank, N.A.
Herman J. Russell - Chairman and Chief Executive Officer of H. J. Russell &
Company (construction), Atlanta, Georgia. Chairman of
the Board, Citizens Trust Bank, Atlanta, Georgia. Director of Wachovia
Corporation and First Union Real Estate and Mortgage
Investments.
Gloria M. Shatto - President Emerita, Berry College, Mount Berry, Georgia.
Director of SOUTHERN, Becton Dickinson & Company and Texas Instruments
Incorporated.
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
Corporation, Cerulean Companies, Inc. and Blue Cross/Blue Shield of Georgia.
Carl Ware - President, Africa Group, The Coca-Cola Company since 1991.
William C. Archer, III - Executive Vice President - External Affairs since
September 1995. Senior Vice President - External Affairs from April 1995 to
September 1995. Vice President - Human Resources for SCS from 1992 to 1995.
Responsible for governmental and regulatory affairs, corporate relations, land
department, environmental affairs, corporate communications, risk management,
corporate security, regulatory and litigation support and corporate concerns.
Gene R. Hodges - Executive Vice President - Customer Operations, Power Delivery
and Safety since 2-19-92. Elected Vice President in charge of customer service
and power delivery in 1992. Safety department was added to the Executive Vice
President's responsibilities in 1995. Responsible for the northern and southern
regions and power delivery, customer service, region safety and labor relations
areas.
David M. Ratcliffe - Executive Vice President and Treasurer since 3-1-98 and
Executive Vice President, Treasurer and Chief Financial Officer since 5-20-98.
He previously served as Senior Vice President - External Affairs of SOUTHERN
from 1995 to 1998. President and Chief Executive Officer of MISSISSIPPI from
1991 to 1995. Responsible for accounting, corporate secretary, finance and
procurement.
Wayne T. Dahlke - Senior Vice President - Power Delivery since 1992. Senior Vice
President - Marketing from 1989 to 1992. Responsible for transmission and
construction, planning and projects, distribution, forestry and right of way
services and system operations.
James K. Davis - Senior Vice President - Corporate Relations since 1993. Vice
President of Corporate Relations from 1988 to 1993. Responsible for corporate
relations and consumer affairs.
Robert H. Haubein - Senior Vice President - Fossil/ Hydro Power since 1994.
Senior Vice President - Administrative Services from 1992 to 1994. Responsible
for fossil/hydro power generation, labor relations, safety and health.
Leonard J. Haynes - Senior Vice President - Marketing since 1998. Vice President
of Marketing from October 1995 to November 1998. Responsible for GEORGIA's and
SAVANNAH's Power Marketing organizations as well as SOUTHERN's national accounts
organization.
Fred R. Williams - Senior Vice President - Resource Policy and Planning since
1997. Senior Vice President - Wholesale Power Marketing from 1995 to 1997.
Senior Vice President - Bulk Power Markets from 1992 to August 1995. Responsible
for managing the supply needs for retail and wholesale customers and developing
policy and recommendations for future industry structure.
Involvement in certain legal proceedings.
None.
III-6
GULF
Identification of directors of GULF.
Travis J. Bowden
President and Chief Executive Officer
Age 60
Served as Director since 2-1-94
Paul J. DeNicola (1)
Age 50
Served as Director since 4-19-91
Fred C. Donovan, Sr. (1)
Age 58
Served as Director since 1-18-91
W. Deck Hull, Jr. (1)
Age 66
Served as Director since 10-14-83
Joseph K. Tannehill (1)
Age 65
Served as Director since 7-19-85
Barbara H. Thames (1)
Age 58
Served as Director since 2-28-97
(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 30, 1998) 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.
Identification of executive officers of GULF.
Travis J. Bowden
President, Chief Executive Officer and Director
Age 60
Served as Executive Officer since 2-1-94
Francis M. Fisher, Jr.
Vice President - Power Delivery and Customer Operations
Age 50
Served as Executive Officer since 5-19-89
John E. Hodges, Jr.
Vice President - Marketing and Employee/External Affairs
Age 55
Served as Executive Officer since 5-19-89
Robert G. Moore
Vice President - Power Generation and Transmission
Age 49
Served as Executive Officer since 7-25-97
Arlan E. Scarbrough
Vice President - Finance
Age 62
Served as Executive Officer since 9-21-77
Each of the above is currently an executive officer of GULF, serving a term
running from the last annual meeting of the directors (July 24, 1998) 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
GULF acting solely in their capacities as such.
Identification of certain significant employees.
None.
Family relationships.
None.
Business experience.
Travis J. Bowden - President and Chief Executive Officer since 1994. He
previously served as Executive Vice President of ALABAMA from 1985 to 1994.
III-7
Paul J. DeNicola - President and Chief Executive Officer of SCS since 1994.
Executive Vice President and Group Executive of SOUTHERN since 1991. He
previously served as Executive Vice President of SCS from 1991 through 1993.
Director of SOUTHERN, MISSISSIPPI and SAVANNAH.
Fred C. Donovan, Sr. - President of Baskerville - Donovan, Inc., an
architectural and engineering firm, Pensacola, Florida.
W. Deck Hull, Jr. - President and Director of Hull Company - Panama City,
Florida. He previously served as Vice Chairman of the
SunTrust Bank, West Florida, Panama City, Florida.
Joseph K. Tannehill - President, Chairman and Chief Executive Officer of
Tannehill International Industries, Inc., Lynn Haven,
Florida. Director of Regions Bank of North Florida, Panama City, Florida.
Barbara H. Thames - Vice President of West Florida Regional Medical Center,
Pensacola, Florida. She previously served as Chief
Executive Officer of Santa Rosa Medical Center, Milton, Florida.
Francis M. Fisher, Jr. - Vice President - Power Delivery and Customer
Operations since 1996. He previously served as Vice
President-Employee and External Relations from 1989 to 1996. Responsible for
power delivery, customer operations, corporate real
estate, and total quality management and serves as compliance officer.
John E. Hodges, Jr. - Vice President - Marketing and Employee/External Affairs
since 1996. He previously served as Vice President - Customer Operations from
1989 to 1996. Responsible for corporate communications, marketing, govermental
affairs, economic development, safety and health, employee relations and human
resources-coastal region.
Robert G. Moore - Vice President - Power Generation and Transmission of GULF and
Vice President of Fossil Generation of SCS since 1997. He previously served as
Plant Manager - Bowen at GEORGIA. Responsible for the generation and
transmission of electricity and bulk power maketing efforts.
Arlan E. Scarbrough - Vice President - Finance since 1980. Responsible for all
accounting, financial and regulatory matters.
Involvement in certain legal proceedings.
None.
III-8
MISSISSIPPI
Identification of directors of MISSISSIPPI.
Dwight H. Evans
President and Chief Executive Officer
Age 50
Served as Director since 3-27-95
Paul J. DeNicola (1)
Age 50
Served as Director since 5-1-89
Edwin E. Downer (1)
Age 67
Served as Director since 4-24-84
Robert S. Gaddis (1)
Age 67
Served as Director since 1-21-86
Aubrey K. Lucas (1)
Age 64
Served as Director since 4-24-84
George A. Schloegel (1)
Age 58
Served as Director since 7-26-95
Philip J. Terrell (1)
Age 45
Served as Director since 2-22-95
N. Eugene Warr (1)
Age 63
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 7,
1998) 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 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. Identification of executive officers of MISSISSIPPI.
Dwight H. Evans
President, Chief Executive Officer and Director
Age 50
Served as Executive Officer since 3-27-95
H. E. Blakeslee
Vice President - Customer Services and Marketing
Age 58
Served as Executive Officer since 1-25-84
Andrew J. Dearman, III
Vice President - Power Generation and Delivery
Age 45
Served as Executive Officer since 4-23-97
Don E. Mason
Vice President - External Affairs and Corporate Services
Age 57
Served as Executive Officer since 7-27-83
Michael W. Southern
Vice President, Secretary, Treasurer and
Chief Financial Officer
Age 46
Served as Executive Officer since 1-1-95
Each of the above is currently an executive officer of MISSISSIPPI, serving
a term running from the last annual meeting of the directors (May 7, 1998) for
one year until the next annual meeting or until his successor is elected and
qualified.
There are no arrangements or understandings between any of the individuals
listed above and any other person pursuant to which he was or is to be selected
as an officer, other than any arrangements or understandings with officers of
MISSISSIPPI acting solely in their capacities as such.
Identification of certain significant employees.
None.
Family relationships.
None.
III-9
Business experience.
Dwight H. Evans - President and Chief Executive Officer since 1995. He
previously served as Executive Vice President - External Affairs of GEORGIA from
1989 to 1995.
Paul J. DeNicola - President and Chief Executive Officer of SCS effective 1994.
Executive Vice President and Group Executive of SOUTHERN since 1991. Executive
Vice President of SCS from 1991 through 1993. Director of SOUTHERN, SAVANNAH and
GULF.
Edwin E. Downer - Business consultant specializing in economic analysis,
management controls and procedural studies, Meridian, Mississippi.
Robert S. Gaddis - Chairman of the Advisory Board of Trustmark National Bank,
Laurel, Mississippi.
Aubrey K. Lucas - President Emeritus and Distinguished Professor of Higher
Education at the University of Southern Mississippi, Hattiesburg, Mississippi.
George A. Schloegel - President of Hancock Bank. President, Chief Executive
Officer and Director of Hancock Bank Securities
Corporation. Vice Chairman of Hancock Holding Company. Director of Hancock
Bank - Mississippi and Hancock Bank - Louisiana.
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). Director of
Coast Community Bank, formerly SouthTrust Bank of Mississippi, Biloxi,
Mississippi.
H. E. Blakeslee - Vice President - Customer Services and Marketing since 1984.
Responsible for rate design, revenue forecasting, marketing, district
operations, corporate compliance, distribution engineering, customer accounting,
vehicle maintenance centers and customer call center.
Andrew J. Dearman, III - Vice President - Power Generation and Delivery since
1997. Responsible for generating plants, environmental quality, fuel services,
power generation technical services, transmission, system planning, bulk power
contracts, system operations and control, system protection and real estate. He
served as Vice President - Southern Division of ALABAMA from 1995 to May 1997,
and Division Manager - Customer Service of ALABAMA from 1989 to 1995.
Don E. Mason - Vice President- External Affairs and Corporate Services since
1983. Responsible for external affairs, corporate communications, security, risk
management, economic development and general services, as well as the human
resources function.
Michael W. Southern - Vice President, Secretary, Treasurer and Chief Financial
Officer since 1995. Responsible for accounting, secretary/treasury, corporate
planning, procurement and information resources. 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.
Involvement in certain legal proceedings.
None.
III-10
SAVANNAH
Identification of directors of SAVANNAH.
G. Edison Holland, Jr.
President and Chief Executive Officer
Age 46
Served as Director since 7-15-97
Archie H. Davis (1)
Age 57
Served as Director since 2-18-97
Paul J. DeNicola (1)
Age 50
Served as Director since 3-14-91
Walter D. Gnann (1)
Age 63
Served as Director since 5-17-83
Robert B. Miller, III (1)
Age 53
Served as Director since 5-17-83
Arnold M. Tenenbaum (1)
Age 62
Served as Director since 5-17-77
(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 19, 1998)
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.
Identification of executive officers of SAVANNAH.
G. Edison Holland, Jr.
President, Chief Executive Officer and Director
Age 46
Served as Executive Officer since 7-15-97
W. Miles Greer
Vice President - Customer Operations, Marketing and External Affairs
Age 55
Served as Executive Officer since 11-20-85
Kirby R. Willis
Vice President, Treasurer, Chief Financial Officer
and Assistant Corporate Secretary
Age 47
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 meeting of the directors held on July 21, 1998 for the
ensuing year.
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.
Identification of certain significant employees.
None.
Family relationships.
None.
Business experience.
G. Edison Holland, Jr. - Elected President and Chief Executive Officer in 1997.
Vice President - Power Generation/Transmission and Corporate Counsel of GULF
from 1995 to 1997. Served as a partner in the law firm of Beggs & Lane from 1979
to 1997. Director of SunTrust Bank of Savannah.
Archie H. Davis - President and Chief Executive Officer of The Savannah Bancorp
and The Savannah Bank, N.A., Savannah, Georgia. Member of the Board of
Directors of Thomaston Mills, Thomaston, Georgia. Director of Bryan Bank &
Trust.
III-11
Paul J. DeNicola - President and Chief Executive Officer of SCS since 1994.
Executive Vice President and Group Executive of SOUTHERN since 1991. Executive
Vice President of SCS from 1991 through 1993. Director of SOUTHERN, GULF and
MISSISSIPPI.
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 Building Systems, Inc., Savannah,
Georgia.
Arnold M. Tenenbaum - President and Director of Chatham Steel Corporation.
Director of First Union Bank of Georgia, First Union
Bank of Savannah, Cerulean Corporation and Blue Cross/Blue Shield of Georgia.
W. Miles Greer - Vice President - Customer Operations, Marketing and External
Affairs since 1998. Responsible for marketing, customer services, transmission
and distribution, engineering, system operation and external affairs. He
previously served as Vice President of Marketing and Customer Service from 1994
to 1998.
Kirby R. Willis - Vice President, Treasurer and Chief Financial Officer since
1994 and Assistant Corporate Secretary effective 1998. Responsible primarily for
all accounting, financial, information resources, labor relations, corporate
services, environmental and safety activities. He previously served as
Treasurer, Controller and Assistant Secretary from 1991 to 1993.
Involvement in certain legal proceedings.
None
Section 16(a) Beneficial Ownership Reporting Compliance.
GEORGIA's Mr. Franklin filed one late report with the SEC representing one
transaction in SOUTHERN common stock.
III-12
Item 11. EXECUTIVE COMPENSATION
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 $100,000 during
1998 for each of the operating affiliates (ALABAMA, GEORGIA, GULF, MISSISSIPPI
and SAVANNAH).
Key terms used in this Item will have the following meanings:-
AME.........................Above-market earnings on deferred compensation
ESP.........................Employee Savings Plan
ESOP........................Employee Stock Ownership Plan
SBP.........................Supplemental Benefit Plan
ERISA.......................Employee Retirement Income Security Act
ALABAMA
SUMMARY COMPENSATION TABLE
ANNUAL COMPENSATION LONG-TERM COMPENSATION
Number of
Securities Long-
Name Underlying Term
and Other Annual Stock Incentive All Other
Principal Compensation Options Payouts Compensation
Position Year Salary($) Bonus($) ($)1 (Shares) ($)2 ($)3
- - - - - - - ------------------------------------------------------------------------------------------------------------------------
Elmer B. Harris
President,
Chief Executive 1998 545,102 192,751 19,060 29,411 249,971 30,180
Officer, 1997 500,700 101,002 20,453 35,648 247,224 30,172
Director 1996 480,310 72,697 7,112 31,608 439,508 25,068
Banks H. Farris 1998 275,822 32,631 8,530 11,473 178,829 14,764
Executive Vice 1997 247,170 37,500 7,218 13,513 155,313 14,379
President 1996 235,255 32,390 7,829 9,730 155,313 12,161
William B.
Hutchins, III
Executive Vice
President, 1998 237,532 34,646 3,010 8,118 132,472 12,678
Chief Financial 1997 217,756 31,400 1,383 9,834 115,170 12,441
Officer 1996 209,213 28,806 3,029 8,654 115,169 10,853
See next page for footnotes.
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
- - - - - - - -------------------------------------------------------------------------------------------------------------------------
Michael D. Garrett4 1998 221,731 25,966 12,389 7,800 105,866 11,558
Executive Vice 1997 - - - - - -
President 1996 - - - - - -
Earl B. Parsons, Jr.4 1998 213,075 26,758 7,285 7,282 114,911 11,249
Senior Vice President 1997 - - - - - -
1996 - - - - - -
1 Tax reimbursement by ALABAMA and certain personal benefits.
2 Payouts made in 1997, 1998 and 1999 for the four-year performance periods ending December 31, 1996, 1997 and 1998,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 $5,792 $1,046 $23,342
Banks H. Farris 7,200 1,046 6,518
William B. Hutchins, III 7,200 1,046 4,432
Michael D. Garrett 6,093 1,046 4,419
Earl B. Parsons, Jr. 7,200 1,046 3,003
4 Messrs. Garrett and Parsons, Jr. were named executive officers effective April 24, 1998.
III-14
GEORGIA
SUMMARY COMPENSATION TABLE
ANNUAL COMPENSATION LONG-TERM COMPENSATION
Number of
Securities Long-
Name Underlying Term
and Other Annual Stock Incentive All Other
Principal Compensation Options Payouts Compensation
Position Year Salary($) Bonus($) ($)1 (Shares) ($)2 ($)3
- - - - - - - -------------------------------------------------------------------------------------------------------------------------
H. Allen Franklin
President, 1998 564,329 237,502 7,078 30,521 283,629 31,590
Chief Executive 1997 511,505 129,426 14,219 36,544 280,513 31,350
Officer, Director 1996 482,658 73,260 10,992 31,853 498,688 27,334
David M. Ratcliffe
Executive
Vice President,
Treasurer, 1998 339,672 62,700 3,934 14,039 218,175 12,255
Chief Financial 1997 313,152 50,515 10,828 17,086 207,322 18,342
Officer 1996 347,985 39,465 8,446 15,179 207,322 16,889
Gene R. Hodges 1998 244,284 42,595 4,543 8,317 132,472 13,087
Executive 1997 228,336 39,058 5,544 10,271 126,075 13,111
Vice President 1996 221,708 26,209 1,783 9,214 126,075 12,193
Warren Y. Jobe
Executive 1998 249,314 37,434 7,804 10,275 132,472 12,660
Vice President, 1997 238,948 39,862 98,870 10,483 126,075 13,408
Director 1996 227,496 26,749 4,308 9,404 126,075 12,476
Robert H.
Haubein, Jr. 1998 239,448 35,683 1,922 8,175 132,472 13,007
Senior Vice 1997 220,358 35,683 657 9,952 115,170 11,981
President 1996 211,010 29,681 2,081 8,757 115,169 11,740
1 Tax reimbursement by GEORGIA on certain personal benefits including membership fees of $94,429 in 1997 for Mr. Jobe.
2 Payouts made in 1997, 1998 and 1999 for the four-year performance periods ending December 31, 1996,
1997 and 1998, 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 $7,200 $1,046 $23,344
David M. Ratcliffe 7,200 1,046 4,009
Gene R. Hodges 7,200 1,046 4,841
Warren Y. Jobe 6,450 1,046 5,164
Robert H. Haubein, Jr. 6,450 1,046 5,511
III-15
GULF
SUMMARY COMPENSATION TABLE
ANNUAL COMPENSATION LONG-TERM COMPENSATION
Number of
Securities Long-
Name Underlying Term
and Other Annual Stock Incentive All Other
Principal Compensation Options Payouts Compensation
Position Year Salary($) Bonus($) ($)1 (Shares) ($)2 ($)3
- - - - - - - -------------------------------------------------------------------------------------------------------------------------
Travis J. Bowden
President, 1998 329,280 35,121 3,839 13,583 218,175 18,068
Chief Executive 1997 306,584 33,933 2,842 16,694 207,322 17,888
Officer, Director 1996 297,685 29,950 1,560 14,975 207,322 14,950
Arlan E. Scarbrough 1998 196,661 18,071 3,253 6,721 96,594 10,218
Vice President 1997 180,642 18,212 1,440 8,142 84,048 10,235
1996 173,719 17,512 1,514 7,234 84,047 9,420
John E. Hodges, Jr. 1998 192,765 17,680 915 6,575 96,594 10,014
Vice President 1997 178,428 17,989 2,418 8,042 91,977 10,185
1996 171,688 17,297 1,415 7,145 91,977 9,405
Francis M. 1998 175,719 16,147 240 6,005 96,594 9,329
Fisher, Jr. 1997 160,783 16,274 479 7,275 84,048 9,182
Vice President 1996 151,236 15,352 459 5,674 84,047 8,177
Robert G. Moore4 1998 159,332 18,626 525 4,881 72,767 8,325
Vice President 1997 149,926 23,474 - 4,741 46,551 7,550
1996 - - - - - -
1 Tax reimbursement by GULF on certain personal benefits.
2 Payouts made in 1997, 1998 and 1999 for the four-year performance periods
ending December 31, 1996, 1997 and 1998, 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 $6,450 $1,046 $10,572
Arlan E. Scarbrough 6,448 1,046 2,724
John E. Hodges, Jr. 6,698 1,046 2,270
Francis M. Fisher, Jr. 7,200 1,046 1,083
Robert G. Moore 6,927 1,046 352
4 Mr. Moore was named an executive officer effective July 25, 1997.
III-16
MISSISSIPPI
SUMMARY COMPENSATION TABLE
ANNUAL COMPENSATION LONG-TERM COMPENSATION
Number of
Securities Long-
Name Underlying Term
and Other Annual Stock Incentive All Other
Principal Compensation Options Payouts Compensation
Position Year Salary($) Bonus($) ($)1 (Shares) ($)2 ($)3
- - - - - - - -------------------------------------------------------------------------------------------------------------------------
Dwight H. Evans
President, Chief 1998 283,195 42,603 5,051 11,693 218,175 15,291
Executive 1997 262,678 39,643 3,830 14,303 126,075 15,025
Officer, Director 1996 253,006 35,923 3,519 12,830 126,075 13,824
H. E. Blakeslee 1998 207,416 36,202 47 7,068 96,594 10,979
Vice President 1997 192,029 38,863 697 8,687 91,977 10,991
1996 190,429 25,664 224 7,572 91,977 9,885
Don E. Mason 1998 203,234 29,560 4,497 6,926 96,594 10,757
Vice President 1997 188,126 41,889 839 8,512 84,048 10,675
1996 186,670 25,148 125 7,420 84,047 9,587
Michael W. Southern
Vice President
Chief Financial 1998 174,334 34,130 - 5,997 83,087 8,978
Officer, Secretary, 1997 155,151 31,406 1,590 6,281 65,768 8,757
Treasurer 1996 155,027 20,740 2,841 5,475 65,768 7,865
Andrew J.
Dearman, III4 1998 159,713 41,031 600 4,893 83,087 8,343
Vice President 1997 141,393 21,008 2,083 5,871 42,903 21,354
1996 - - - - - -
1 Tax reimbursement by MISSISSIPPI on certain personal benefits.
2 Payouts made in 1997, 1998 and 1999 for the four-year performance periods ending
December 31, 1996, 1997 and 1998, 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
Dwight H. Evans $6,450 $1,046 $7,795
H. E. Blakeslee 6,093 1,046 3,840
Don E. Mason 5,992 1,046 3,719
Michael W. Southern 6,879 1,046 1,053
Andrew J. Dearman, III 6,936 1,046 361
In 1997, Mr. Dearman received a one-time lump-sum payment of
$13,591, given in connection with his appointment to his current position.
4 Mr. Dearman was named an executive officer effective April 23, 1997.
III-17
SAVANNAH
SUMMARY COMPENSATION TABLE
ANNUAL COMPENSATION LONG-TERM COMPENSATION
Number of
Securities Long-
Name Underlying Term
and Other Annual Stock Incentive All Other
Principal Compensation Options Payouts Compensation
Position Year Salary($) Bonus($) ($)1 (Shares) ($)2 ($)3
- - - - - - - -------------------------------------------------------------------------------------------------------------------------
G. Edison
Holland, Jr.4
President, 1998 233,330 26,019 17,309 7,951 128,608 8,246
Chief Executive 1997 202,413 26,231 3,046 8,640 91,977 49,892
Officer, Director 1996 184,359 18,584 2,969 7,677 91,977 9,940
W. Miles Greer 1998 160,207 16,054 13 4,901 69,000 13,179
Vice President 1997 138,643 16,294 805 4,924 60,636 10,740
1996 131,203 16,225 322 4,261 60,636 9,631
Kirby R. Willis
Vice President, 1998 155,236 15,554 13 4,748 69,000 10,581
Chief Financial 1997 134,794 15,915 182 4,809 60,636 9,322
Officer, Treasurer 1996 122,110 15,505 674 3,924 60,636 8,765
1 Tax reimbursement by SAVANNAH on certain personal benefits, including membership
fees of $11,669 for Mr. Holland, Jr. in 1998.
2 Payouts made in 1997, 1998 and 1999 for the four-year performance periods ending December 31, 1996, 1997 and
1998, 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
G. Edison Holland, Jr. $7,200 $1,046 $ -
W. Miles Greer 5,902 1,046 6,231
Kirby R. Willis 6,483 1,046 3,052
In 1997, Mr. Holland received a one-time lump-sum payment of $38,654, given in connection with his appointment to his current
position.
4 Mr. Holland became president on July 1, 1997. He was previously an executive officer at GULF.
III-18
STOCK OPTION GRANTS IN 1998
Stock Option Grants. The following table sets forth all stock option grants to
the named executive officers of each operating subsidiary during the year ending
December 31, 1998.
Individual Grants Grant Date Value
# of % of Total
Securities Options Exercise
Underlying Granted to or
Options Employees in Base Price Expiration Grant Date
Name Granted1 Fiscal Year2 ($/Sh)1 Date1 Present Value($)3
-----------------------------------------------------------------------------------------------------------
ALABAMA
Elmer B. Harris 29,411 1.8 27.03125 05/01/2007 167,349
Banks H. Farris 11,473 0.7 27.03125 06/01/2003 65,281
William B. Hutchins, III 8,118 0.5 27.03125 07/20/2008 46,191
Michael D. Garrett 7,800 0.5 27.03125 07/20/2008 44,382
Earl B. Parsons, Jr. 7,282 0.4 27.03125 06/01/2006 41,435
GEORGIA
H. Allen Franklin 30,521 1.8 27.03125 07/20/2008 173,664
David M. Ratcliffe 14,039 0.9 27.03125 07/20/2008 79,882
Gene R. Hodges 8,317 0.5 27.03125 04/01/2006 47,324
Warren Y. Jobe 10,275 0.6 27.03125 07/20/2008 58,465
Robert H. Haubein, Jr. 8,175 0.5 27.03125 02/01/2008 46,516
GULF
Travis J. Bowden 13,583 0.8 27.03125 09/01/2006 77,287
Arlan E. Scarbrough 6,721 0.4 27.03125 11/01/2004 38,242
John E. Hodges, Jr. 6,575 0.4 27.03125 07/20/2008 37,412
Francis M. Fisher, Jr. 6,005 0.4 27.03125 07/20/2008 34,168
Robert G. Moore 4,881 0.3 27.03125 07/20/2008 27,773
See next page for footnotes.
III-19
STOCK OPTION GRANTS IN 1998
Individual Grants Grant Date Value
# of % of Total
Securities Options Exercise
Underlying Granted to or
Options Employees in Base Price Expiration Grant Date
Name Granted1 Fiscal Year2 ($/Sh)1 Date1 Present Value($)3
------------------------------------------------------------------------------------------------------------
MISSISSIPPI
Dwight H. Evans 11,693 0.7 27.03125 07/20/2008 66,533
H. E. Blakeslee 7,068 0.4 27.03125 07/01/2008 40,217
Don E. Mason 6,926 0.4 27.03125 07/20/2008 39,409
Michael W. Southern 5,997 0.4 27.03125 07/20/2008 34,123
Andrew J. Dearman, III 4,893 0.3 27.03125 07/20/2008 27,841
SAVANNAH
G. Edison Holland, Jr. 7,951 0.5 27.03125 07/20/2008 45,241
W. Miles Greer 4,901 0.3 27.03125 07/20/2008 27,887
Kirby R. Willis 4,748 0.3 27.03125 07/20/2008 27,016
1 Performance Stock Plan grants were made on July 20, 1998, and vest 25% per
year on the anniversary date of the grant. Grants fully vest upon
termination incident to death, disability, or retirement. The exercise
price is the average of the high and low fair market value of SOUTHERN's common
stock on the date granted. In accordance with the terms of the Performance Stock
Plan, Mr. Blakeslee's unexercised options expire on July 1, 2008, three years
after his normal retirement date; Mr. Bowden's unexercised options expire on
September 1, 2006, three years after his normal retirement date; Mr. Farris'
unexercised options expire on June 1, 2003, three years after his normal
retirement date; Mr. Harris' unexercised options expire on May 1, 2007, three
years after his normal retirement date; Mr. Haubein, Jr.'s unexercised options
expire on February 1, 2008, three years after his normal retirement date; Mr.
Gene R. Hodges' unexercised options expire on April 1, 2006, three years after
his normal retirement date; Mr. Parsons Jr.'s unexercised options expire on June
1, 2006, three years after his normal retirement date; and Mr. Scarbrough's
unexercised options expire on November 1, 2004, three years after his normal
retirement date.
2 A total of 1,659,519 stock options were granted in 1998 to
key executives participating in SOUTHERN's Performance 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. There is no assurance that the value realized will be at or near the
value estimated by the Black-Scholes model. Significant assumptions used to
calculate this value: price volatility - 19.16%; risk-free rate of return -
5.46%; dividend opportunity - 50%; time to exercise - 10 years; reductions for
probability of forfeiture before vesting - 9.61%; and reductions for probability
of forfeiture before expiration - 15.51%. These assumptions reflect the effects
of cash dividend equivalents paid to participants under the Performance Dividend
Plan assuming targets are met.
III-20
AGGREGATED STOCK OPTION EXERCISES IN 1998 AND YEAR-END OPTION VALUES
Aggregated Stock Option Exercises. The following table sets forth information
concerning options exercised during the year ending December 31, 1998, by the
named executive officers and the value of unexercised options held by them as of
December 31, 1998.
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($)2 Unexercisable Unexercisable
- - - - - - - --------------------------------------------------------------------------------------------------------------
ALABAMA
Elmer B. Harris - - 183,510/79,994 1,929,365/424,248
Banks H. Farris 13,154 99,117 24,020/28,937 181,514/150,304
William B. Hutchins, III - - 32,521/22,034 279,966/116,806
Michael D. Garrett 13,165 77,775 2,019/19,246 15,773/98,358
Earl B. Parsons, Jr. 6,005 31,460 6,188/19,842 44,155/105,299
GEORGIA
H. Allen Franklin 3,560 56,404 149,760/81,846 1,480,720/432,104
David M. Ratcliffe - - 69,668/38,325 708,769/203,513
Gene R. Hodges 8,329 79,692 26,842/23,007 215,427/122,705
Warren Y. Jobe - - 39,645/25,268 358,857/128,865
Robert H. Haubein, Jr. 6,684 79,581 26,696/22,236 215,611/117,962
GULF
Travis J. Bowden 81,334 969,563 0/37,458 0/199,560
Arlan E. Scarbrough 11,200 82,590 0/18,295 0/97,050
John E. Hodges, Jr. 10,519 117,035 15,640/18,007 114,024/95,730
Francis M. Fisher, Jr. 8,857 78,155 0/15,700 0/82,450
Robert G. Moore - - 6,368/11,522 45,011/57,844
See next page for footnotes.
III-21
AGGREGATED STOCK OPTION EXERCISES IN 1998 AND YEAR-END OPTION VALUES
Number of
Securities Value of
Underlying Unexercised
Unexercised In-the-Money
Options at Options at
Fiscal Fiscal
Year-End (#) Year-End($)1
Shares Acquired Value Exercisable/ Exercisable/
Name on Exercise (#) Realized($)2 Unexercisable Unexercisable
- - - - - - - --------------------------------------------------------------------------------------------------------------
MISSISSIPPI
Dwight H. Evans 2,455 37,055 40,274/31,458 341,070/165,956
H. E. Blakeslee 5,284 60,270 21,932/19,270 175,814/102,347
Don E. Mason - - 11,421/18,882 80,640/100,284
Michael W. Southern - - 7,942/14,658 55,894/74,599
Andrew J. Dearman, III - - 6,737/12,448 47,781/64,906
SAVANNAH
G. Edison Holland, Jr. - - 30,209/20,233 261,280/104,649
W. Miles Greer - - 6,655/11,824 47,029/59,900
Kirby R. Willis - - 6,192/11,327 43,806/57,231
1 This represents the excess of the fair market
value of SOUTHERN's common stock of $29.0625 per share, as of December 31, 1998,
above the exercise price of the options. One column reports the "value" of
options that are vested and therefore could be exercised; the other the "value"
of options that are not vested and therefore could not be exercised as of
December 31, 1998.
2 The "Value Realized" is ordinary income, before taxes, and
represents the amount equal to the excess of the fair market value of the shares
at the time of exercise over the exercise price.
III-22
LONG-TERM INCENTIVE PLANS - AWARDS IN 1998
Long-Term Incentive Plans. The following table sets forth the long-term
incentive plan awards made to the named executive officers for the performance
period January 1, 1998 through December 31, 2001.
Estimated Future Payouts under
Non-Stock Price-Based Plans
Performance or
Other Period
Number of Until Maturation Threshold Target Maximum
Name Units (#)1 or Payout ($)2 ($)2 ($)2
- - - - - - - ----------------------------------------------------------------------------------------------------------------
ALABAMA
Elmer B. Harris 291,502 4 years 145,751 291,502 583,004
Banks H. Farris 120,832 4 years 60,416 120,832 241,664
William B. Hutchins, III 89,508 4 years 44,754 89,508 179,017
Michael D. Garrett 89,508 4 years 44,754 89,508 179,017
Earl B. Parsons, Jr. 89,508 4 years 44,754 89,508 179,017
GEORGIA
H. Allen Franklin 330,751 4 years 165,376 330,751 661,502
David M. Ratcliffe 147,416 4 years 73,708 147,416 294,832
Gene R. Hodges 89,508 4 years 44,754 89,508 179,017
Warren Y. Jobe 89,508 4 years 44,754 89,508 179,017
Robert H. Haubein, Jr. 89,508 4 years 44,754 89,508 179,017
GULF
Travis J. Bowden 147,416 4 years 73,708 147,416 294,832
Arlan E. Scarbrough 65,265 4 years 32,632 65,265 130,530
John E. Hodges, Jr. 65,265 4 years 32,632 65,265 130,530
Francis M. Fisher, Jr. 65,265 4 years 32,632 65,265 130,530
Robert G. Moore 65,265 4 years 32,632 65,265 130,530
See next page for footnotes.
III-23
LONG-TERM INCENTIVE PLANS - AWARDS IN 1998
Estimated Future Payouts under
Non-Stock Price-Based Plans
Performance or
Other Period
Number of Until Maturation Threshold Target Maximum
Name Units (#)1 or Payout ($)2 ($)2 ($)2
- - - - - - - ------------------------------------------------------------------------------------------------------------------
MISSISSIPPI
Dwight H. Evans 147,416 4 years 73,708 147,416 294,832
H. E. Blakeslee 65,265 4 years 32,632 65,265 130,530
Don E. Mason 65,265 4 years 32,632 65,265 130,530
Michael W. Southern 65,265 4 years 32,632 65,265 130,530
Andrew J. Dearman, III 65,265 4 years 32,632 65,265 130,530
SAVANNAH
G. Edison Holland, Jr. 107,637 4 years 53,819 107,637 215,274
W. Miles Greer 46,620 4 years 23,310 46,620 93,240
Kirby R. Willis 46,620 4 years 23,310 46,620 93,240
1 A performance unit is a method of assigning a dollar value to a performance
award opportunity. Under the Executive Productivity Improvement Plan,
Messrs. Harris and Franklin's number of units are based on the beginning of the
period base salary mid-points. All other executive officers listed in this
table are participants in the Productivity Improvement Plan of SOUTHERN,
the number of units granted to these named executive officers is based on the
weighted average of the base salary mid-points as of December 31 for each
calendar year in the four-year computation period. No awards are paid unless
the participant remains employed by the company through the end 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 and
total shareholder return relative to selected groups of electric and gas
utilities. If certain minimum performance relative to the selected groups 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. The Plan provides that in the discretion of the committee,
extraordinary income may be excluded for purposes of calculating the amount
available for the payment of awards. All awards are payable in cash at the end
of the performance period.
III-24
DEFINED BENEFIT OR ACTUARIAL PLAN DISCLOSURE
Pension Plan Table. The following table sets forth the estimated combined annual
pension benefits under the Pension, Supplemental Defined Benefit, and
Supplemental Executive Retirement Plans in effect during 1998 for the named
executives at ALABAMA, GEORGIA, GULF and MISSISSIPPI and Mr. Holland at
SAVANNAH. Employee compensation covered by the Pension, Supplemental Benefit,
and Supplemental Executive Retirement Plans for pension purposes is limited to
the average of the highest three of the final 10 years' compensation -- base
salary plus the excess of annual and long-term incentive compensation over 25
percent of base salary (reported under column titled "Salary", "Bonus", and
"Long-Term Incentive Payouts" 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 $3,900 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
$ 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
900,000 229,500 306,000 382,500 459,000 535,500 612,000
1,100,000 280,500 374,000 467,500 561,000 654,500 748,000
1,300,000 331,500 442,000 552,500 663,000 773,500 884,000
As of December 31, 1998, the applicable compensation levels and years
of accredited service are presented in the following tables:
ALABAMA
Compensation Accredited
Name Level Years of Service
Elmer B. Harris $844,132 39
Banks H. Farris 391,968 39
William B. Hutchins, III 319,544 32
Michael D. Garrett 268,316 30
Earl B. Parsons, Jr. 269,744 37
III-25
GEORGIA
Compensation Accredited
Name Level Years of Service
H. Allen Franklin $920,468 27
David M. Ratcliffe 506,316 27
Gene R. Hodges 342,084 34
Warren Y. Jobe1 343,808 34
Robert H. Haubein, Jr. 326,044 31
GULF
Compensation Accredited
Name Level Years of Service
Travis J. Bowden2 $481,924 32
Arlan E. Scarbrough 244,832 35
John E. Hodges, Jr. 248,136 32
Francis M. Fisher, Jr. 227,144 27
Robert G. Moore 183,044 25
MISSISSIPPI
Compensation Accredited
Name Level Years of Service
Dwight H. Evans $398,224 27
H. E. Blakeslee 274,248 33
Don E. Mason 264,564 32
Michael W. Southern 221,140 23
Andrew J. Dearman, III 185,060 23
SAVANNAH
Compensation Accredited
Name Level Years of Service
G. Edison Holland, Jr.3 $280,560 15
W. Miles Greer 143,858 14
Kirby R. Willis 137,972 24
- - - - - - - ---------------------------
1 The number of accredited years of service includes 7 years and 8 months
credited to Mr. Jobe pursuant to a supplemental pension agreement.
2 The number of accredited years of service includes 10 years credited to
Mr. Bowden pursuant to a supplemental pension agreement.
3 The number of accredited years of service includes 9 years and 3 months
credited to Mr. Holland pursuant to a supplemental pension agreement.
III-26
Effective January 1, 1998, SAVANNAH merged its pension plan into
SOUTHERN's Pension Plan. SAVANNAH also has in effect a supplemental executive
retirement plan for certain of its executive employees. The plan is designed to
provide participants with a supplemental retirement benefit, which, in
conjunction with social security and benefits under SOUTHERN's qualified
pension plan, will equal 70 percent of the highest three of the final 10 years'
average annual earnings (excluding incentive compensation).
The following table sets forth the estimated combined annual pension
benefits under SOUTHERN's pension and SAVANNAH's supplemental executive
retirement plans in effect during 1998 which are payable to SAVANNAH's named
executives, except Mr.Holland who participates in the plans described on
page III-25, upon retirement at the normal retirement age after designated
periods of accredited service and at a specified compensation level.
Years of Accredited Service
Remuneration 15 25 35
$ 90,000 $ 63,000 $ 63,000 $ 63,000
120,000 84,000 84,000 84,000
150,000 105,000 105,000 105,000
180,000 126,000 126,000 126,000
210,000 147,000 147,000 147,000
260,000 182,000 182,000 182,000
280,000 196,000 196,000 196,000
300,000 210,000 210,000 210,000
III-27
Compensation of Directors.
Standard Arrangements. The following table presents compensation paid
to the directors, during 1998 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 payable in cash may be deferred under
the Deferred Compensation Plan until membership on the board is terminated or
may be payable in SOUTHERN common stock at the election of the director.
ALABAMA GEORGIA GULF MISSISSIPPI SAVANNAH
Cash Retainer Fee $17,000 $20,000 $10,000 $10,000 $10,000
Stock Retainer Fee $3,000 $3,000 $2,000 $2,000 $2,000
Meeting Fee 900 900 750 750 750
Committees:
Audit 900 900 750 750 750
Compensation 900 900 750 750 750
Executive 900 900 - - 750
Finance - 900 - 750 -
Nominating 900 - - - -
Nuclear Safety 900 - - - -
Nuclear Operations
Overview - 1,800 - - -
Effective January 1, 1997, the Outside Directors Pension Plan (the
"Plan") was terminated and benefits payable under the Plan were frozen.
Non-employee directors serving as of January 1, 1997, were given a one-time
election to receive a Plan benefit buy-out equal to the actuarial present value
of future Plan benefits or receive benefits under the terms of the Plan at the
annual retainer rate in effect on December 31, 1996. Directors who elected to
receive the benefit buy-out were required to defer receipt of that amount under
the Deferred Compensation Plan until termination from board membership.
Directors who elected to continue to participate under the terms of the Plan are
entitled to benefits upon retirement from the board on the retirement date
designated in the respective companies' by-laws. The annual benefit payable is
based upon length of service and varies from 75 percent of the annual retainer
in effect on December 31, 1996, if the participant has at least 60 months of
service on the board of one or more system companies, to 100 percent if the
participant has at least 120 months of such service. Payments will continue for
the greater of the lifetime of the participant or 10 years.
Other Arrangements. No director received other compensation for
services as a director during the year ending December 31, 1998 in addition to
or in lieu of that specified by the standard arrangements specified above.
III-28
Employment Contracts and Termination of Employment and Change in Control
Arrangements.
Each registrant has adopted SOUTHERN's Change in Control Plan which is
applicable to certain of its officers, and has entered into individual change in
control agreements with its most highly compensated executive officers. If an
executive is involuntarily terminated, other than for cause, within two years
following a change in control of SOUTHERN the agreements provide for:
o lump sum payment of two or three times annual compensation,
o up to five years' coverage under group health and life insurance plans,
o immediate vesting of all stock options and stock appreciation rights
previously granted,
o payment of any accrued long-term and short-term bonuses and dividend
equivalents, and
o payment of any excise tax liability incurred as a result of payments made
under the agreement.
A change in control is defined under the agreements as:
o acquisition of at least 20 percent of the SOUTHERN's stock,
o a change in the majority of the members of the SOUTHERN's board of
directors,
o a merger or other business combination that results in SOUTHERN's
shareholders immediately before the merger owning less than 65 percent of
the voting power after the merger, or
o a sale of substantially all the assets of SOUTHERN.
If a change in control affects only a subsidiary of SOUTHERN, these
payments would only be made to executives of the affected subsidiary who are
involuntarily terminated as a result of that change in control.
SOUTHERN also has amended its short- and long-term incentive plans to
provide for pro-rata payments at not less than target-level performance if a
change in control occurs and the plans are not continued or replaced with
comparable plans.
On February 28, 1998, SOUTHERN and GEORGIA entered into a Deferred
Compensation Agreement with Mr. Franklin. On the fifth anniversary of the
Agreement, if Mr. Franklin is still employed by SOUTHERN or one of its
subsidiaries, he will receive the cash value of the number of shares of common
stock that could have been purchased for $500,000 on February 28, 1998, and on
which dividends were reinvested throughout the five-year period. If certain
performance goals are met, Mr. Franklin also will receive the estimated income
tax expense on the compensation. Mr. Franklin may elect to defer receipt of the
award until termination of employment.
SOUTHERN and GEORGIA entered into a Deferred Compensation
Agreement with Mr. Jobe. Mr. Jobe becomes eligible for benefits under the terms
of this Agreement if one of the following Eligibility Events occurs: (1) Mr.
Jobe terminates employment with SOUTHERN or one of its subsidiaries on or after
attaining age sixty-two and enters into a release as provided by the Agreement;
or (2) Mr. Jobe, after entering into this Agreement but while employed by
SOUTHERN or one of its subsidiaries, becomes totally and permanently disabled as
determined by a medical doctor selected by SOUTHERN and enters into a release as
provided by the Agreement. Upon the occurrence of an eligibility event as
detailed in item (1) above, SOUTHERN agrees to pay Mr. Jobe a lump sum amount
equal to two times base pay in effect at the time of the eligibility event; a
lump sum amount equal to the present value of the monthly Early Retirement
Reduction Percentage of Employee's Accrued Retirement Income under the pension
plan, plus an amount equal to the reduction of Mr. Jobe's monthly Supplemental
Employee Retirement Plan benefit; and consulting fees for services provided by
Mr. Jobe as an independent contractor. Upon the occurrence of an eligibility
event as detailed in item (2) above, SOUTHERN agrees to pay Mr. Jobe a lump sum
amount
III-29
Employment Contracts and Termination of Employment and Change in Control
Arrangements. (continued)
equal to two times base pay in effect at the time of the eligibility event; and
a lump sum amount equal to the present value of the monthly Early Retirement
Reduction Percentage of Employee's Accrued Retirement Income under the pension
plan, plus an amount equal to the reduction of Mr. Jobe's monthly Supplemental
Employee Retirement Plan benefit.
Report on Repricing of Options.
None.
Compensation Committee Interlocks and Insider Participation.
None.
III-30
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
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%
270 Peachtree Street, N.W.
Atlanta, Georgia 30303
Registrants:
ALABAMA 5,608,955
GEORGIA 7,761,500
GULF 992,717
MISSISSIPPI 1,121,000
SAVANNAH 10,844,635
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, 1998. 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, 1998.
Name of Directors,
Nominees and Number of Shares
Executive Officers Title of Class Beneficially Owned (1) (2)
ALABAMA
Whit Armstrong SOUTHERN Common 16,949
David J. Cooper, Sr. SOUTHERN Common 379
A. William Dahlberg SOUTHERN Common 355,291
Peter V. Gregerson, Sr. SOUTHERN Common 575
Elmer B. Harris SOUTHERN Common 222,887
Carl E. Jones, Jr. SOUTHERN Common 11,403
Patricia M. King SOUTHERN Common 177
James K. Lowder SOUTHERN Common 5,47
III-31
Name of Directors,
Nominees and Number of Shares
Executive Officers Title of Class Beneficially Owned (1)(2)
Thomas C. Meredith SOUTHERN Common 18
William V. Muse SOUTHERN Common 575
John T. Porter SOUTHERN Common 1,008
Robert D. Powers SOUTHERN Common 575
Andreas Renschler SOUTHERN Common 410
C. Dowd Ritter SOUTHERN Common 177
William J. Rushton, III SOUTHERN Common 8,148
James H. Sanford SOUTHERN Common 511
John C. Webb, IV SOUTHERN Common 19,572
Banks H. Farris SOUTHERN Common 28,112
Michael D. Garrett SOUTHERN Common 8,087
William B. Hutchins, III SOUTHERN Common 48,307
Earl B. Parsons Jr. SOUTHERN Common 10,895
The directors, nominees,
and executive officers
as a group SOUTHERN Common 728,635
GEORGIA
Daniel P. Amos SOUTHERN Common 168
Juanita P. Baranco SOUTHERN Common 168
A. William Dahlberg SOUTHERN Common 355,291
W. A. Fickling, Jr. SOUTHERN Common 1,069
III-32
Name of Directors,
Nominees and Number of Shares
Executive Officers Title of Class Beneficially Owned(1)(2)
H. Allen Franklin SOUTHERN Common 177,239
L. G. Hardman III SOUTHERN Common 16,062
Warren Y. Jobe SOUTHERN Common 70,034
GEORGIA Preferred 200
James R. Lientz, Jr. SOUTHERN Common 946
G. Joseph Prendergast SOUTHERN Common 961
Herman J. Russell SOUTHERN Common 10,710
Gloria M. Shatto SOUTHERN Common 18,830
GEORGIA Preferred 1,200
W. J. Vereen SOUTHERN Common 496
Carl Ware SOUTHERN Common 646
William C. Archer, III SOUTHERN Common 17,500
Robert H. Haubein, Jr. SOUTHERN Common 29,002
Gene R. Hodges SOUTHERN Common 43,245
David M. Ratcliffe SOUTHERN Common 79,206
The directors, nominees
and executive officers
as a group SOUTHERN Common 917,255
GEORGIA Preferred 1,650
III-33
Name of Directors,
Nominees and Number of Shares
Executive Officers Title of Class Beneficially Owned (1) (2)
GULF
Travis J. Bowden SOUTHERN Common 34,889
Paul J. DeNicola SOUTHERN Common 139,642
Fred C. Donovan, Sr. SOUTHERN Common 637
W. Deck Hull, Jr. SOUTHERN Common 2,549
Joseph K. Tannehill SOUTHERN Common 4,439
Barbara H. Thames SOUTHERN Common 160
Francis M. Fisher, Jr. SOUTHERN Common 6,604
John E. Hodges, Jr. SOUTHERN Common 37,925
Robert G. Moore SOUTHERN Common 20,729
Arlan E. Scarbrough SOUTHERN Common 20,039
The directors, nominees
and executive officers
as a group SOUTHERN Common 267,502
MISSISSIPPI
Paul J. DeNicola SOUTHERN Common 139,642
Edwin E. Downer SOUTHERN Common 5,365
Dwight H. Evans SOUTHERN Common 62,158
GEORGIA Preferred 400
MISSISSIPPI Preferred 200
SOUTHERN Preferred 200
Robert S. Gaddis SOUTHERN Common 3,183
III-34
Name of Directors,
Nominees and Number of Shares
Executive Officers Title of Class Beneficially Owned (1) (2)
Aubrey K. Lucas SOUTHERN Common 1,940
George A. Schloegel SOUTHERN Common 485
Philip J. Terrell SOUTHERN Common 1,103
N. Eugene Warr SOUTHERN Common 688
H. E. Blakeslee SOUTHERN Common 26,201
Andrew J. Dearman, III SOUTHERN Common 11,674
Don E. Mason SOUTHERN Common 34,258
Michael W. Southern SOUTHERN Common 7,430
The directors, nominees
and executive officers
as a group SOUTHERN Common 294,125
GEORGIA Preferred 400
MISSISSIPPI Preferred 233
SOUTHERN Preferred 200
SAVANNAH
Archie H. Davis SOUTHERN Common 190
Paul J. DeNicola SOUTHERN Common 139,642
Walter D. Gnann SOUTHERN Common 1,833
G. Edison Holland SOUTHERN Common 32,589
Robert B. Miller, III SOUTHERN Common 2,203
Arnold M. Tenenbaum SOUTHERN Common 793
III-35
Name of Directors,
Nominees and Number of Shares
Executive Officers Title of Class Beneficially Owned (1) (2)
W. Miles Greer SOUTHERN Common 9,599
Kirby R. Willis SOUTHERN Common 10,996
The directors, nominees
and executive officers
as a group SOUTHERN Common 185,772
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. Blakeslee, 21,932 shares; Mr. Dahlberg, 289,787 shares; Mr. DeNicola,
103,158 shares; Mr. Evans, 40,274 shares; Mr. Farris, 24,020 shares; Mr.
Franklin, 149,760 shares; Mr. Greer, 6,655 shares; Mr. Harris, 183,510
shares; Mr. Haubein, 26,696 shares; Mr. G. R. Hodges, 26,842 shares; Mr. J.
E. Hodges, 15,640 shares; Mr. Holland, 30,209 shares; Mr. Hutchins, 32,521
shares; Mr. Jobe, 39,645 shares; Mr. Mason, 11,421 shares; Mr. Southern,
7,942 shares, and Mr. Willis, 6,192 shares. Also included are shares of
SOUTHERN common stock held by the spouses of the following directors: Mr.
Bowden, 500 shares; Mr. DeNicola, 12,072 shares; Mr. Gaddis; 1,200 shares;
Mr. Hardman, 100 shares; Mr. Harris, 310 shares, and Dr. Shatto, 14,113
shares. Also included are shares of common stock held in the Southern
Company Deferred Stock Trust of which certain directors have the power to
direct the voting, as follows: Mr. Hardman, 6,714 shares and Dr. Shatto,
799 shares. Also included are 1,200 shares of GEORGIA preferred stock held
by Dr. Shatto's spouse.
III-36
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
ALABAMA
Transactions with management and others.
Mr. Whit Armstrong is President, Chairman and Chief Executive Officer of The
Citizens Bank, Enterprise, Alabama; Mr. Carl E. Jones, Jr. is President and
Chief Executive Officer of Regions Financial Corporation, Birmingham, Alabama;
Mr. Wallace D. Malone is Chairman and Chief Executive Officer of SouthTrust
Corporation, Birmingham, Alabama. Mr. C. Dowd Ritter is Chairman, President,
Chief Executive Officer and Director of AmSouth Bancorporation and AmSouth Bank,
Birmingham, Alabama. During 1998, these banks furnished a number of regular
banking services in the ordinary course of business to ALABAMA. ALABAMA intends
to maintain normal banking relations with all the aforesaid banks in the future.
Certain business relationships.
None.
Indebtedness of management.
None.
Transactions with promoters.
None.
GEORGIA
Transactions with management and others.
Mr. L. G. Hardman III is Chairman of the Board of The First National Bank
of Commerce, Georgia; Mr. James R. Lientz, Jr. is President of NationsBank
Mid-South Banking Group, Atlanta, Georgia; Mr. G. Joseph Prendergast is Senior
Executive Vice President, Wachovia Corporation, Atlanta, Georgia; and Mr. Herman
J. Russell is Chairman of the Board of Citizens Trust Bank, Atlanta, Georgia.
During 1998, 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 1998, GEORGIA leased a building from Riverside Manufacturing Co. for
approximately $84,075. Also,Riverside Manufacturing sold to GEORGIA fire
retardant uniforms for $88,646. Mr. William J. Vereen is Chief Executive
Officer, President, Treasurer and Director of Riverside Manufacturing Co.
Certain business relationships.
None.
Indebtedness of management.
None.
Transactions with promoters.
None.
GULF
Transactions with management and others.
None
Certain business relationships.
None.
Indebtedness of management.
None.
Transactions with promoters.
None.
MISSISSIPPI
Transactions with management and others.
Mr. Robert S. Gaddis is Chairman of the Advisory Board of Trustmark
National Bank, Laurel, Mississippi; Mr. George A. Schloegel is President of
Hancock Bank, Gulfport, Mississippi. During 1998, these banks furnished a number
of regular banking services in the ordinary course of business to MISSISSIPPI.
MISSISSIPPI intends to maintain normal banking relations with the aforesaid
banks in the future.
Certain business relationships.
None.
Indebtedness of management.
None.
Transactions with promoters.
None.
III-37
SAVANNAH
Transactions with management and others.
None
Certain business relationships.
None.
Indebtedness of management.
None.
Transactions with promoters.
None.
III-38
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 1998 were as follows:
SOUTHERN filed Current Reports on Form 8-K:
Date of event: December 18, 1998
Items reported: Items 5 and 7
Date of event: December 21, 1998
Items reported: Item 5
ALABAMA filed Current Reports on Form 8-K:
Date of event: October 7, 1998
Items reported: Items 5 and 7
Date of event: October 28, 1998
Items reported: Items 5 and 7
Date of event: November 12, 1998
Items reported: Items 5 and 7
GEORGIA filed Current Reports on Form 8-K:
Date of event: November 19, 1998
Items reported: Items 5 and 7
Date of event: November 19, 1998
Items reported: Items 5 and 7
SAVANNAH filed a Current Report on Form 8-K:
Date of event: December 3, 1998
Items reported: Items 5 and 7
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: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 24, 1999
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, Chief Financial Officer and
Treasurer
(Principal Financial and Accounting Officer)
Directors:
John C. Adams Elmer B. Harris
A. D. Correll Zack T. Pate
Paul J. DeNicola William J. Rushton, III
Jack Edwards Gloria M. Shatto
H. Allen Franklin Gerald J. St. Pe'
Bruce S. Gordon Herbert Stockham
L. G. Hardman III
By: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 24, 1999
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: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 24, 1999
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, Chief Financial Officer and Treasurer
(Principal Financial Officer)
Art P. Beattie
Vice President, Secretary and Comptroller
(Principal Accounting Officer)
Directors:
Whit Armstrong Thomas C. Meredith
David J. Cooper John T. Porter
A. W. Dahlberg Robert D. Powers
Peter V. Gregerson, Sr. Andreas Renschler
Carl E. Jones, Jr. C. Dowd Ritter
Patricia M. King James H. Sanford
James K. Lowder John Cox Webb, IV
Wallace D. Malone, Jr.
By: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 24, 1999
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: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 24, 1999
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)
David M. Ratcliffe
Executive Vice President, Chief Financial Officer
and Treasurer
(Principal Financial Officer)
Cliff S. Thrasher
Vice President, Comptroller and Chief Accounting Officer
(Principal Accounting Officer)
Directors:
Juanita P. Baranco Zell Miller
A. W. Dahlberg G. Joseph Prendergast
William A. Fickling, Jr. Herman J. Russell
L. G. Hardman III William Jerry Vereen
Warren Y. Jobe Carl Ware
James R. Lientz, Jr.
By: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 24, 1999
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: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 24, 1999
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)
Arlan E. Scarbrough
Vice President - Finance
(Principal Financial and Accounting Officer)
Directors:
Paul J. DeNicola Joseph K. Tannehill
Fred C. Donovan, Sr. Barbara H. Thames
W. Deck Hull, Jr.
By: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 24, 1999
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: Dwight H. Evans, President and
Chief Executive Officer
By: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 24, 1999
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.
Dwight H. Evans
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 George A. Schloegel
Edwin E. Downer Philip J. Terrell
Robert S. Gaddis Gene Warr
Linda T. Howard
By: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 24, 1999
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: G. Edison Holland, Jr., President and
Chief Executive Officer
By: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 24, 1999
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.
G. Edison Holland, 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:
Archie H. Davis Robert B. Miller, III
Paul J. DeNicola Arnold M. Tenenbaum
Walter D. Gnann
By: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 24, 1999
IV-4
Exhibit 21. Subsidiaries of the Registrants.*
Jurisdiction of
Name of Company Organization
- - - - - - - ------------------------------------------------ -- ---------------------
The Southern Company Delaware
Southern Company Capital Trust I Delaware
Southern Company Capital Trust II Delaware
Southern Company Capital Trust III Delaware
Southern Company Capital Trust IV Delaware
Southern Company Capital Trust V Delaware
Southern Company Capital Trust VI Delaware
Southern Company Capital Trust VII Delaware
Alabama Power Company Alabama
Alabama Power Capital Trust I Delaware
Alabama Power Capital Trust II Delaware
Alabama Power Capital Trust III Delaware
Alabama Power Capital Trust IV Delaware
Alabama Power Capital Trust V Delaware
Alabama Property Company Alabama
Southern Electric Generating Company Alabama
Georgia Power Company Georgia
Georgia Power Capital Trust I Delaware
Georgia Power Capital Trust II Delaware
Georgia Power Capital Trust III Delaware
Georgia Power Capital Trust IV Delaware
Georgia Power Capital Trust V Delaware
Georgia Power Capital Trust VI Delaware
Georgia Power L.P. Holdings Corp. Georgia
Georgia Power Capital, L.P. Delaware
Piedmont-Forrest Corporation Georgia
Southern Electric Generating Company Alabama
Gulf Power Company Maine
Gulf Power Capital Trust I Delaware
Gulf Power Capital Trust II Delaware
Gulf Power Capital Trust III Delaware
Mississippi Power Company Mississippi
Mississippi Power Capital Trust I Delaware
Mississippi Power Capital Trust II Delaware
Mississippi Power Capital Trust III Delaware
Savannah Electric and Power Company Georgia
Savannah Electric Capital Trust I Delaware
Southern Energy, Inc. Delaware
- - - - - - - ------------------------------------------------ -- ---------------------
*This information is as of December 31, 1998. In addition, the list omits
certain subsidiaries pursuant to paragraph (b)(21)(ii) of Regulation S-K Item
601.
IV-5
Exhibit 23(a)
ARTHUR ANDERSEN LLP
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation
of our reports dated February 10, 1999 on the financial statements of The
Southern Company and its subsidiaries and the related financial statement
schedule, included in this Form 10-K, into The Southern Company's previously
filed Registration Statement File Nos. 2-78617, 33-3546, 33-30171, 33-51433,
33-54415, 33-57951, 33-58371, 33-60427, 333-09077, 333-44127, 333-44261 and
333-64871.
/s/ Arthur Andersen LLP
Atlanta, Georgia
March 22, 1999
IV-6
ARTHUR ANDERSEN LLP
Exhibit 23(b)
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation
of our reports dated February 10, 1999 on the financial statements of Alabama
Power Company and the related financial statement schedule, included in this
Form 10-K, into Alabama Power Company's previously filed Registration Statement
File Nos. 33-61845 and 333-67453.
/s/ Arthur Andersen LLP
Birmingham, Alabama
March 22, 1999
IV-7
ARTHUR ANDERSEN LLP
Exhibit 23(c)
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation
of our reports dated February 10, 1999 on the financial statements of Georgia
Power Company and the related financial statement schedule, included in this
Form 10-K, into Georgia Power Company's previously filed Registration Statement
File No. 333-43895.
/s/ Arthur Andersen LLP
Atlanta, Georgia
March 22, 1999
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 10, 1999 on the financial statements of Gulf Power
Company and the related financial statement schedule, included in this Form
10-K, into Gulf Power Company's previously filed Registration Statement File
Nos. 33-50165 and 333-42033.
/s/ Arthur Andersen LLP
Atlanta, Georgia
March 22, 1999
IV-9
ARTHUR ANDERSEN LLP
Exhibit 23 (e)
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation
of our reports dated February 10, 1999 on the financial statements of
Mississippi Power Company and the related financial statement schedule, included
in this Form 10-K, into Mississippi Power Company's previously filed
Registration Statement File No. 333-45069.
/s/ Arthur Andersen LLP
Atlanta, Georgia
March 22, 1999
IV-10
ARTHUR ANDERSEN LLP
Exhibit 23(f)
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation
of our reports dated February 10, 1999 on the financial statements of Savannah
Electric and Power Company and the related financial statement schedule,
included in this Form 10-K, into Savannah Electric and Power Company's
previously filed Registration Statement File No. 333-46171.
/s/ Arthur Andersen LLP
Atlanta, Georgia
March 22, 1999
IV-11
ARTHUR ANDERSEN LLP
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULE
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 10, 1999. Our audits were made for the purpose of forming an
opinion on those statements taken as a whole. The schedule listed under Item
14(a)(2) herein as it relates to The Southern Company and its subsidiaries (page
S-2) is the responsibility of The Southern Company's management and is presented
for purposes of complying with the Securities and Exchange Commission's rules
and is not part of the basic consolidated financial statements. This schedule
has been subjected to the auditing procedures applied in the audits of the basic
consolidated financial statements and, in our opinion, fairly states 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 10, 1999
IV-12
ARTHUR ANDERSEN LLP
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULE
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 10, 1999. Our audits were made
for the purpose of forming an opinion on those statements taken as a whole. The
schedule listed under Item 14(a)(2) herein as it relates to Alabama Power
Company (page S-3) is the responsibility of Alabama Power Company's management
and is presented for purposes of complying with the Securities and Exchange
Commission's rules and is not part of the basic financial statements. This
schedule has been subjected to the auditing procedures applied in the audits of
the basic financial statements and, in our opinion, fairly states 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 10, 1999
IV-13
ARTHUR ANDERSEN LLP
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULE
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 10, 1999. Our audits were made
for the purpose of forming an opinion on those statements taken as a whole. The
schedule listed under Item 14(a)(2) herein as it relates to Georgia Power
Company (page S-4) is the responsibility of Georgia Power Company's management
and is presented for purposes of complying with the Securities and Exchange
Commission's rules and is not part of the basic financial statements. This
schedule has been subjected to the auditing procedures applied in the audits of
the basic financial statements and, in our opinion, fairly states 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 10, 1999
IV-14
ARTHUR ANDERSEN LLP
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULE
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 10, 1999. Our audits were made for
the purpose of forming an opinion on those statements taken as a whole. The
schedule listed under Item 14(a)(2) herein as it relates to Gulf Power Company
(page S-5) is the responsibility of Gulf Power Company's management and is
presented for purposes of complying with the Securities and Exchange
Commission's rules and is not part of the basic financial statements. This
schedule has been subjected to the auditing procedures applied in the audits of
the basic financial statements and, in our opinion, fairly states 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 10, 1999
IV-15
ARTHUR ANDERSEN LLP
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULE
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 10, 1999. Our audits
were made for the purpose of forming an opinion on those statements taken as a
whole. The schedule listed under Item 14(a)(2) herein as it relates to
Mississippi Power Company (page S-6) is the responsibility of Mississippi Power
Company's management and is presented for purposes of complying with the
Securities and Exchange Commission's rules and is not part of the basic
financial statements. This schedule has been subjected to the auditing
procedures applied in the audits of the basic financial statements and, in our
opinion, fairly states 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 10, 1999
IV-16
ARTHUR ANDERSEN LLP
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULE
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 10, 1999. Our
audits were made for the purpose of forming an opinion on those statements taken
as a whole. The schedule listed under Item 14(a)(2) herein as it relates to
Savannah Electric and Power Company (page S-7) is the responsibility of Savannah
Electric and Power Company's management and is presented for purposes of
complying with the Securities and Exchange Commission's rules and is not part of
the basic financial statements. This schedule has been subjected to the auditing
procedures applied in the audits of the basic financial statements and, in our
opinion, fairly states 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 10, 1999
IV-17
INDEX TO FINANCIAL STATEMENT SCHEDULES
Schedule
Page
II Valuation and Qualifying Accounts and Reserves
1998, 1997 and 1996
The Southern Company and Subsidiary Companies.....................S-2
Alabama Power Company.............................................S-3
Georgia Power Company.............................................S-4
Gulf Power Company................................................S-5
Mississippi Power Company.........................................S-6
Savannah Electric and Power Company...............................S-7
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
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
(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
1998.......................... $77,056 $64,789 $6,325 $35,659 (1) $112,511
1997.......................... 31,587 35,930 36,290 (2) 26,751 (1) 77,056
1996.......................... 37,119 24,768 48 30,348 (1) 31,587
- - - - - - - -------------------
Notes:
(1) Represents write-off of accounts considered to be uncollectible, less
recoveries of amounts previously written off.
(2) Includes the addition of a Purchased Reserve in the amount of $37,000 related to the acquisition of
CEPA.
S-2
ALABAMA POWER COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
(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
1998.......................... $2,272 $7,702 $- $8,119 (Note) $1,855
1997.......................... 1,171 8,580 - 7,479 (Note) 2,272
1996.......................... 1,212 8,214 - 8,255 (Note) 1,171
- - - - - - - -------------------
Note: Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously
written off.
S-3
GEORGIA POWER COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
(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
1998.......................... $3,000 $17,856 $- $15,356 (Note) $5,500
1997.......................... 4,000 7,888 - 8,888 (Note) 3,000
1996.......................... 5,000 11,815 - 12,815 (Note) 4,000
- - - - - - - -------------------
Note: Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously
written off.
S-4
GULF POWER COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31,1998, 1997 AND 1996
(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
1998.......................... $796 $2,288 $- $2,088 (Note) $996
1997.......................... 789 1,350 - 1,343 (Note) 796
1996.......................... 768 1,850 7 1,836 (Note) 789
- - - - - - - -------------------
Note: Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously
written off.
S-5
MISSISSIPPI POWER COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
(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
1998.......................... $698 $1,510 $31 $1,618 (Note) $621
1997.......................... 839 1,128 56 1,325 (Note) 698
1996.......................... 802 1,726 41 1,730 (Note) 839
- - - - - - - -------------------
Note: Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously
written off.
S-6
SAVANNAH ELECTRIC AND POWER COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
(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
1998.......................... $354 $417 $- $487 (Note) $284
1997.......................... 632 192 - 470 (Note) 354
1996.......................... 983 126 - 477 (Note) 632
- - - - - - - -------------------
Note: Represents write-off of accounts receivable considered to be uncollectible, less recoveries of amounts
previously written off.
S-7
EXHIBIT INDEX
The following exhibits indicated by an asterisk preceding the exhibit number
are filed herewith. The balance of the exhibits have heretofore been filed with
the SEC, respectively, as the exhibits and in the file numbers indicated and are
incorporated herein by reference. The exhibits marked with a pound sign are
management contracts or compensatory plans or arrangements required to be filed
herewith and required to be identified as such by Item 14 of Form 10-K.
Reference is made to a duplicate list of exhibits being filed as a part of this
Form 10-K, which list, prepared in accordance with Item 601 of Regulation S-K of
the SEC, immediately precedes the exhibits being physically filed with this Form
10-K.
(1) Underwriting Agreements
GEORGIA
(c) - Distribution Agreement dated November 29, 1995 between
GEORGIA and Lehman Brothers Inc.; Donaldson, Lufkin &
Jenrette Securities Corporation; J. P. Morgan Securities
Inc.; Salomon Brothers Inc and Smith Barney Inc. relating to
$300,000,000 First Mortgage Bonds Secured Medium-Term Notes.
(Designated in GEORGIA's Form 10-K for the year ended
December 31, 1995, as Exhibit 1(c).)
(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 August
10, 1998. (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), in
Certificate of Notification, File No. 70-8191, as Exhibit A,
in ALABAMA's Form 10-K for the year ended December 31, 1997,
File No. 1-3164, as Exhibit 3(b)2 and Form 8-K dated August
10, 1998, File No. 1-3164, as Exhibit 4.4.)
E-1
(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
January 26, 1998. (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), in Form 8-K
dated October 20, 1993, File No. 1-6468, as Exhibit 4(b) and
in GEORGIA's Form 10-K for the year ended December 31, 1997,
File No. 1-6468, as Exhibit 3(c)2.)
(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 January 28, 1998. (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, in Form 8-K dated November 3, 1993,
File No. 0-2429, as Exhibit 4 and in GULF's Form 10-K for
the year ended December 31, 1997, File No. 0-2429, as
Exhibit 3(d)2.)
(d) 2 - By-laws of GULF as amended effective July 26, 1996, and
as presently in effect. (Designated in Form U-1, File No.
70-8949, as Exhibit A-2(c).)
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 December 31, 1997.
(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, in Form 8-K dated August 18,
1993, File No. 0-6849, as Exhibit 4(b)-3 and in
MISSISSIPPI's Form 10-K for the year ended December 31,
1997, File No. 0-6849, as Exhibit 3(e)2.)
E-2
(e) 2 - By-laws of MISSISSIPPI as amended effective April 2,
1996, and as presently in effect. (Designated in Form U5S
for 1995, File No. 30-222-2, as Exhibit B-10.)
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 - Amendment to charter of SAVANNAH dated December 2, 1998.
(f) 3 - 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.)
(4) Instruments Describing Rights of Security Holders, Including Indentures
SOUTHERN
(a) 1 - Subordinated Note Indenture dated as of February 1,
1997, among SOUTHERN, Southern Company Capital Funding, Inc.
and Bankers Trust Company, as Trustee, and indentures
supplemental thereto dated as of February 4, 1997.
(Designated in Registration Nos. 333-28349 as Exhibits 4.1
and 4.2 and 333-28355 as Exhibit 4.2.)
(a) 2 - Subordinated Note Indenture dated as of June 1, 1997,
among SOUTHERN, Southern Company Capital Funding, Inc. and
Bankers Trust Company, as Trustee, and indentures
supplemental thereto through that dated as of December 23,
1998. (Designated in SOUTHERN's Form 10-K for the year ended
December 31, 1997, File No. 1-3526, as Exhibit (4)(a)2, in
Form 8-K dated June 18, 1998, File No. 1-3526, as Exhibit
4.2 and in Form 8-K dated December 18, 1998, File No.
1-3526, as Exhibit 4.4.)
(a) 3 - Amended and Restated Trust Agreement of Southern Company
Capital Trust I dated as of February 1, 1997. (Designated in
Registration No. 333-28349 as Exhibit 4.6)
(a) 4 - Amended and Restated Trust Agreement of Southern Company
Capital Trust II dated as of February 1, 1997. (Designated
in Registration No. 333-28355 as Exhibit 4.6)
(a) 5 - Amended and Restated Trust Agreement of Southern Company
Capital Trust III dated as of June 1, 1997. (Designated in
SOUTHERN's Form 10-K for the year ended December 31, 1997,
File No. 1-3526, as Exhibit (4)(a)5.)
(a) 6 - Amended and Restated Trust Agreement of Southern Company
Capital Trust IV dated as of June 1, 1998. (Designated in
Form 8-K dated June 18, 1998, File No. 1-3526, as Exhibit
4.5.)
E-3
(a) 7 - Amended and Restated Trust Agreement of Southern Company
Capital Trust V dated as of December 1, 1998. (Designated in
Form 8-K dated December 18, 1998, File No. 1-3526, as
Exhibit 4.7A.)
(a) 8 - Capital Securities Guarantee Agreement relating to
Southern Company Capital Trust I dated as of February 1,
1997. (Designated in Registration No. 333-28349 as Exhibit
4.10)
(a) 9 - Capital Securities Guarantee Agreement relating to
Southern Company Capital Trust II dated as of February 1,
1997. (Designated in Registration No. 333-28355 as Exhibit
4.10)
(a) 10 - Preferred Securities Guarantee Agreement relating to
Southern Company Capital Trust III dated as of June 1, 1997.
(Designated in SOUTHERN's Form 10-K for the year ended
December 31, 1997, File No. 1-3526, as Exhibit (4)(a)8.)
(a) 11 - Preferred Securities Guarantee Agreement relating to
Southern Company Capital Trust IV dated as of June 1, 1998.
(Designated in Form 8-K dated June 18, 1998, File No.
1-3626, as Exhibit 4.8.)
(a) 12 - Preferred Securities Guarantee Agreement relating to
Southern Company Capital Trust V dated as of December 1,
1998. (Designated in Form 8-K dated December 18, 1998, File
No. 1-3526, as Exhibit 4.11A.)
ALABAMA
(b) 1 - Indenture dated as of January 1, 1942, between ALABAMA
and The Chase Manhattan Bank (formerly 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. 1-3164, as Exhibit 4(a)-3, in Form 8-K dated
February 17, 1993, File No. 1-3164, as Exhibit 4(a)-3, in
Form 8-K dated March 10, 1993, File No. 1-3164, 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.
1-3164, as Exhibit 4, in Certificate of Notification, File
No. 70-8069, as Exhibit A, in Form 8-K dated November 16,
1993, File No. 1-3164, 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. 1-3164,
as Exhibit 4.)
E-4
(b) 2 - Subordinated Note Indenture dated as of January 1, 1996,
between ALABAMA and The Chase Manhattan Bank (formerly
Chemical Bank), as Trustee, and indenture supplemental
thereto dated as of January 1, 1996. (Designated in
Certificate of Notification, File No. 70-8461, as Exhibits E
and F.)
(b) 3 - Subordinated Note Indenture dated as of January 1, 1997,
between ALABAMA and The Chase Manhattan Bank, as Trustee,
and indentures supplemental thereto through that dated as of
February 25, 1999. (Designated in Form 8-K dated January 9,
1997, File No. 1-3164, as Exhibits 4.1 and 4.2 and in Form
8-K dated February 18, 1999, File No. 3164, as Exhibit 4.2.)
(b) 4 - Senior Note Indenture dated as of December 1, 1997,
between ALABAMA and The Chase Manhattan Bank, as Trustee,
and indentures supplemental thereto through that dated
November 17, 1998. (Designated in Form 8-K dated December 4,
1997, File No. 1-3164, as Exhibits 4.1 and 4.2, in Form 8-K
dated February 20, 1998, File No. 1-3164, as Exhibit 4.2, in
Form 8-K dated April 17, 1998, File No. 1-3164, as Exhibit
4.2, in Form 8-K dated August 11, 1998, File No. 1-3164, as
Exhibit 4.2, in Form 8-K dated September 8, 1998, File No.
1-3164, as Exhibit 4.2, in Form 8-K dated September 16,
1998, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated
October 7, 1998, File No. 1-3164, as Exhibit 4.2, in Form
8-K dated October 28, 1998, File No. 1-3164, as Exhibit 4.2
and in Form 8-K dated November 12, 1998, File No. 1-3164, as
Exhibit 4.2 .)
(b) 5 - Amended and Restated Trust Agreement of Alabama Power
Capital Trust I dated as of January 1, 1996. (Designated in
Certificate of Notification, File No. 70-8461, as Exhibit
D.)
(b) 6 - Amended and Restated Trust Agreement of Alabama Power
Capital Trust II dated as of January 1, 1997. (Designated in
Form 8-K dated January 9, 1997, File No. 1-3164, as Exhibit
4.5.)
(b) 7 - Amended and Restated Trust Agreement of Alabama Power
Capital Trust III dated as of February 1, 1999. (Designated
in Form 8-K dated February 18, 1999, File No. 1-3164, as
Exhibit 4.5.)
(b) 8 - Guarantee Agreement relating to Alabama Power Capital
Trust I dated as of January 1, 1996. (Designated in
Certificate of Notification, File No. 70-8461, as Exhibit
G.)
(b) 9 - Guarantee Agreement relating to Alabama Power Capital
Trust II dated as of January 1, 1997. (Designated in Form
8-K dated January 9, 1997, File No. 1-3164, as Exhibit 4.8.)
(b) 10 - Guarantee Agreement relating to Alabama Power Capital
Trust III dated as of February 1, 1999. (Designated in Form
8-K dated February 18, 1999, File No. 1-3164, as Exhibit
4.8.)
E-5
GEORGIA
(c) 1 - Indenture dated as of March 1, 1941, between GEORGIA and
The Chase Manhattan Bank (formerly 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 October 15, 1995. (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, in Certificate of Notification, File No.
70-8443, as Exhibit E, in GEORGIA's Form 10-K for the year
ended December 31, 1994, File No. 1-6468, as Exhibits 4(c)2
and 4(c)3, in Certificate of Notification, File No. 70-8443,
as Exhibit C, in Certificate of Notification, File No.
70-8443, as Exhibit C, in Form 8-K dated May 17, 1995, File
No. 1-6468, as Exhibit 4 and in GEORGIA's Form 10-K for the
year ended December 31, 1995, File No. 1-6468, as Exhibits
4(c)2, 4(c)3, 4(c)4, 4(c)5 and 4(c)6.)
(c) 2 - Indenture dated as of December 1, 1994, between GEORGIA
and Trust Company Bank, as Trustee and indentures
supplemental thereto through that dated as of December 15,
1994. (Designated in Certificate of Notification, File No.
70-8461, as Exhibits E and F.)
(c) 3 - Subordinated Note Indenture dated as of August 1, 1996,
between GEORGIA and The Chase Manhattan Bank, as Trustee,
and indentures supplemental thereto through January 1, 1997.
(Designated in Form 8-K dated August 21, 1996, File No.
1-6468, as Exhibits 4.1 and 4.2 and in Form 8-K dated
January 9, 1997, File No. 1-6468, as Exhibit 4.2.)
(c) 4 - Subordinated Note Indenture dated as of June 1, 1997,
between GEORGIA and The Chase Manhattan Bank, as Trustee,
E-6
and indentures supplemental thereto through that dated as of
February 25, 1999. (Designated in Certificate of
Notification, File No. 70-8461, as Exhibits D and E and Form
8-K dated February 17, 1999, File No. 1-6468, as Exhibit
4.4.)
(c) 5 - Senior Note Indenture dated as of January 1, 1998,
between GEORGIA and The Chase Manhattan Bank, as Trustee,
and indentures supplemental thereto through that dated as of
March 9, 1999. (Designated in Form 8-K dated January 21,
1998, File No. 1-6468, as Exhibits 4.1 and 4.2, in Forms 8-K
each dated November 19, 1998, File No. 1-6468, as Exhibit
4.2 and in Form 8-K dated March 3, 1999, File No. 1-6469 as
Exhibit 4.2.)
(c) 6 - Amended and Restated Trust Agreement of Georgia Power
Capital Trust I dated as of August 1, 1996. (Designated in
Form 8-K dated August 21, 1996, File No. 1-6468, as Exhibit
4.5.)
(c) 7 - Amended and Restated Trust Agreement of Georgia Power
Capital Trust II dated as of January 1, 1997. (Designated in
Form 8-K dated January 9, 1997, File No. 1-6468, as Exhibit
4.5.)
(c) 8 - Amended and Restated Trust Agreement of Georgia Power
Capital Trust III dated as of June 1, 1997. (Designated in
Certificate of Notification, File No. 70-8461, as Exhibit
C.)
(c) 9 - Amended and Restated Trust Agreement of Georgia Power
Capital Trust IV dated as of February 1, 1999. (Designated
in Form 8-K dated February 17, 1999, as Exhibit 4.7-A)
(c) 10 - Guarantee Agreement relating to Georgia Power Capital
Trust I dated as of August 1, 1996. (Designated in Form 8-K
dated August 21, 1996, File No. 1-6468, as Exhibit 4.8.)
(c) 11 - Guarantee Agreement relating to Georgia Power Capital
Trust II dated as of January 1, 1997. (Designated in Form
8-K dated January 9, 1997, File No. 1-6468, as Exhibit 4.8.)
(c) 12 - Guarantee Agreement relating to Georgia Power Capital
Trust III dated as of June 1, 1997. (Designated in
Certificate of Notification, File No. 70-8461, as Exhibit
F.)
(c) 13 - Guarantee Agreement relating to Georgia Power Capital
Trust IV dated as of February 1, 1999. (Designated in Form
8-K dated February 17, 1999, as Exhibit 4.11-A.)
GULF
(d) 1 - Indenture dated as of September 1, 1941, between GULF
and The Chase Manhattan Bank (formerly The Chase Manhattan
Bank (National Association)), as Trustee, and indentures
supplemental thereto through November 1, 1996. (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
E-7
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, in Certificate of Notification, File No. 70-8229, as
Exhibits E and F, in Form 8-K dated January 17, 1996, File
No. 0-2429, as Exhibit 4, in Certificate of Notification,
File No. 70-8229, as Exhibit A, in Certificate of
Notification, File No. 70-8229, as Exhibit A and in Form 8-K
dated November 6, 1996, File No. 0-2429, as Exhibit 4.)
(d) 2 - Subordinated Note Indenture dated as of January 1, 1997,
between GULF and The Chase Manhattan Bank, as Trustee, and
indentures supplemental thereto through that dated as of
January 1, 1998. (Designated in Form 8-K dated January 27,
1997, File No. 0-2429, as Exhibits 4.1 and 4.2, in Form 8-K
dated July 28, 1997, File No. 0-2429, as Exhibit 4.2 and in
Form 8-K dated January 13, 1998, File No. 0-2429, as Exhibit
4.2.)
(d) 3 - Senior Note Indenture dated as of January 1, 1998,
between GULF and The Chase Manhattan Bank, as Trustee, and
indenture supplemental thereto dated as of June 24, 1998.
(Designated in Form 8-K dated June 17, 1998, File No.
0-2429, as Exhibits 4.1 and 4.2.)
(d) 4 - Amended and Restated Trust Agreement of Gulf Power
Capital Trust I dated as of January 1, 1997. (Designated in
Form 8-K dated January 27, 1997, File No. 0-2429, as Exhibit
4.5.)
(d) 5 - Amended and Restated Trust Agreement of Gulf Power
Capital Trust II dated as of January 1, 1998. (Designated in
Form 8-K dated January 13, 1998, File No. 0-2429, as Exhibit
4.5.)
(d) 6 - Guarantee Agreement relating to Gulf Power Capital Trust
I dated as of January 1, 1997. (Designated in Form 8-K dated
January 27, 1997, File No. 0-2429, as Exhibit 4.8.)
(d) 7 - Guarantee Agreement relating to Gulf Power Capital Trust
II dated as of January 1, 1998. (Designated in Form 8-K
dated January 13, 1998, File No. 0-2429, as Exhibit 4.8.)
MISSISSIPPI
(e) 1 - Indenture dated as of September 1, 1941, between
MISSISSIPPI and Bankers Trust Company, as Successor Trustee,
and indentures supplemental thereto through December 1,
1995. (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, in Form 8-K
E-8
dated March 8, 1994, File No. 0-6849, as Exhibit 4, in
Certificate of Notification, File No. 70-8127, as Exhibit C
and in Form 8-K dated December 5, 1995, File No. 0-6849, as
Exhibit 4.)
(e) 2 - Senior Note Indenture dated as of May 1, 1998 between
MISSISSIPPI and Bankers Trust Company, as Trustee and
indentures supplemental thereto through May 20, 1998.
(Designated in Form 8-K dated May 14, 1998, File No. 0-6849,
as Exhibits 4.1, 4.2(a) and 4.2(b).)
(e) 3 - Subordinated Note Indenture dated as of February 1,
1997, between MISSISSIPPI and Bankers Trust Company, as
Trustee, and indenture supplemental thereto dated as of
February 1, 1997. (Designated in Form 8-K dated February 20,
1997, File No. 0-6849, as Exhibits 4.1 and 4.2.)
(e) 4 - Amended and Restated Trust Agreement of Mississippi
Power Capital Trust I dated as of February 1, 1997.
(Designated in Form 8-K dated February 20, 1997, File No.
0-6849, as Exhibit 4.5.)
(e) 5 - Guarantee Agreement relating to Mississippi Power
Capital Trust I dated as of February 1, 1997. (Designated in
Form 8-K dated February 20, 1997, File No. 0-6849, as
Exhibit 4.8.)
SAVANNAH
(f) 1 - Indenture dated as of March 1, 1945, between SAVANNAH
and The Bank of New York, New York, as Trustee, and
indentures supplemental thereto through May 1, 1996.
(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), in Form
8-K dated July 22, 1993, File No. 1-5072, as Exhibit 4, in
Form 8-K dated May 18, 1995, File No. 1-5072, as Exhibit 4
and in Form 8-K dated May 23, 1996, File No. 1-5072, as
Exhibit 4.)
(f) 2 - Senior Note Indenture dated as of March 1, 1998 between
SAVANNAH and The Bank of New York, as Trustee and indenture
supplemental thereto dated as of March 1, 1998. (Designated
in Form 8-K dated March 9, 1998, File No. 1-5072, as
Exhibits 4.1 and 4.2.)
(f) 3 - Subordinated Note Indenture dated as of December 1,
1998, between SAVANNAH and The Bank of New York, as Trustee,
and indenture supplemental thereto dated as of December 9,
1998. (Designated in Form 8-K dated December 3, 1998, File
No. 1-5072, as Exhibit 4.3 and 4.4.)
(f) 4 - Amended and Restated Trust Agreement of Savannah
Electric Capital Trust I dated as of December 1, 1998.
(Designated in Form 8-K dated December 3, 1998, File No.
1-5072, as Exhibit 4.7.)
E-9
(f) 5 - Guarantee Agreement relating to Savannah Electric
Capital Trust I dated as of December 1, 1998. (Designated in
Form 8-K dated December 3, 1998, File No. 1-5072, as Exhibit
4.11.)
(10) Material Contracts
SOUTHERN
(a) 1 - Service contracts dated as of January 1, 1984, between
SCS and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SEGCO and
SOUTHERN and Amendment No. 1 dated as of September 6, 1985
between SCS 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 - Service contract dated as of December 12, 1994, between
SCS and Mobile Energy Services Company, Inc. (Designated in
SOUTHERN's Form 10-K for the year ended December 31, 1994,
File No. 1-3526, as Exhibit 10(a)58.)
(a) 6 - 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) 7 - Agreement dated as of January 27, 1959, Amendment No. 1
dated as of October 27, 1982 and Amendment No. 2 dated
November 4, 1993 and effective June 1, 1994, among SEGCO,
ALABAMA and GEORGIA. (Designated in Registration No. 2-59634
as Exhibit 5(c), in GEORGIA's Form 10-K for the year ended
December 31, 1982, File No. 1-6468, as Exhibit 10(d)(2) and
in ALABAMA's Form 10-K for the year ended December 31, 1994,
File No. 1-3164, as Exhibit 10(b)18.)
(a) 8 - 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) 9 - 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).)
E-10
(a) 10 - 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) 11 - 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) 12 - 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) 13 - 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) 14 - 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) 15 - 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) 16 - 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) 17 - 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) 18 - Alvin W. Vogtle Nuclear Units Number One and Two
Purchase, Amendment, Assignment and Assumption Agreement
dated as of November 16, 1983, between GEORGIA and MEAG.
(Designated in GEORGIA's Form 10-K for the year ended
December 31, 1983, File No. 1-6468, as Exhibit 10(k)(4).)
(a) 19 - 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) 20 - 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).)
E-11
(a) 21 - Nuclear Operating Agreement between Southern Nuclear
and GEORGIA dated as of July 1, 1993. (Designated in
SOUTHERN's Form 10-K for the year ended December 31, 1997,
File No. 1-3526, as Exhibit 10(a)21.)
(a) 22 - Pseudo Scheduling and Services Agreement between
GEORGIA and MEAG dated as of April 8, 1997. (Designated in
SOUTHERN's Form 10-K for the year ended December 31, 1997,
File No. 1-3526, as Exhibit 10(a)22.)
(a) 23 - 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) 24 - 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) 25 - 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) 26 - 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) 27 - Plant Robert W. Scherer Purchase, Sale and Option
Agreement dated as of May 15, 1980, between GEORGIA and
MEAG. (Designated in Form U-1, File No. 70-6481, as Exhibit
B-1.)
(a) 28 - 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) 29 - 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).)
E-12
(a) 30 - 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) 31 - 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 and Amendment No. 1 dated as of June 15, 1994.
(Designated in Form U-1, File No. 70-7843, as Exhibit B-1
and in SOUTHERN's Form 10-K for the year ended December 31,
1994, File No. 1-3526, as Exhibit 10(a)60.)
(a) 32 - Plant Robert W. Scherer Unit No. Four Operating
Agreement by and among GEORGIA, FP&L and JEA, dated as of
December 31, 1990 and Amendment No. 1 dated as of June 15,
1994. (Designated in Form U-1, File No. 70-7843, as Exhibit
B-2 and in SOUTHERN's Form 10-K for the year ended December
31, 1994, File No. 1-3526, as Exhibit 10(a)61.)
(a) 33 - 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) 34 - 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) 35 - Unit Power Sales Agreement dated July 19, 1988, between
FPC and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and
SCS. (Designated in SAVANNAH's Form 10-K for the year ended
December 31, 1988, File No. 1-5072, as Exhibit 10(d).)
(a) 36 - 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) 37 - 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).)
E-13
(a) 38 - 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) 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.)
(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).)
E-14
(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 - Revised and Restated Coordination Services Agreement
between and among GEORGIA, OPC and Georgia Systems
Operations Corporation dated as of September 10, 1997.
(Designated in SOUTHERN's Form 10-K for the year ended
December 31, 1997, File No. 1-3526, as Exhibit 10(a)48.)
(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.)
(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.)
E-15
(a) 58 - 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) 59 - The Southern Company Productivity Improvement
Plan, Amended and Restated effective January 1, 1998.
# * (a) 60 - The Southern Company Executive Productivity
Improvement Plan, Amended and Restated effective January 1,
1998.
* (a) 61 - The Southern Company Employee Savings Plan, Amended
and Restated effective January 1, 1997 and all amendments
thereto through Amendment Number Three.
* (a) 62 - The Southern Company Employee Stock Ownership Plan,
Amended and Restated effective January 1, 1997 and all
amendments thereto through Amendment Number Two.
* (a) 63 - The Southern Company Performance Pay Plan, Amended
and Restated effective January 1, 1998.
# (a) 64 - The Deferred Compensation Plan for the Directors of
The Southern Company and First Amendment and Second
Amendment thereto. (Designated in SOUTHERN's Form 10-K for
the year ended December 31, 1994, File No. 1-3526, as
Exhibit 10(a)76 and in SOUTHERN's Form 10-K for the year
ended December 31, 1995, File No. 1-3526, as Exhibit
10(a)75.)
# (a) 65 - The Southern Company Outside Directors Pension
Plan. (Designated in SOUTHERN's Form 10-K for the year ended
December 31, 1994, File No. 1-3526, as Exhibit 10(a)77.)
# * (a) 66 - The Southern Company Deferred Compensation Plan,
Amended and Restated effective January 1, 1998.
# (a) 67 - The Southern Company Outside Directors Stock Plan
and First Amendment thereto. (Designated in Registration No.
33-54415 as Exhibit 4(c) and in SOUTHERN's Form 10-K for the
year ended December 31, 1995, File No. 1-3526, as Exhibit
10(a)79.)
# (a) 68 - Outside Directors Stock Plan for Subsidiaries of
The Southern Company and First Amendment thereto.
(Designated in SOUTHERN's Form 10-K for the year ended
December 31, 1995, File No. 1-3526, as Exhibit 10(a)80.)
# * (a) 69 - The Southern Company Performance Dividend Plan,
Amended and Restated effective January 1, 1998.
E-16
(a) 70 - The Southern Company Pension Plan, effective as of
January 1, 1997 and Amendment Number One thereto.
(Designated in SOUTHERN's Form 10-K for the year ended
December 31, 1996, File No. 1-3526, as Exhibit 10(a)83 and
in SOUTHERN's Form 10-K for the year ended December 31,
1997, File No. 1-3526, as Exhibit 10(a)79.)
* (a) 71 - Amendment Number Two and Amendment Number Three to
The Southern Company Pension Plan.
# * (a) 72 - The Southern Company Performance Stock Plan,
Amended and Restated effective January 1, 1998.
# (a) 73 - The Southern Company Supplemental Executive
Retirement Plan. (Designated in SOUTHERN's Form 10-K for the
year ended December 31, 1997, File No. 1-3526, as Exhibit
10(a)81.)
# * (a) 74 - Amendment Number One and Amendment Number Two to
The Southern Company Supplemental Executive Retirement Plan.
# (a) 75 - The Southern Company Performance Sharing Plan
effective January 1, 1997. (Designated in SOUTHERN's Form
10-K for the year ended December 31, 1997, File No. 1-3526,
as Exhibit 10(a)82.)
# * (a) 76 - Amendments One through Six to The Southern
Company Performance Sharing Plan.
# * (a) 77 - The Southern Company Supplemental Benefit Plan,
Amended and Restated effective January 1, 1998.
* (a) 78 - Southern Company Change in Control Severance Plan,
effective December 7, 1998.
# * (a) 79 - Southern Company Executive Change in Control
Severance Plan, effective December 7, 1998.
# * (a) 80 - Deferred Compensation Agreement between SOUTHERN,
GEORGIA and Henry Allen Franklin.
# * (a) 81 - Deferred Compensation Agreement between SOUTHERN,
Southern Nuclear and William G. Hairston III.
# * (a) 82 - Deferred Compensation Agreement between SOUTHERN,
GEORGIA and Warren Y. Jobe.
# * (a) 83 - Change in Control Agreement between SOUTHERN,
Southern Energy Resources, Inc. and Thomas G. Boren.
# * (a) 84 - Change in Control Agreement between SOUTHERN,
GULF and Travis J. Bowden.
# * (a) 85 - Change in Control Agreement between SOUTHERN, SCS
and A. W. Dahlberg.
# * (a) 86 - Change in Control Agreement between SOUTHERN, SCS
and Paul J. DeNicola.
E-17
# * (a) 87 - Change in Control Agreement between SOUTHERN,
MISSISSIPPI and Dwight H. Evans.
# * (a) 88 - Change in Control Agreement between SOUTHERN,
ALABAMA and Banks Harry Farris.
# * (a) 89 - Change in Control Agreement between SOUTHERN,
GEORGIA and Henry Allen Franklin.
# * (a) 90 - Change in Control Agreement between SOUTHERN,
Southern Nuclear and William G. Hairston, III.
# * (a) 91 - Change in Control Agreement between SOUTHERN,
ALABAMA and Elmer B. Harris.
# * (a) 92 - Change in Control Agreement between SOUTHERN,
SAVANNAH and G. Edison Holland, Jr.
# * (a) 93 - Change in Control Agreement between SOUTHERN, SCS
and C. Alan Martin.
# * (a) 94 - Change in Control Agreement between SOUTHERN, SCS
and Charles Douglas McCrary.
# * (a) 95 - Change in Control Agreement between SOUTHERN,
GEORGIA and David M. Ratcliffe.
# * (a) 96 - Change in Control Agreement between SOUTHERN, SCS
and Stephen A. Wakefield.
# * (a) 97 - Change in Control Agreement between SOUTHERN, SCS
and W. Lawrence Westbrook.
ALABAMA
(b) 1 - Service contracts dated as of January 1, 1984, between
SCS and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SEGCO and
SOUTHERN and Amendment No. 1 dated as of September 6, 1985
between SCS 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)6 herein.
(b) 3 - Agreement dated as of January 27, 1959, Amendment No. 1
dated as of October 27, 1982 and Amendment No. 2 dated
November 4, 1993 and effective June 1, 1994, among SEGCO,
ALABAMA and GEORGIA. See Exhibit 10(a)7 herein.
E-18
(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)33 herein.
(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)34 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)35 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)36 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)37 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)38 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-19
(b) 17 - Long Term Transmission Service Agreement between
Entergy Power, Inc. and ALABAMA, MISSISSIPPI and SCS. See
Exhibit 10(a)53 herein.
(b) 18 - Operating Agreement for the Joseph M. Farley Nuclear
Plant between ALABAMA and Southern Nuclear dated as of
December 23, 1991. See Exhibit 10(a)58 herein.
# * (b) 19 - The Southern Company Productivity Improvement
Plan, Amended and Restated effective January 1, 1998. See
Exhibit 10(a)59 herein.
# * (b) 20 - The Southern Company Executive Productivity
Improvement Plan, Amended and Restated effective January 1,
1998. See Exhibit 10(a)60 herein.
* (b) 21 - The Southern Company Employee Savings Plan, Amended
and Restated effective January 1, 1997 and all amendments
thereto through Amendment Number Three. See Exhibit 10(a)61
herein.
* (b) 22 - The Southern Company Employee Stock Ownership Plan,
Amended and Restated effective January 1, 1997 and all
amendments thereto through Amendment Number Two. See Exhibit
10(a)62 herein.
* (b) 23 - The Southern Company Performance Pay Plan, Amended
and Restated effective January 1, 1998. See Exhibit 10(a)63
herein.
# * (b) 24 - The Southern Company Deferred Compensation Plan,
Amended and Restated effective January 1, 1998. See Exhibit
10(a)66 herein.
# (b) 25 - The Southern Company Outside Directors Pension
Plan. See Exhibit 10(a)65 herein.
# (b) 26 - Outside Directors Stock Plan for Subsidiaries of
The Southern Company and First Amendment thereto. See
Exhibit 10(a)68 herein.
(b) 27 - The Southern Company Pension Plan, effective as of
January 1, 1997 and Amendment Number One thereto. See
Exhibit 10(a)70 herein.
* (b) 28 - Amendment Number Two and Amendment Number Three to
The Southern Company Pension Plan. See Exhibit 10(a)71
herein.
# * (b) 29 - The Southern Company Performance Stock Plan,
Amended and Restated effective January 1, 1998. See Exhibit
10(a)72 herein.
# (b) 30 - The Southern Company Supplemental Executive
Retirement Plan. See Exhibit 10(a)73 herein.
# * (b) 31 - Amendment Number One and Amendment Number Two to
The Southern Company Supplemental Executive Retirement Plan.
See Exhibit 10(a)74 herein.
# * (b) 32 - The Southern Company Performance Dividend Plan,
Amended and Restated effective January 1, 1998. See Exhibit
10(a)69 herein.
E-20
# (b) 33 - The Southern Company Performance Sharing Plan
effective January 1, 1997. See Exhibit 10(a)75 herein.
# * (b) 34 - Amendments One through Six to The Southern
Company Performance Sharing Plan. See Exhibit 10(a)76
herein.
# * (b) 35 - The Southern Company Supplemental Benefit Plan,
Amended and Restated effective January 1, 1998. See Exhibit
10(a)77 herein.
* (b) 36 - Southern Company Change in Control Severance Plan,
effective December 7, 1998. See Exhibit 10(a)78 herein.
# * (b) 37 - Southern Company Executive Change in Control
Severance Plan, effective December 7, 1998. See Exhibit
10(a)79 herein.
# * (b) 38 - Change in Control Agreement between SOUTHERN,
ALABAMA and Banks Harry Farris. See Exhibit 10(a)88 herein.
# * (b) 39 - Change in Control Agreement between SOUTHERN,
ALABAMA and Elmer B. Harris. See Exhibit 10(a)91 herein.
# * (b) 40 - Supplemental Pension Agreement between ALABAMA,
GULF and Travis J. Bowden.
GEORGIA
(c) 1 - Service contracts dated as of January 1, 1984, between
SCS and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SEGCO and
SOUTHERN and Amendment No. 1 dated as of September 6, 1985,
between SCS 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)6 herein.
(c) 3 - Agreement dated as of January 27, 1959, Amendment No. 1
dated as of October 27, 1982 and Amendment No. 2 dated
November 4, 1993 and effective June 1, 1994, among SEGCO,
ALABAMA and GEORGIA. See Exhibit 10(a)7 herein.
(c) 4 - Joint Committee Agreement dated as of August 27, 1976,
among GEORGIA, OPC, MEAG and Dalton. See Exhibit 10(a)8
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)9 herein.
(c) 6 - Edwin I. Hatch Nuclear Plant Operating Agreement dated
as of January 6, 1975, between GEORGIA and OPC. See Exhibit
10(a)10 herein.
E-21
(c) 7 - Revised and Restated Integrated Transmission System
Agreement dated as of November 12, 1990, between GEORGIA and
OPC. See Exhibit 10(a)11 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)12 herein.
(c) 9 - Plant Hal Wansley Operating Agreement dated as of March
26, 1976, between GEORGIA and OPC. See Exhibit 10(a)13
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)14 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)15 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)16 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)17 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)18 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)19 herein.
(c) 16 - Plant Hal Wansley Operating Agreement dated as of
August 27, 1976, between GEORGIA and MEAG. See Exhibit
10(a)20 herein.
(c) 17 - Nuclear Operating Agreement between Southern Nuclear
and GEORGIA dated as of July 1, 1993. See Exhibit 10(a)21
herein.
(c) 18 - Pseudo Scheduling and Services Agreement between
GEORGIA and MEAG dated as of April 8, 1997. See Exhibit
10(a)22 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)23 herein.
(c) 20 - Plant Hal Wansley Operating Agreement dated as of April
19, 1977, between GEORGIA and Dalton. See Exhibit 10(a)24
herein.
E-22
(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)25 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)26 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)27 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)28 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)29 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)30 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 and Amendment No. 1 dated as of June 15, 1994. See
Exhibit 10(a)31 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 and Amendment No. 1 dated as of June 15,
1994. See Exhibit 10(a)32 herein.
(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)33 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)34 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)35 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)36 herein.
E-23
(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)37 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)38 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.
(c) 41 - Block Power Sale Agreement between GEORGIA and OPC
dated as of November 12, 1990. See Exhibit 10(a)47 herein.
(c) 42 - Revised and Restated Coordination Services Agreement
between and among GEORGIA, OPC and Georgia Systems
Operations Corporation dated as of September 10, 1997. 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.
E-24
(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.)
# * (c) 54 - The Southern Company Productivity Improvement
Plan, Amended and Restated effective January 1, 1998. See
Exhibit 10(a)59 herein.
# * (c) 55 - The Southern Company Executive Productivity
Improvement Plan, Amended and Restated effective January 1,
1998. See Exhibit 10(a)60 herein.
* (c) 56 - The Southern Company Employee Savings Plan, Amended
and Restated effective January 1, 1997 and all amendments
thereto through Amendment Number Three. See Exhibit 10(a)61
herein.
* (c) 57 - The Southern Company Employee Stock Ownership Plan,
Amended and Restated effective January 1, 1997 and all
amendments thereto through Amendment Number Two. See Exhibit
10(a)62 herein.
* (c) 58 - The Southern Company Performance Pay Plan, Amended
and Restated effective January 1, 1998. See Exhibit 10(a)63
herein.
# * (c) 59 - The Southern Company Deferred Compensation Plan,
Amended and Restated effective January 1, 1998. See Exhibit
10(a)66 herein.
E-25
# (c) 60 - The Southern Company Outside Directors Pension
Plan. See Exhibit 10(a)65 herein.
# (c) 61 - Outside Directors Stock Plan for Subsidiaries of
The Southern Company and First Amendment thereto. See
Exhibit 10(a)68 herein.
(c) 62 - The Southern Company Pension Plan, effective as of
January 1, 1997 and Amendment Number One thereto. See
Exhibit 10(a)70 herein.
* (c) 63 - Amendment Number Two and Amendment Number Three to
The Southern Company Pension Plan. See Exhibit 10(a)71
herein.
# * (c) 64 - The Southern Company Performance Stock Plan,
Amended and Restated effective January 1, 1998. See Exhibit
10(a)72 herein.
# (c) 65 - The Southern Company Supplemental Executive
Retirement Plan. See Exhibit 10(a)73 herein.
# * (c) 66 - Amendment Number One and Amendment Number Two to
The Southern Company Supplemental Executive Retirement Plan.
See Exhibit 10(a)74 herein.
# * (c) 67 - The Southern Company Performance Dividend Plan,
Amended and Restated effective January 1, 1998. See Exhibit
10(a)69 herein.
# (c) 68 - The Southern Company Performance Sharing Plan
effective January 1, 1997. See Exhibit 10(a)75 herein.
# * (c) 69 - Amendments One through Six to The Southern
Company Performance Sharing Plan. See Exhibit 10(a)76
herein.
# * (c) 70 - The Southern Company Supplemental Benefit Plan,
Amended and Restated effective January 1, 1998. See Exhibit
10(a)77 herein.
* (c) 71 - Southern Company Change in Control Severance Plan,
effective December 7, 1998. See Exhibit 10(a)78 herein.
# * (c) 72 - Southern Company Executive Change in Control
Severance Plan, effective December 7, 1998. See Exhibit
10(a)79 herein.
# * (c) 73 - Deferred Compensation Agreement between SOUTHERN,
GEORGIA and Henry Allen Franklin. See Exhibit 10(a)80
herein.
# * (c) 74 - Deferred Compensation Agreement between SOUTHERN,
GEORGIA and Warren Y. Jobe. See Exhibit 10(a)82 herein.
# * (c) 75 - Change in Control Agreement between SOUTHERN,
GEORGIA and Henry Allen Franklin. See Exhibit 10(a)89
herein.
# * (c) 76 - Change in Control Agreement between SOUTHERN,
GEORGIA and David M. Ratcliffe. See Exhibit 10(a)95 herein.
E-26
# * (c) 77 - Supplemental Pension Agreement between GEORGIA
and Warren Y. Jobe.
GULF
(d) 1 - Service contracts dated as of January 1, 1984, between
SCS and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SEGCO and
SOUTHERN and Amendment No. 1 dated as of September 6, 1985,
between SCS and SOUTHERN. See Exhibit 10(a)1 herein.
(d) 2 - Interchange contract dated October 28, 1988, effective
January 1, 1989, between ALABAMA, GEORGIA, GULF,
MISSISSIPPI, SAVANNAH and SCS. See Exhibit 10(a)6 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)29 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)30 herein.
(d) 5 - 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.
(d) 6 - 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)33 herein.
(d) 7 - 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)34 herein.
(d) 8 - Unit Power Sales Agreement dated July 19, 1988, between
FPC and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SAVANNAH and
SCS. See Exhibit 10(a)35 herein.
(d) 9 - Amended Unit Power Sales Agreement dated July 20, 1988,
between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
SAVANNAH and SCS. See Exhibit 10(a)36 herein.
(d) 10 - Amended Unit Power Sales Agreement dated August 17,
1988, between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
SAVANNAH and SCS. See Exhibit 10(a)37 herein.
E-27
(d) 11 - 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) 12 - Unit Power Sales Agreement dated December 8, 1990,
between Tallahassee and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
SAVANNAH and SCS. See Exhibit 10(a)38 herein.
(d) 13 - Transition Energy Agreement dated December 31, 1990,
between JEA and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
SAVANNAH and SCS. See Exhibit 10(a)39 herein.
(d) 14 - Transition Energy Agreement dated December 31, 1990,
between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
SAVANNAH and SCS. See Exhibit 10(a)40 herein.
# * (d) 15 - The Southern Company Productivity Improvement
Plan, Amended and Restated effective January 1, 1998. See
Exhibit 10(a)59 herein.
# * (d) 16 - The Southern Company Executive Productivity
Improvement Plan, Amended and Restated effective January 1,
1998. See Exhibit 10(a)60 herein.
* (d) 17 - The Southern Company Employee Savings Plan, Amended
and Restated effective January 1, 1997 and all amendments
thereto through Amendment Number Three. See Exhibit 10(a)61
herein.
* (d) 18 - The Southern Company Employee Stock Ownership Plan,
Amended and Restated effective January 1, 1997 and all
amendments thereto through Amendment Number Two. See Exhibit
10(a)62 herein.
* (d) 19 - The Southern Company Performance Pay Plan, Amended
and Restated effective January 1, 1998. See Exhibit 10(a)63
herein.
# * (d) 20 - The Southern Company Deferred Compensation Plan,
Amended and Restated effective January 1, 1998. See Exhibit
10(a)66 herein.
# (d) 21 - The Southern Company Outside Directors Pension
Plan. See Exhibit 10(a)65 herein.
# (d) 22 - Outside Directors Stock Plan for Subsidiaries of
The Southern Company and First Amendment thereto. See
Exhibit 10(a)68 herein.
(d) 23 - The Southern Company Pension Plan, effective as of
January 1, 1997 and Amendment Number One thereto. See
Exhibit 10(a)70 herein.
* (d) 24 - Amendment Number Two and Amendment Number Three to
The Southern Company Pension Plan. See Exhibit 10(a)71
herein.
# * (d) 25 - The Southern Company Supplemental Benefit Plan,
Amended and Restated effective January 1, 1998. See Exhibit
10(a)77 herein.
E-28
* (d) 26 - Southern Company Change in Control Severance Plan,
effective December 7, 1998. See Exhibit 10(a)78 herein.
# * (d) 27 - Southern Company Executive Change in Control
Severance Plan, effective December 7, 1998. See Exhibit
10(a)79 herein.
# * (d) 28 - Change in Control Agreement between SOUTHERN,
GULF and Travis J. Bowden. See Exhibit 10(a)84 herein.
# * (d) 29 - The Southern Company Performance Stock Plan,
Amended and Restated effective January 1, 1998. See Exhibit
10(a)72 herein.
# (d) 30 - The Southern Company Supplemental Executive
Retirement Plan. See Exhibit 10(a)73 herein.
# * (d) 31 - Amendment Number One and Amendment Number Two to
The Southern Company Supplemental Executive Retirement Plan.
See Exhibit 10(a)74 herein.
# * (d) 32 - The Southern Company Performance Dividend Plan,
Amended and Restated effective January 1, 1998. See Exhibit
10(a)69 herein.
# (d) 33 - The Southern Company Performance Sharing Plan
effective January 1, 1997. See Exhibit 10(a)75 herein.
# * (d) 34 - Amendments One through Six to The Southern
Company Performance Sharing Plan. See Exhibit 10(a)76
herein.
# * (d) 35 - Supplemental Pension Agreement between SAVANNAH,
GULF and G. Edison Holland, Jr.
# * (d) 36 - Supplemental Pension Agreement between ALABAMA,
GULF and Travis J. Bowden. See Exhibit 10(b)40 herein.
MISSISSIPPI
(e) 1 - Service contracts dated as of January 1, 1984, between
SCS and ALABAMA, GEORGIA, GULF, MISSISSIPPI, SEGCO and
SOUTHERN and Amendment No. 1 dated as of September 6, 1985,
between SCS 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)6 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)33 herein.
E-29
(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)34 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)35 herein.
(e) 6 - Amended Unit Power Sales Agreement dated July 20, 1988,
between FP&L and ALABAMA, GEORGIA, GULF, MISSISSIPPI,
SAVANNAH and SCS. See Exhibit 10(a)36 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)37 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)38 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, 1998. See
Exhibit 10(a)59 herein.
# * (e) 15 - The Southern Company Executive Productivity
Improvement Plan, Amended and Restated effective January 1,
1998. See Exhibit 10(a)60 herein.
* (e) 16 - The Southern Company Employee Savings Plan, Amended
and Restated effective January 1, 1997 and all amendments
thereto through Amendment Number Three. See Exhibit 10(a)61
herein.
E-30
* (e) 17 - The Southern Company Employee Stock Ownership Plan,
Amended and Restated effective January 1, 1997 and all
amendments thereto through Amendment Number Two. See Exhibit
10(a)62 herein.
* (e) 18 - The Southern Company Performance Pay Plan, Amended
and Restated effective January 1, 1998. See Exhibit 10(a)63
herein.
# * (e) 19 - The Southern Company Deferred Compensation Plan,
Amended and Restated effective January 1, 1998. See Exhibit
10(a)66 herein.
# (e) 20 - The Southern Company Outside Directors Pension
Plan. See Exhibit 10(a)65 herein.
# (e) 21 - Outside Directors Stock Plan for Subsidiaries of
The Southern Company and First Amendment thereto. See
Exhibit 10(a)68 herein.
(e) 22 - The Southern Company Pension Plan, effective as of
January 1, 1997 and Amendment Number One thereto. See
Exhibit 10(a)70 herein.
* (e) 23 - Amendment Number Two and Amendment Number Three to
The Southern Company Pension Plan. See Exhibit 10(a)71
herein.
# * (e) 24 - The Southern Company Supplemental Benefit Plan,
Amended and Restated effective January 1, 1998. See Exhibit
10(a)77 herein.
* (e) 25 - Southern Company Change in Control Severance Plan,
effective December 7, 1998. See Exhibit 10(a)78 herein.
# * (e) 26 - Southern Company Executive Change in Control
Severance Plan, effective December 7, 1998. See Exhibit
10(a)79 herein.
# * (e) 27 - Change in Control Agreement between SOUTHERN,
MISSISSIPPI and Dwight H. Evans. See Exhibit 10(a)87 herein.
# * (e) 28 - The Southern Company Performance Stock Plan,
Amended and Restated effective January 1, 1998. See Exhibit
10(a)72 herein.
# (e) 29 - The Southern Company Supplemental Executive
Retirement Plan. See Exhibit 10(a)73 herein.
# * (e) 30 - Amendment Number One and Amendment Number Two to
The Southern Company Supplemental Executive Retirement Plan.
See Exhibit 10(a)74 herein.
# * (e) 31 - The Southern Company Performance Dividend Plan,
Amended and Restated effective January 1, 1998. See Exhibit
10(a)69 herein.
# (e) 32 - The Southern Company Performance Sharing Plan
effective January 1, 1997. See Exhibit 10(a)75 herein.
E-31
# * (e) 33 - Amendments One through Six to The Southern
Company Performance Sharing Plan. See Exhibit 10(a)76
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)6 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)35 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)36 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)37 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)38 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.
# * (f) 11 - The Southern Company Productivity Improvement
Plan, Amended and Restated effective January 1, 1998. See
Exhibit 10(a)59 herein.
# * (f) 12 - The Southern Company Executive Productivity
Improvement Plan, Amended and Restated effective January 1,
1998. See Exhibit 10(a)60 herein.
E-32
* (f) 13 - The Southern Company Employee Savings Plan, Amended
and Restated effective January 1, 1997 and all amendments
thereto through Amendment Number Three. See Exhibit 10(a)61
herein.
* (f) 14 - The Southern Company Employee Stock Ownership Plan,
Amended and Restated effective January 1, 1997 and all
amendments thereto through Amendment Number Two. See Exhibit
10(a)62 herein.
# (f) 15 - Supplemental Executive Retirement Plan of SAVANNAH,
Amended and Restated effective January 1, 1996 and all
amendments thereto through Amendment Number Two. (Designated
in SAVANNAH's Form 10-K for the year ended December 31,
1995, File No. 1-5072, as Exhibit 10(f)17, in SAVANNAH's
Form 10-K for the year ended December 31, 1996, File No.
1-5072, as Exhibit 10(f)20 and in SAVANNAH's Form 10-K for
the year ended December 31, 1997, File No. 1-5072, as
Exhibit 10(f)18.)
# (f) 16 - Deferred Compensation Plan for Key Employees of
SAVANNAH and all amendments thereto through Amendment Number
Two. (Designated in SAVANNAH's Form 10-K for the year ended
December 31, 1994, File No. 1-5072, as Exhibit 10(f)17, in
SAVANNAH's Form 10-K for the year ended December 31, 1995,
File No. 1-5072, as Exhibit 10(f)19 and in SAVANNAH's Form
10-K for the year ended December 31, 1996, File No. 1-5072,
as Exhibit 10(f)22.)
# * (f) 17 - Amendment Number Three to the Deferred
Compensation Plan for Key Employees of SAVANNAH.
* (f) 18 - The Southern Company Performance Pay Plan, Amended
and Restated effective January 1, 1998. See Exhibit 10(a)63
herein.
# (f) 19 - The Southern Company Outside Directors Pension
Plan. See Exhibit 10(a)65 herein.
# (f) 20 - Deferred Compensation Plan for Directors of
SAVANNAH. (Designated in SAVANNAH's Form 10-K for the year
ended December 31, 1997, File No. 1-5072, as Exhibit
10(f)23.)
# (f) 21 - Outside Directors Stock Plan for Subsidiaries of
The Southern Company and First Amendment thereto. See
Exhibit 10(a)68 herein.
(f) 22 - The Southern Company Pension Plan, effective as of
January 1, 1997 and Amendment Number One thereto. See
Exhibit 10(a)70 herein.
* (f) 23 - Amendment Number Two and Amendment Number Three to
The Southern Company Pension Plan. See Exhibit 10(a)71
herein.
# * (f) 24 - The Southern Company Supplemental Benefit Plan,
Amended and Restated effective January 1, 1998. See Exhibit
10(a)77 herein.
* (f) 25 - Southern Company Change in Control Severance Plan,
effective December 7, 1998. See Exhibit 10(a)78 herein.
E-33
# * (f) 26 - Southern Company Executive Change in Control
Severance Plan, effective December 7, 1998. See Exhibit
10(a)79 herein.
# * (f) 27 - Change in Control Agreement between SOUTHERN,
SAVANNAH and G. Edison Holland, Jr. See Exhibit 10(a)92
herein.
# * (f) 28 - The Southern Company Deferred Compensation Plan,
Amended and Restated effective January 1, 1998. See Exhibit
10(a)66 herein.
# * (f) 29 - The Southern Company Performance Stock Plan,
Amended and Restated effective January 1, 1998. See Exhibit
10(a)72 herein.
# (f) 30 - The Southern Company Supplemental Executive
Retirement Plan. See Exhibit 10(a)73 herein.
# * (f) 31 - Amendment Number One and Amendment Number Two to
The Southern Company Supplemental Executive Retirement Plan.
See Exhibit 10(a)74 herein.
# * (f) 32 - The Southern Company Performance Dividend Plan,
Amended and Restated effective January 1, 1998. See Exhibit
10(a)69 herein.
# (f) 33 - The Southern Company Performance Sharing Plan
effective January 1, 1997. See Exhibit 10(a)75 herein.
# * (f) 34 - Amendments One through Six to The Southern
Company Performance Sharing Plan. See Exhibit 10(a)76
herein.
# * (f) 35 - Supplemental Pension Agreement between SAVANNAH,
GULF and G. Edison Holland, Jr. See Exhibit 10(d)35 herein.
(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.
E-34
GULF
* (d) - The consent of Arthur Andersen LLP is contained herein
at page IV-9.
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.
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 10, 1999, File No. 1-3526, as Exhibit 27.)
ALABAMA
(b) - Financial Data Schedule. (Designated in Form 8-K dated
February 10, 1999, File No. 1-3164, as Exhibit 27.)
E-35
GEORGIA
(c) - Financial Data Schedule. (Designated in Form 8-K dated
February 10, 1999, File No. 1-6468, as Exhibit 27.)
GULF
(d) - Financial Data Schedule. (Designated in Form 8-K dated
February 10, 1999, File No. 0-2429, as Exhibit 27.)
MISSISSIPPI
(e) - Financial Data Schedule. (Designated in Form 8-K dated
February 10, 1999, File No. 0-6849, as Exhibit 27.)
SAVANNAH
(f) - Financial Data Schedule. (Designated in Form 8-K dated
February 10, 1999, File No. 1-5072, as Exhibit 27.)
E-36