===============================================================================
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, 1999
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
(404) 506-6526
0-2429 Gulf Power Company 59-0276810
(A Maine Corporation)
One Energy Place
Pensacola, Florida 32520
(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
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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 5.83% Series
Senior Notes
7 1/8% Series A 7% Series C
7% Series B 6.75% Series J
Company obligated mandatorily redeemable preferred
securities, $25 liquidation amount
7.375% Trust Preferred Securities 5
7.60% Trust Originated Preferred Securities 6
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Senior Notes Georgia Power Company
6 7/8% Series A 6 5/8% Series D
6.60% Series B
Company obligated mandatorily redeemable
preferred securities, $25 liquidation amount
7.75% Trust Preferred Securities 7 7.60% Trust Preferred Securities 8
7.75% Cumulative Quarterly Income Preferred Securities 9
6.85% Trust Preferred Securities 10
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1 As of December 31, 1999.
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 Trust I and guaranteed by Georgia Power
Company.
8 Issued by Georgia Power Capital Trust II and guaranteed by Georgia Power
Company.
9 Issued by Georgia Power Capital Trust III and guaranteed by Georgia Power
Company.
10 Issued by Georgia Power Capital Trust IV and guaranteed by Georgia Power
Company.
Company obligated mandatorily Gulf Power Company
redeemable preferred securities,
$25 liquidation amount
7.625% Cumulative Quarterly Income Preferred Securities 11
7.00% Cumulative Quarterly Income Preferred Securities 12
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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
redeemablepreferred 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)
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Preferred stock, cumulative, $100 stated value Georgia Power Company
$4.60 Series (1954)
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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 Mississippi
Power Company.
14 Issued by Savannah Electric Capital Trust I and guaranteed by Savannah
Electric and Power Company.
15 As of December 31, 1999.
Preferred stock, cumulative, $100 par value Gulf Power Company
4.64% Series 5.44% Series
5.16% Series
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Preferred stock, cumulative, $100 par value Mississippi Power Company
4.40% Series4.60% Series
4.72% Series7.00% Series
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Indicate by check mark whether the registrants (1) have filed all
reports required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period that the
registrants were required to file such reports), and (2) have been subject to
such filing requirements for the past 90 days. Yes X No___
Indicate by check mark if disclosure of delinquent filers pursuant
to Item 405 of Regulation S-K is not contained herein, and will not be
contained, to the best of registrants' knowledge, in definitive proxy or
information statements incorporated by reference in Part III of this Form 10-K
or any amendment to this Form 10-K. ( )
Aggregate market value of voting stock held by non-affiliates of
The Southern Company at February 29, 2000: $14.4 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 29, 2000
The Southern Company Par Value $5 Per Share 649,563,507
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 2000 Annual Meeting of
Stockholders are incorporated by reference into PART III.
This combined Form 10-K is separately filed by The Southern Company, Alabama
Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power
Company and Savannah Electric and Power Company. Information contained herein
relating to any individual company is filed by such company on its own behalf.
Each company makes no representation as to information relating to the other
companies.
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Table of Contents
Page
PART I
Item 1 Business
The SOUTHERN System.................................................................................. I-2
Integrated Southeast Utilities....................................................................... I-2
Southern Energy...................................................................................... I-2
Other Business....................................................................................... I-3
Certain Factors Affecting the Industry............................................................... I-3
Construction Programs................................................................................ I-4
Year 2000............................................................................................ I-5
Financing Programs................................................................................... I-6
Fuel Supply.......................................................................................... I-7
Territory Served by the Integrated Southeast Utilities............................................... 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-24
Item 4 Submission of Matters to a Vote of Security Holders.................................................... I-24
Executive Officers of SOUTHERN......................................................................... I-25
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-30
Item 13 Certain Relationships and Related Transactions........................................................ III-35
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.
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
integrated Southeast utilities................ ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH
IPP........................................... Independent power producer
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
PSC........................................... Public Service Commission
RTO........................................... Regional Transmission Organization
RUS........................................... Rural Utility Service (formerly Rural Electrification
Administration)
ii
DEFINITIONS
(continued)
SAVANNAH...................................... Savannah Electric and Power Company
SCEM.......................................... Southern Company Energy Marketing, L.P.
SCS........................................... Southern Company Services, Inc. (the system
service company)
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 Energy............................... Southern Energy, Inc.
Southern LINC................................. Southern Communications Services, Inc.
Southern Nuclear.............................. Southern Nuclear Operating Company, Inc.
SOUTHERN system............................... SOUTHERN, the integrated Southeast utilities, SEGCO,
Southern Energy, Southern Nuclear, SCS, Southern LINC, Energy
Solutions and other subsidiaries
TVA........................................... Tennessee Valley Authority
WPD........................................... Western Power Distribution (United Kingdom)
(formerly South Western Electricity plc)
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 businesses, internal
restructuring or other restructuring options, that may be pursued by the
registrants; state and federal rate regulation in the United States; 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 Southern Energy and
other subsidiaries 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. The integrated
Southeast utilities supply electric service in the states of Alabama, Georgia,
Florida, Mississippi and Georgia, respectively. More particular information
relating to each of the integrated Southeast utilities 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, Energy Solutions and other direct and
indirect subsidiaries. Southern Energy acquires, develops, builds, owns and
operates power production and delivery facilities and provides a broad range of
energy-related services to utilities and industrial companies in selected
countries around the world. Southern Energy businesses include independent power
projects, integrated utilities, a distribution company, and energy trading and
marketing businesses outside the southeastern United States. A further
description of Southern Energy's business and organization follows later in this
section under "Southern Energy." Southern LINC provides digital wireless
communications services to SOUTHERN's integrated Southeast utilities and also
markets these services to the public within the Southeast. Southern Nuclear
provides services to ALABAMA and GEORGIA's nuclear plants. Energy Solutions
develops new business opportunities related to energy products and services.
ALABAMA and GEORGIA each own 50% of the outstanding common stock of SEGCO.
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.
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.
I-1
The SOUTHERN System
Integrated Southeast Utilities
The transmission facilities of each of the integrated Southeast utilities 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
integrated Southeast utilities 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 the Integrated Southeast Utilities" herein.)
Operating contracts covering arrangements in effect with principal
neighboring utility systems provide for capacity exchanges, capacity purchases
and sales, transfers of economy energy and other similar transactions.
Additionally, the integrated Southeast utilities 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 integrated Southeast utilities 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 integrated Southeast utilities are represented on
the National Electric Reliability Council.
An intra-system interchange agreement provides for coordinating operations
of the power producing facilities of the integrated Southeast utilities 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 integrated Southeast utilities to provide the most economical
sources of power consistent with good operation. The resulting benefits and
savings are apportioned among the integrated Southeast utilities.
Reference is made to each registrant's "Management's Discussion and Analysis
- - Future Earnings Potential" in Item 7 for information relating to the FERC's
final rule issued on December 20, 1999, relating to RTOs.
SCS has contracted with SOUTHERN, each integrated Southeast utility,
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 integrated Southeast utilities 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.
Southern Energy
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 Energy is a global company
engaged in electricity generation and distribution, integrated utility
operations and energy marketing. Southern Energy is one of the world's largest
independent power producers with ownership interests in generating facilities
with a total capacity of 28,000 megawatts, of which Southern Energy has net
ownership or control of over 14,000 megawatts. In addition, Southern Energy has
projects under construction or advanced development in which it will have
additional net ownership interests totaling 5,000 megawatts. SOUTHERN has filed
with the SEC a request to invest up to nearly $6 billion in Southern Energy's
domestic and international business. The current SEC authority is $4.1 billion,
I-2
of which $2.7 billion has been invested as of December 31, 1999. For additional
information relating to Southern Energy's business strategy, reference is made
to Item 7, SOUTHERN's "Management's Discussion and Analysis - Future Earnings
Potential" herein.
Approximately 60% of the net megawatts of generating capacity currently
owned by Southern Energy is located in the United States, with the remainder in
England, Germany, the Philippines, China, Brazil, Argentina, Chile, the Bahamas
and Trinidad and Tobago. In the United States during 1999, Southern Energy
completed the acquisition of 3,065 megawatts from Pacific Gas & Electric Company
in California and 1,794 megawatts from Orange & Rockland Utilities, Inc. and
Consolidated Edison Company of New York, Inc. in the State of New York. These
North American acquisitions, together with acquisitions completed prior to 1999,
are a component of Southern Energy's strategy of investing in generating assets
which are expected to be linked to Southern Energy's trading and marketing
activities. Also in 1999, Southern Energy completed the acquisition of a 9.99%
ownership interest in Shandong International Power Development Company Limited
which currently owns generating facilities in China with installed capacity of
4,435 megawatts.
In 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 Properties - Southern Energy"
herein for additional information relating to these and other Southern Energy
projects.
In addition, Southern Energy is a leading energy marketer in North America
through its 60% interest in SCEM, a joint venture between Southern Energy and
Vastar Resources, Inc. formed for the purpose of marketing and trading energy
and energy-linked commodities, including electricity, natural gas, oil, coal and
emission allowances. Southern Energy has also opened an office in Amsterdam, The
Netherlands, in order to market and trade energy in European markets.
SOUTHERN continues to consider various business strategies and restructuring
options to enhance shareholder value with respect to its investment in Southern
Energy.
Other Business
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 integrated Southeast
utilities and marketing its services to non-affiliates within the Southeast. Its
system covers approximately 130,000 square miles and combines the functions of
two-way radio dispatch, cellular phone, short text and numeric messaging and
wireless data transfer.
These continuing efforts to invest in and develop new business opportunities
offer the potential of earning returns which may exceed those of rate-regulated
operations. However, these activities also involve a higher degree of risk.
SOUTHERN expects to make substantial investments over the period 2000-2002 in
these and other new businesses.
Certain Factors Affecting the Industry
Various factors are currently affecting the electric utility industry in
general, including increasing competition and the regulatory changes related
thereto, costs required to comply with environmental regulations, and the
potential for new business opportunities (with their associated risks) outside
of traditional rate-regulated operations. The effects of these and other factors
on the SOUTHERN system are described herein. Particular reference is made to
Item 1 - BUSINESS - "Southern Energy", "Other Business", "Competition" and
"Environmental Regulation." See also "Cautionary Statement Regarding
Forward-Looking Information."
I-3
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 2000 through
2002 by the integrated Southeast utilities, SEGCO, SCS, Southern LINC and
Southern Energy are estimated as follows: (in millions)
------------------------------ -------- --------- ----------
2000 2001 2002
-------- --------- ----------
ALABAMA $ 831 $743 $ 860
GEORGIA 1,244 1,511 1,485
GULF 106 232 90
MISSISSIPPI 84 54 61
SAVANNAH 26 30 36
SEGCO 15 41 69
SCS 30 24 20
Southern LINC 53 27 10
Southern Energy* 578 1,044 1,222
Other 49 134 88
=========================== =========== ========= ==========
SOUTHERN system $3,016 $3,840 $3,941
=========================== =========== ========= ==========
*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 - "Southern
Energy" herein.)
I-4
Estimated construction costs in 2000 are expected to be apportioned approximately as follows: (in millions)
---------------------------- ----------------------- ----------- ------------- ---------- ---------------------------
SOUTHERN Southern
system* Energy ALABAMA GEORGIA GULF MISSISSIPPI SAVANNAH
----------------------- ----------- ------------- ---------- ---------------------------
New generation $641 $ - $240 $ 368 $26 $ 7 $-
Other generating
facilities including
associated plant
substations 864 442 140 229 17 16 5
New business 372 - 139 176 25 22 10
Transmission 420 10 143 225 16 25 1
Joint line and substation 54 - - 47 7 - -
Distribution 289 103 89 73 9 7 8
Nuclear fuel 93 - 32 61 - - -
General plant 283 23 48 65 6 7 2
----------------------- ----------- ------------- ---------- ---------------------------
$3,016 $578 $831 $1,244 $106 $84 $26
======================= =========== ============= ========== ===========================
*Southern LINC, SCS and other businesses plan capital additions to general
plant in 2000 of $53 million, $30 million and $49 million, respectively, while
SEGCO plans capital additions of $15 million to generating facilities. (See Item
1 - BUSINESS "Southern Energy" and "Other 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; acquisitions 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. In addition, there can be no assurance that costs related to
capital expenditures will be fully recovered.
The integrated Southeast utilities have approximately 5,200 megawatts of
combustion turbine generating capacity scheduled to be placed in service by
2002. Approximately 1,400 megawatts of this new capacity will be dedicated to
the wholesale market. Southern Energy has approximately 1,000 megawatts of owned
capacity under construction. Significant construction of transmission and
distribution facilities and the upgrading of generating plants will be
continuing for the business in the Southeast. (See Item 2 - PROPERTIES - "Other
Electric Properties - Southern Energy" 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 Challenge" in Item 7 herein for information relating to Year 2000
issues.
I-5
Financing Programs
The amount and timing of additional equity capital to be raised in 2000, 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 2000 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 integrated Southeast utilities 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 integrated Southeast utilities 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 addition, future projects undertaken by subsidiaries of Southern Energy,
as with existing projects, will generally be financed with an appropriate mix of
debt that is non-recourse to SOUTHERN and equity.
Short-term debt is often utilized as appropriate at SOUTHERN and the
integrated Southeast utilities.
The maximum amounts of short-term or term-loan indebtedness authorized by
the appropriate regulatory authorities are shown on the following table:
Amount Outstanding at
Authorized December 31, 1999
-------------- ---------------------
(in millions)
ALABAMA $ 750 (1) $ 97
GEORGIA 1,700 (2) 636
GULF 300(1) 55
MISSISSIPPI 350(1) 138
SAVANNAH 90(2) 64
SOUTHERN 2,000(1) 1,075
------------------ -------------- -- -------------------
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, 1999, GEORGIA
had remaining authority of $376 million expiring December 31, 2000. SAVANNAH
received 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.
I-6
Fuel Supply
The integrated Southeast utilities' and SEGCO's supply of electricity is derived
predominantly from coal. The sources of generation for the years 1997 through
1999 and the estimates for 2000 are shown below:
Oil and
ALABAMA Coal Nuclear Hydro Gas
--------- ---------- --------- ---------
1997 72% 20% 8% *%
1998 72 18 8 2
1999 72 20 5 3
2000 69 18 7 6
GEORGIA
1997 75 22 2 1
1998 73 22 3 2
1999 75 22 1 2
2000 74 22 3 1
GULF
1997 100 ** ** *
1998 98 ** ** 2
1999 97 ** ** 3
2000 98 ** ** 2
MISSISSIPPI
1997 85 ** ** 15
1998 80 ** ** 20
1999 81 ** ** 19
2000 81 ** ** 19
SAVANNAH
1997 87 ** ** 13
1998 76 ** ** 24
1999 78 ** ** 22
2000 89 ** ** 11
SEGCO
1997 100 ** ** *
1998 100 ** ** *
1999 100 ** ** *
2000 100 ** ** *
SOUTHERN system***
1997 77 17 4 2
1998 76 16 4 4
1999 78 17 2 3
2000 76 16 4 4
---------- ------- --------- ---------- --------- ---------
*Less than 0.5%.
**Not applicable.
***Amounts shown for the SOUTHERN system are weighted averages of the integrated
Southeast utilities and SEGCO.
The average costs of fuel in cents per net kilowatt-hour generated for 1997
through 1999 are shown below:
1997 1998 1999
-------------- ------------- -------------
ALABAMA 1.49 1.54 1.44
GEORGIA 1.32 1.36 1.34
GULF 1.99 1.69 1.60
MISSISSIPPI 1.54 1.62 1.65
SAVANNAH 2.27 2.33 2.20
SEGCO 1.51 1.53 1.77
SOUTHERN
System* 1.46 1.48 1.45
- ------------------- -------------- ------------- -------------
* Amounts shown for the SOUTHERN system are weighted averages of the
integrated Southeast utilities and SEGCO.
See SELECTED FINANCIAL DATA in Item 6 herein for each registrant's source
of energy supply.
I-7
As of February 11, 2000, the integrated Southeast utilities had stockpiles
of coal on hand at their respective coal-fired plants which represented an
estimated 25.8 days of recoverable supply for bituminous coal and 54.1 days for
sub-bituminous coal. It is estimated that approximately 66.9 million tons of
coal will be consumed in 2000 by the integrated Southeast utilities (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 integrated Southeast
utilities currently have 38 coal contracts. These contracts cover remaining
terms of up to 12 years. Approximately 26% of 2000 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 the inventory targets will be approximately 32 nameplate days of
recoverable supply for the heavy burn season between June 1 and September 30 and
25 nameplate days for the remaining periods. During 1999, the integrated
Southeast utilities' and SEGCO's average price of coal delivered was
approximately $34.77 per ton.
In 1999, the weighted average sulfur content of all coal purchased by the
integrated Southeast utilities for use in the coal-fired facilities was 0.83%
sulfur. This sulfur level allowed the integrated Southeast utilities to remain
well below the limits as set forth by Phase I of the Clean Air Act. Phase II
sulfur dioxide and nitrogen oxide limits began in 2000. The integrated Southeast
utilities have secured sufficient quantities of lower sulfur coal to help meet
the more stringent Phase II sulfur requirements in conjunction with the sulfur
dioxide allowances banked in Phase I. 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.
The integrated Southeast utilities 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. 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. Activities for adding dry cask storage
capacity and for potentially increasing spent fuel pool rack capacity at Plant
Hatch during 2000 are in progress. Planning for additional on-site spent fuel
storage capacity at Plant Farley is also in progress, with the intent to place
additional on-site spent fuel storage capacity in operation as early as 2005. In
addition, through Southern Nuclear, ALABAMA and GEORGIA are members of Private
Fuel Storage, LLC, a joint utility effort to develop a private spent fuel
storage facility for temporary storage of spent nuclear fuel. This facility is
planned to begin operation as early as 2003.
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 the Integrated Southeast Utilities
The territory in which the integrated Southeast utilities 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 integrated
Southeast utilities. 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 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-Results
of Operations" in Item 7 herein. Also, for information relating to the sources
of revenues for the SOUTHERN system and each of the integrated Southeast
utilities, reference is made to Item 6 herein.
A portion of the area served by the integrated Southeast utilities 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 integrated Southeast utilities 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 its full 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 821,000 kilowatts and a transmission system
estimated to be 1,480 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 1997, 1998 and 1999. 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 1997, 1998 and 1999
will be used to meet the needs of GEORGIA's retail customers through 2004. In
April 1999, a new power supply agreement was implemented between GEORGIA and
OPC. Pursuant to this agreement, OPC will purchase 250 megawatts of steam
capacity through March 2006, 250 megawatts of peaking capacity through August of
2000, and 125 megawatts of peaking capacity from September 2000 through August
2001.
There are 65 municipally-owned electric distribution systems operating in
the territory in which the integrated Southeast utilities 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 is being sold to AMEA for its member municipalities that
previously were served directly by ALABAMA as wholesale customers. Under the
terms of the contracts, ALABAMA received payments from AMEA representing the net
present value of the revenues associated with the respective capacity
entitlements. See Note 7 to ALABAMA's financial statements in Item 8 herein for
further information on these contracts.
Forty-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 Act. The Energy Act
allows 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. The
integrated Southeast utilities are aggressively working to maintain and expand
their 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 continues to
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 a 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 such company's financial condition and
results of operations. The integrated Southeast utilities are attempting to
minimize or reduce their cost exposure. Reference is made to Note 3 to the
financial statements for SOUTHERN under "Alabama Power Rate Adjustment
Procedures" and "Georgia Power 1998 Retail Rate Order" for information regarding
these efforts.
Reference is made to each registrant's "Management's Discussion and Analysis
- - Future Earnings Potential" in Item 7 for information relating to the FERC's
final rule issued on December 20, 1999, relating to RTOs.
Continuing to be a low-cost producer could provide opportunities to increase
market share and profitability in markets that evolve with changing regulation.
Conversely, if the integrated Southeast utilities do not remain low-cost
producers and provide quality service, then energy sales could be adversely
affected, 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 and to enhance
shareholder value, 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 or other restructuring options, disposition
of certain assets or businesses, 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 - "Southern
Energy" and "Other 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 twelve
industrial customers. Under the terms of these contracts, ALABAMA purchases
excess generation of such companies. During 1999, ALABAMA purchased
approximately 94 million kilowatt-hours from such companies at a cost of $2.2
million.
I-12
GEORGIA currently has contracts in effect with six small power producers
whereby GEORGIA purchases their excess generation. During 1999, GEORGIA
purchased 3.9 million kilowatt-hours from such companies at a cost of $638,000.
In June 1998, GEORGIA entered into a 30-year purchased power agreement for
electricity from a 300-megawatt cogeneration facility. Payments are subject to
reductions for failure to meet minimum capacity output. During 1999, GEORGIA
purchased 705.2 million kilowatt-hours at a cost of $39 million from this
facility. Reference is made to Note 4 to the financial statements for GEORGIA in
Item 8 herein for information regarding purchased power commitments.
GULF currently has agreements in effect with four industrial customers
pursuant to which GULF purchases "as available" energy from customer-owned
generation. During 1999, GULF purchased 162 million kilowatt-hours from such
companies for $5.0 million.
In 1996, MISSISSIPPI entered into agreements to purchase options for summer
peaking power for the years 1997 through 2000. 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 1999, SAVANNAH purchased 28 million
kilowatt-hours from such companies at a cost of $2.8 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 integrated Southeast utilities 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 the Integrated Southeast Utilities" herein for information
concerning suppliers of electricity operating within or near the areas served at
retail by the integrated Southeast utilities.)
Regulation
State Commissions
The integrated Southeast utilities 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 the Integrated Southeast Utilities" herein.)
Holding Company Act
SOUTHERN is registered as a holding company under the Holding Company Act, and
it and its subsidiary companies are subject to the regulatory provisions of said
Act, including provisions relating to the issuance of securities, sales and
acquisitions of securities and utility assets, services performed by SCS and
Southern Nuclear, and the activities of certain of SOUTHERN's special purpose
subsidiaries.
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.
Federal Power Act
The Federal Power Act subjects the integrated Southeast utilities and SEGCO to
regulation by the FERC as companies engaged in the transmission or sale at
wholesale of electric energy in interstate commerce, including regulation of
accounting policies and practices.
ALABAMA and GEORGIA are also subject to the provisions of the Federal Power
Act or the earlier Federal Water Power Act applicable to licensees with respect
to their hydroelectric developments. Among the hydroelectric projects subject to
licensing by the FERC are 14 existing ALABAMA generating stations having an
I-13
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 received a new, 40-year license for the Flint River Project
effective November 1, 1999. GEORGIA has also started the relicensing process for
the Middle Chattahoochee Project. This project consists of the Goat Rock,
Oliver, and North Highlands facilities.
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.
On February 29, 2000, Southern Nuclear, on behalf of GEORGIA, filed a
license renewal application with the NRC for Plant Hatch units 1 and 2. If
approved, the operating license will be extended to August 6, 2034 for Plant
Hatch unit 1 and until June 13, 2038 for Plant Hatch unit 2.
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 regarding nuclear performance standards imposed by the
Georgia PSC that may impact retail rates.
Environmental Regulation
The integrated Southeast utilities, SEGCO and Southern Energy's domestic
operations 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 integrated Southeast
utilities, SEGCO and Southern Energy 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, including a pending lawsuit brought
on behalf of the EPA.
I-14
The integrated Southeast utilities', SEGCO's and Southern Energy's estimated
capital expenditures for environmental quality control facilities for the years
2000, 2001 and 2002 are as follows: (in millions)
--------------------- --- ---------- ---------- -----------
2000 2001 2002
---------- ---------- -----------
ALABAMA $ 28 $ 78 $ 72
GEORGIA 161 268 298
GULF 2 2 9
MISSISSIPPI - - 7
SAVANNAH 1 2 2
SEGCO 4 31 55
Southern Energy 29 38 69
--------------------- --- ---------- ---------- -----------
Total $225 $419 $512
===================== === ========== ========== ===========
*The foregoing estimates are included in the current construction programs.
(See Item 1 - BUSINESS - "Construction Programs" herein.)
Additionally, each integrated Southeast utility 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 integrated Southeast utilities, SEGCO and Southern Energy 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.
International Regulation
Southern Energy's international operations are subject to the jurisdiction of
numerous governmental agencies in the countries in which its projects are
located with respect to environmental and other regulatory matters. Generally,
many of the countries in which Southern Energy conducts and will conduct
business have recently developed or are in the process of developing new
regulatory and legal structures to accommodate private and foreign-owned
businesses. These regulatory and legal structures and their interpretation by
applicable administrative agencies are relatively new and sometimes limited, and
more detailed rules and procedures may be issued in the future. The
interpretation of existing rules can also be expected to evolve over time. In
addition, as Southern Energy acquires additional projects in various countries,
it will be affected by the environmental and other regulatory restrictions of
such countries.
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 integrated Southeast utilities 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 integrated Southeast utilities are allowed by their respective PSCs to
negotiate the terms and compensation of service to large customers. Such terms
and compensation of service, however, are subject to final PSC approval.
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
I-15
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. 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. Reference is also made to GULF's
"Management's Discussion and Analysis - Future Earnings Potential" in Item 7
herein for a discussion of recent Florida PSC matters.
Integrated Resource Planning
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 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 were evaluated against self-build options,
and a Certification Filing for the selected resources was approved by the
Georgia PSC in March 2000. The selected resources for retail needs in Georgia
are: (1) a 7-year purchased power agreement with the West Georgia Generating
Company for 310 megawatts starting in 2002, increasing to 465 megawatts in 2005,
and terminating in May 2009; and (2) a 7 1/2-year purchased power agreement for
two 568 megawatt combined cycle units to be located at Plant Wansley starting in
2002 and terminating at the end of 2009. SAVANNAH has a 7-year purchased power
agreement with GEORGIA for 200 megawatts of the 1,136 megawatt addition at Plant
Wansley starting in 2002 and terminating in 2009. After 2009, this capacity will
be available to the wholesale market.
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 each of 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 32,949 employees on their
payrolls at December 31, 1999.
-------------------------------- --- -------------------------
Employees
at
December 31, 1999
-------------------------
ALABAMA 6,792
GEORGIA 8,961
GULF 1,339
MISSISSIPPI 1,328
SAVANNAH 533
SCS 3,572
Southern Energy* 6,680
Southern Nuclear 3,018
Other 726
-------------------------------- --- -------------------------
Total 32,949
================================ === =========================
*Includes 5,282 employees on international payrolls.
The integrated Southeast utilities 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, 2002.
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 four-year labor agreements with the IBEW and the Office and
Professional Employees International Union that expire April 15, 2003 and
December 1, 2003, respectively.
Southern Energy has a labor contract with the United Steel Workers that
extends to January 1, 2004 at its State Line facility in Hammond, Indiana.
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. Also, Southern
Energy New York has a contract with the IBEW which expires on June 1, 2000.
Currently, Southern Energy New York is in negotiations with the IBEW.
Southern Nuclear has agreements with the IBEW on separate three-year
contracts extending to August 15, 2001 for Plant Farley and to June 30, 2002 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 Integrated Southeast Utilities
The integrated Southeast utilities and SEGCO, at December 31, 1999, 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 899,612 (8)
Vogtle Augusta, GA 1,060,240 (9)
-----------
GEORGIA Total 1,959,852
-----------
Total Nuclear Steam 3,679,852
-----------
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
-------
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 31,196,193
==========
------------------------------------------------ -----------------
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.
I-19
Except as discussed below under "Titles to Property," the principal plants
and other important units of the integrated Southeast utilities 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, 1999, the unamortized portion of
this cost was $35 million.
The all-time maximum demand on the integrated Southeast utilities and SEGCO
was 30,578,200 kilowatts and occurred in August 1999. This amount excludes
demand served by capacity retained by MEAG and Dalton and excludes demand
associated with power purchased from OPC and SEPA by its preference customers.
The reserve margin for the integrated Southeast utilities and SEGCO at that time
was 8.5%. 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.)
I-20
Other Electric Properties - Southern Energy
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, 1999, 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 15 428 - 26.00 Coal
BEWAG Germany 14 340 - 26.00 Oil & Gas
Birchwood Virginia 1 111 222 50.00 Coal (2)
CEPA China 3 634 - 32.00 Coal
CEPA Philippines 2 641 735 87.22 Coal
CEPA Philippines 3 189 210 90.10 Oil
CEPA China 16 443 - 9.99 Coal
CEPA Philippines 2 1,119 1,218 91.90 Coal
CEPA Philippines 1 100 100 100.00 Oil
CEPA Philippines 4 15 15 100.00 Diesel
CEMIG Brazil 34 194 - 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 37 103 125 82.34 Diesel & Hydro
Freeport Grand Bahamas 8 79 126 62.50 Oil
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
SE California California 13 3,065 3,065 100.00 Oil & Gas
SE New York New York 16 1,794 1,794 100.00 Oil, Gas, Coal &
Hydro
SE New Maine and Massachusetts 8 1,245 1,236 100.00 Oil & Gas
England
SEI Wichita Falls Texas 4 80 80 100.00 Gas
WPD United Kingdom 10 71 - 3.77 Gas
WPD United Kingdom 8 6 12 49.00 Oil & Gas
WPD United Kingdom 2 3 - 22.00 Wind
WPD United Kingdom 2 - 2 - Oil
==============================================================================================================================
Total Capacity 12,446 11,949
==============================================================================================================================
I-21
Notes: (1) Represents megawatts of capacity under a concession
agreement expiring in the year 2023. In early 2000, Southern
Energy announced an agreement to sell Alicura, its
Argentinean assets, substantially at the adjusted carrying value
with no material gain or loss expected to be recognized in 2000.
(2) Cogeneration facility.
Facilities Under Construction
-------------------------------------------------------------------------------------------------------------------------------
Megawatts of Capacity -----------------
Percent
Facility Location Units Own Operate Ownership Type
--------------------------------------------------------------------------------------------------------------------------------
SEI Wisconsin Wisconsin 2 306 306 100.00 Gas
SEI Texas Texas 3 550 550 100.00 Gas
Edelnor Chile 1 206 250 82.34 Gas
--------------------------------------------------------------------------------------------------------------------------------
Total Capacity 1,062 1,106
================================================================================================================================
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 1,796 - - 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 addition, GEORGIA 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
is 25.4 percent. On January 14, 1998, the Georgia PSC ordered that the Company
I-22
be allowed approximately $108 million of its $142 million investment in the
plant in rate base as of December 31, 1998. GEORGIA appealed the Georgia PSC's
order. Under the rate order approved by the Georgia PSC on December 18, 1998,
GEORGIA accepted the rate base allowance and, 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 integrated Southeast utilities' 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 integrated
Southeast utilities 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.
I-23
Item 3. LEGAL PROCEEDINGS
(1) United States of America v. ALABAMA, GEORGIA and SCS (United States
District Court for the Northern District of Georgia)
Reference is made to Note 3 in each of the registrant's financial
statements in Item 8 herein.
(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 Lake Martin
Litigation" and "Lake Martin 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 "Other 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).
Reference is made to Note 3 to SOUTHERN's financial statements in Item 8
herein under the caption "Mobile Energy Services Petition for
Bankruptcy".
(5) State of Minas Gerais v. Southern Electric Brasil Participacoes Ltda.
(Appellate Court of the State of Minas Gerais)
Reference is made to Note 3 to SOUTHERN's financial statements in Item 8
herein under the caption "Southern Energy Brazilian Investment".
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 integrated Southeast utilities, 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-24
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, 1999.
A. W. Dahlberg
Chairman, Chief Executive Officer, and Director
Age 59
Elected Director in 1985 and Chairman and Chief Executive Officer effective
March 1995. Also served as President from January 1994 to June 1999.
H. Allen Franklin
President, Chief Operating Officer and Director
Age 55
Elected Director in 1988 and President and Chief Operating Officer effective
June 1999. Previously served as President and Chief Executive Officer of GEORGIA
from January 1994 to June 1999.
S. Marce Fuller
Executive Vice President
Age 39
Elected in 1999. She also has served as President and Chief Executive Officer of
Southern Energy since July 1999. Previously Executive Vice President of Southern
Energy from October 1998 to July 1999; Senior Vice President from May 1996 to
October 1998; and Vice President from February 1994 to May 1996. Also served as
President and Chief Executive Officer of SCEM from February 1998 to November
1999.
Elmer B. Harris
Executive Vice President and Director
Age 60
Elected Director in 1989 and Executive Vice President in 1991. He also has
served as President and Chief Executive Officer of ALABAMA since 1989.
David M. Ratcliffe
Executive Vice President
Age 51
Elected in 1999. He also has served as President and Chief Executive Officer of
GEORGIA since June 1999. Previously served as Executive Vice President and Chief
Financial Officer of GEORGIA from March 1998 to June 1999; Senior Vice President
of SOUTHERN from March 1995 to March 1998; and as President and Chief Executive
Officer of MISSISSIPPI from 1991 to March 1995.
Stephen A. Wakefield
Senior Vice President and General Counsel
Age 59
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 60
Elected in 1986. He also has served as Executive Vice President of SCS since
1986.
C. Alan Martin
Vice President
Age 51
Elected in 1998; served as Chief Marketing Officer for the SOUTHERN system.
Previously Vice President of Human Resources of SOUTHERN from 1995 to February
1998. Effective January 1, 2000; elected Executive Vice President of ALABAMA.
Charles D. McCrary
Vice President
Age 48
Elected in 1998; serves as Chief Production Officer for the SOUTHERN system. He
also serves as Executive Vice President of GEORGIA since May 1998. Previously,
he served as Executive Vice President of ALABAMA from 1994 through April 1998.
W. G. Hairston, III
Age 54
President and Chief Executive Officer of Southern Nuclear since 1993.
The officers of SOUTHERN were elected for a term running from June 1, 1999
for one year until the next annual meeting of directors or until their
successors are elected and have qualified, except for Ms. Fuller who was elected
October 18, 1999.
I-25
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
----------- --------------
1999
First Quarter $29-5/8 $23-1/4
Second Quarter 29-3/16 22-3/4
Third Quarter 28 25
Fourth Quarter 27-1/8 22-1/16
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
-------------------- --------------- --- --------------
There is no market for the other registrants' common stock, all of
which is owned by SOUTHERN. On February 29, 2000, the closing price
of SOUTHERN's common stock was $22-3/16.
(b) Number of SOUTHERN's common stockholders
at December 31, 1999:
174,179
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 1999 1998
------------------- --------- ------------- ----------
SOUTHERN First $233,879 $232,449
Second 233,445 233,623
Third 228,690 233,763
Fourth 225,470 233,506
ALABAMA First 98,000 90,400
Second 98,400 90,500
Third 99,700 90,800
Fourth 103,500 95,400
GEORGIA First 133,100 132,100
Second 133,700 132,300
Third 135,500 132,700
Fourth 140,700 139,500
GULF First 15,000 14,100
Second 15,100 14,100
Third 15,300 14,100
Fourth 15,900 14,900
MISSISSIPPI First 13,800 12,700
Second 13,800 12,800
Third 14,000 12,800
Fourth 14,500 13,400
SAVANNAH First 6,200 5,800
Second 6,200 5,800
Third 6,300 5,800
Fourth 6,500 6,100
------------------- --------- ------------- ----------
The dividend paid per share by SOUTHERN was 33.5(cent) for each quarter of
1998 and 1999. The dividend paid on SOUTHERN's common stock for the first
quarter of 2000 was 33.5(cent) per share.
The amount of dividends on their common stock that may be paid by the
subsidiary registrants is restricted in accordance with their first mortgage
bond indenture. The
II-1
amounts of earnings retained in the business and the amounts restricted against
the payment of cash dividends on common stock at December 31, 1999, were as
follows:
-------------------- ------------------ --- --------------
Retained Restricted
Earnings Amount
------------------ --------------
(in millions)
ALABAMA $1,225 $ 796
GEORGIA 1,778 897
GULF 163 127
MISSISSIPPI 172 118
SAVANNAH 111 68
Consolidated 4,232 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-46 and
II-47.
ALABAMA. Reference is made to information under the heading "Selected
Financial and Operating Data," contained herein at pages II-78 and II-79.
GEORGIA. Reference is made to information under the heading "Selected Financial
and Operating Data," contained herein at pages II-111 and II-112.
GULF. Reference is made to information under the heading "Selected Financial
and Operating Data," contained herein at pages II-140 and II-141.
MISSISSIPPI. Reference is made to information under the heading "Selected
Financial and Operating Data," contained herein at pages II-169 and II-170.
SAVANNAH. Reference is made to information under the heading "Selected
Financial and Operating Data," contained herein at pages II-195 and II-196.
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-51 through II-58.
GEORGIA. Reference is made to information under the heading "Management's
Discussion and Analysis of Results of Operations and Financial Condition,"
contained herein at pages II-83 through II-90.
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-116 through II-123.
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-145 through II-151.
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-174 through II-180.
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 II-31 through II-32, respectively.
Reference is also made to "Management's Discussion and Analysis - Exposure to
Market Risks" in Item 7 of ALABAMA, GEORGIA, GULF, MISSISSIPPI and SAVANNAH
contained herein at pages II-55, II-87, II-120, II-148, and II-177,
respectively.
II-2
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO 1999 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, 1999, 1998 and 1997.................................. II-20
Consolidated Statements of Cash Flows for the Years Ended December 31, 1999, 1998 and 1997.............................. II-21
Consolidated Balance Sheets at December 31, 1999 and 1998............................................................... II-22
Consolidated Statements of Capitalization at December 31, 1999 and 1998................................................. II-24
Consolidated Statements of Common Stockholders' Equity for the Years Ended
December 31, 1999, 1998 and 1997.................................................................................... II-26
Consolidated Statements of Comprehensive Income for the Years Ended
December 31, 1999, 1998 and 1997.................................................................................... II-26
Notes to Financial Statements........................................................................................... II-27
ALABAMA:
Report of Independent Public Accountants .............................................................................. II-50
Statements of Income for the Years Ended December 31, 1999, 1998 and 1997............................................... II-59
Statements of Cash Flows for the Years Ended December 31, 1999, 1998 and 1997........................................... II-60
Balance Sheets at December 31, 1999 and 1998 ........................................................................... II-61
Statements of Capitalization at December 31, 1999 and 1998 ............................................................. II-63
Statements of Common Stockholder's Equity for the Years Ended
December 31, 1999, 1998 and 1997..................................................................................... II-65
Notes to Financial Statements........................................................................................... II-66
GEORGIA:
Report of Independent Public Accountants................................................................................ II-82
Statements of Income for the Years Ended December 31, 1999, 1998 and 1997............................................... II-91
Statements of Cash Flows for the Years Ended December 31, 1999, 1998 and 1997........................................... II-92
Balance Sheets at December 31, 1999 and 1998 ........................................................................... II-93
Statements of Capitalization at December 31, 1999 and 1998 ............................................................. II-95
Statements of Common Stockholder's Equity for the Years Ended
December 31, 1999, 1998 and 1997..................................................................................... II-97
Notes to Financial Statements........................................................................................... II-98
GULF:
Report of Independent Public Accountants................................................................................ II-115
Statements of Income for the Years Ended December 31, 1999, 1998 and 1997............................................... II-124
Statements of Cash Flows for the Years Ended December 31, 1999, 1998 and 1997........................................... II-125
Balance Sheets at December 31, 1999 and 1998 ........................................................................... II-126
Statements of Capitalization at December 31, 1999 and 1998 ............................................................. II-128
Statements of Common Stockholder's Equity for the Years Ended
December 31, 1999, 1998 and 1997..................................................................................... II-129
Notes to Financial Statements........................................................................................... II-130
II-3
Page
MISSISSIPPI:
Report of Independent Public Accountants................................................................................ II-144
Statements of Income for the Years Ended December 31, 1999, 1998 and 1997............................................... II-152
Statements of Cash Flows for the Years Ended December 31, 1999, 1998 and 1997........................................... II-153
Balance Sheets at December 31, 1999 and 1998 ........................................................................... II-154
Statements of Capitalization at December 31, 1999 and 1998 ............................................................. II-156
Statements of Common Stockholder's Equity for the Years Ended
December 31, 1999, 1998 and 1997..................................................................................... II-158
Notes to Financial Statements........................................................................................... II-159
SAVANNAH:
Report of Independent Public Accountants................................................................................ II-173
Statements of Income for the Years Ended December 31, 1999, 1998 and 1997............................................... II-181
Statements of Cash Flows for the Years Ended December 31, 1999, 1998 and 1997........................................... II-182
Balance Sheets at December 31, 1999 and 1998 ........................................................................... II-183
Statements of Capitalization at December 31, 1999 and 1998 ............................................................. II-185
Statements of Common Stockholder's Equity for the Years Ended
December 31, 1999, 1998 and 1997..................................................................................... II-186
Notes to Financial Statements........................................................................................... II-187
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
None.
II-4
THE SOUTHERN COMPANY
AND SUBSIDIARY COMPANIES
FINANCIAL SECTION
II-5
MANAGEMENT'S REPORT
Southern Company and Subsidiary Companies 1999 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 and Chief Executive Officer
/s/W. L. Westbrook
W. L. Westbrook
Financial Vice President, Chief Financial Officer,
and Treasurer
February 16, 2000
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, 1999 and 1998, and the related
consolidated statements of income, comprehensive income, common stockholders'
equity, and cash flows for each of the three years in the period ended
December 31, 1999. 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 auditing standards generally
accepted in the United States. 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-45) referred to above present fairly, in all material respects, the financial
position of Southern Company and subsidiary companies as of December 31, 1999
and 1998, and the results of their operations and their cash flows for each of
the three years in the period ended December 31, 1999, in conformity with
accounting principles generally accepted in the United States.
/s/Arthur Andersen LLP
Atlanta, Georgia
February 16, 2000
II-7
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Southern Company and Subsidiary Companies 1999 Annual Report
Results of Operations
Overview of Consolidated Earnings
Southern Company's 1999 earnings of $1.28 billion or $1.86 per share established
a new record high. Higher earnings were primarily driven by strong growth in the
competitive energy supply business outside the southeastern United States. The
traditional business of selling electricity in the Southeast continued to remain
strong. However, reported earnings in both 1999 and 1998 reflected significant
items not related to the normal day-to-day business activities. After excluding
these items, earnings for 1999 were $1.30 billion or $1.90 per share compared
with $1.23 billion or $1.76 per share in 1998.
Southern Energy, Inc. (Southern Energy) is the Southern Company subsidiary
that owns and manages its international operations and develops and owns its
competitive energy supply business in North America outside the Southeast.
Southern Energy earnings accounted for approximately 26 percent of Southern
Company's reported net income in 1999. Amortization of goodwill related to
Southern Energy investments reduced earnings per share by 5 cents in 1999 and 4
cents in 1998.
A reconciliation of reported earnings to earnings excluding non-day to day
business items and the related explanations are as follows:
Consolidated Earnings
Net Income Per Share
------------- --------------
1999 1998 1999 1998
------------- --------------
(in millions)
Earnings as reported $1,276 $ 977 $1.86 $1.40
- ---------------------------------------------------------------
Gain on asset sale (78) - (.11) -
Write down of assets:
South American
investments - 200 - .29
Rocky Mountain
plant - 21 - .03
Mobile Energy 69 - .10 -
Work force reductions 50 20 .07 .03
Other (14) 7 (.02) .01
- ---------------------------------------------------------------
Total adjustments 27 248 .04 .36
- ---------------------------------------------------------------
Earnings as adjusted $1,303 $1,225 $1.90 $1.76
===============================================================
Amount and
percent change $78 6.4% $0.14 8.0%
- ---------------------------------------------------------------
Southern Energy sold the supply business of South Western Electricity in
1999, and the remaining distribution business was renamed Western Power
Distribution. In 1999, Southern Energy recorded an asset impairment related to
Mobile Energy Services -- see Note 3 to the financial statements. Southern
Energy's write down of assets in 1998 related to investments in Argentina and
Chile not meeting financial expectations, which resulted in an announced plan to
sell these assets. In 1998, Georgia Power wrote down its investment in the Rocky
Mountain pumped storage hydroelectric plant as a result of a settlement related
to its 1998 retail rate proceeding. Work force reduction programs began in late
1999 for Bewag, a German utility in which Southern Energy has a 26 percent
ownership interest. Also, the traditional business recorded costs related to
workforce reductions in 1998.
Discussion of the results of operations are separated between the traditional
business of the integrated Southeast utilities and Southern Energy.
Integrated Southeast Utilities
The five integrated Southeast utilities provide electric service in four states.
These utilities are Alabama Power, Georgia Power, Gulf Power, Mississippi Power,
and Savannah Electric. They comprise Southern Company's principal business
segment with earnings of $1.1 billion in 1999. A condensed income statement for
this business segment is as follows:
Increase (Decrease)
Amount From Prior Year
------ --------------------
1999 1999 1998
- ---------------------------------------------------------------
(in millions)
Operating revenues $9,125 $(238) $675
- ---------------------------------------------------------------
Fuel 2,328 7 117
Purchased power 409 13 182
Other operation
and maintenance 2,430 4 252
Depreciation
and amortization 961 (328) 134
Taxes other than
income taxes 521 13 7
Write down of assets - (34) 34
- ---------------------------------------------------------------
Total operating expenses 6,649 (325) 726
- ---------------------------------------------------------------
Operating income 2,476 87 (51)
Other income (8) (84) 93
- ---------------------------------------------------------------
Earnings before
interest and taxes 2,468 3 42
Interest charges and other 720 41 48
Income taxes 675 (28) 16
- ---------------------------------------------------------------
Net income $1,073 $ (10) $ (22)
===============================================================
II-8
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 1999 Annual Report
Revenues
Operating revenues changed in 1999 and 1998 as a result of the following
factors:
Increase (Decrease)
From Prior Year
------------------
1999 1998
- ---------------------------------------------------------------
(in millions)
Retail --
Growth and price changes $ 166 $258
Rate reductions (352) -
Weather (86) 178
Fuel cost recovery and other 86 189
- ---------------------------------------------------------------
Total retail (186) 625
- ---------------------------------------------------------------
Sales for resale --
Within service area (24) (2)
Outside service area (49) 12
- ---------------------------------------------------------------
Total sales for resale (73) 10
Other operating revenues 21 40
- ---------------------------------------------------------------
Operating revenues $(238) $675
===============================================================
Percent change (2.5)% 7.8%
- ---------------------------------------------------------------
Retail revenues of $8.1 billion in 1999 declined as a result of a Georgia
Power rate reduction effective January 1999. For additional information, see
Note 3 to the financial statements under "Georgia Power 1998 Retail Rate Order."
Customer growth in the Southeast somewhat offset the rate decrease. In 1998,
retail revenues increased sharply, up 8.2 percent compared with the prior year.
Continued growth in the traditional service area and the positive impact of
weather on energy sales were the predominant factors causing the rise in
revenues in 1998. 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 $350 million in 1999,
down 6.5 percent from the prior year. This sharp decline resulted primarily from
supplying less electricity under contractual agreements with certain wholesale
customers in 1999, and a slight reduction in these revenues is expected in 2000.
Revenues from sales for resale within the service area were $374 million in
1998, down 0.7 percent from the prior year.
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. Revenue from long-term unit power contracts have both a capacity and
energy component. 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 of the unit power contracts were as
follows:
1999 1998 1997
- ---------------------------------------------------------------
(in millions)
Capacity $174 $196 $203
Energy 157 152 183
- ---------------------------------------------------------------
Total $331 $348 $386
===============================================================
Capacity revenues in 1999 and 1998 declined each year as a result of
adjustments and true-ups related to contractual pricing. No significant declines
in capacity are scheduled until the termination of the contracts in 2010.
Energy Sales
The changes in revenues for the traditional business in the Southeast are
influenced heavily by the amount of energy sold each year. Kilowatt-hour sales
for 1999 and the percent change by year were as follows:
Amount Percent Change
(billions of ------- ----------------------------
kilowatt-hours) 1999 1999 1998 1997
- ----------------------------------------------------------------
Residential 43.4 (0.2)% 10.9% (2.2)%
Commercial 43.4 4.0 7.2 2.5
Industrial 56.2 1.6 2.1 2.6
Other 0.9 1.6 3.1 (1.1)
-----
Total retail 143.9 1.7 6.2 1.1
Sales for resale --
Within service area 9.4 (4.1) (0.4) (9.6)
Outside service area 13.0 (0.4) (5.6) 27.7
-----
Total 166.3 1.2 4.7 2.2
================================================================
The rate of increase in 1999 total retail energy sales was significantly
lower than in 1998. Although the total number of residential customers served
increased by 61,000 during the year, residential energy sales experienced a
decline as a result of milder weather in 1999. The rate of growth in 1998 retail
II-9
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 1999 Annual Report
energy sales was the highest one-year increase since 1986. Also, residential
energy sales registered the highest annual increase in over two decades as a
result of hotter-than-normal weather. Commercial and industrial sales, both in
1999 and 1998, 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 in the southeastern United States.
Energy sales to retail customers are projected to increase at an average annual
rate of 2.2 percent during the period 2000 through 2010.
Sales to customers outside the service area declined by 0.4 percent in 1999
and by 5.6 percent in 1998 when compared with the respective prior year. The
declines in sales were influenced by weather and 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
Operating expenses of $6.6 billion for 1999 decreased $325 million. This decline
was primarily attributable to $308 million less accelerated depreciation of
plant being recorded in accordance with the 1998 Georgia Power rate order as
referred to earlier. The costs to produce and deliver electricity for the
traditional business in the Southeast for 1999 increased by $68 million to meet
higher energy demands. All other operating and maintenance expenses declined by
$44 million as a result of continued cost control programs.
In 1998, operating expenses of $7.0 billion increased $726 million compared
with the prior year. The costs to produce and deliver electricity for the
traditional business in 1998 increased by $359 million to meet higher energy
demands. Non-production operation and maintenance expenses increased $192
million in 1998. Accelerated depreciation of certain assets increased $157
million when compared with 1997.
Fuel costs constitute the single largest expense for the integrated Southeast
utilities. 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
traditional business service area -- were as follows:
1999 1998 1997
- ----------------------------------------------------------------
Total generation
(billions of kilowatt-hours) 165 164 160
Sources of generation
(percent) --
Coal 78 77 77
Nuclear 17 16 17
Hydro 2 4 4
Oil and gas 3 3 2
Average cost of fuel per net
kilowatt-hour generated
(cents) -- 1.45 1.48 1.46
- ----------------------------------------------------------------
Total fuel and purchased power costs of $2.7 billion in 1999 increased only
$20 million while total energy sales increased 2.0 billion kilowatt-hours
compared with the amounts recorded in 1998. Continued efforts to control energy
costs helped lower the average cost of fuel per net kilowatt-hour generated in
1999. In 1998, fuel and purchased power costs increased $299 million as a result
of 7.4 billion more kilowatt-hours being sold than in 1997.
Total interest charges and other financing costs in 1999 decreased $41
million from amounts reported in the previous year. The decline reflected
additional refinancing of debt in 1999. Alabama Power and Georgia Power -- in
accordance with their respective rate making procedures -- recorded additional
accelerated amortization of premium on reacquired debt of $85 million in 1999,
$33 million in 1998, and no additional amounts in 1997. Interest charges and
other financing costs increased in 1998 as a result of the additional
amortization being recorded.
II-10
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 1999 Annual Report
Southern Energy
Southern Energy's domestic and international operations provided much of
Southern Company's strong financial growth in 1999. A condensed income statement
for Southern Company's other significant business segment is as follows:
Increase (Decrease)
Amount From Prior Year
------- ---------------------
1999 1999 1998
- ----------------------------------------------------------------
(in millions)
Operating revenues $2,268 $ 365 $(1,934)
- ----------------------------------------------------------------
Fuel and purchased power 937 38 (1,996)
Other operation
and maintenance 477 131 (22)
Depreciation
and amortization 322 88 40
Taxes other than
income taxes 89 2 16
Write down of assets 69 (239) 308
- ----------------------------------------------------------------
Total operating expenses 1,894 20 (1,654)
- ----------------------------------------------------------------
Operating income 374 345 (280)
Gain on asset sales 313 272 17
Other income 433 99 100
- ----------------------------------------------------------------
Earnings before
interest and taxes 1,120 716 (163)
Interest charges and other 666 178 97
Income taxes 126 249 (298)
- ----------------------------------------------------------------
Net income $ 328 $ 289 $ 38
================================================================
Southern Energy recorded several significant items not related to the normal
day-to-day business activities in both 1999 and 1998 as discussed earlier.
Excluding these one time items, earnings were $355 million and $239 million in
1999 and 1998, respectively.
Southern Energy develops and owns competitive energy supply businesses around
the world. Domestic assets include a 60 percent interest in a top ten energy
trading and marketing business. International operations are principally located
in China, Philippines, England, Germany, Netherlands, Brazil, Chile, Argentina,
Bahamas, and Trinidad and Tobago.
Earnings by major geographical area -- excluding the one time items -- are as
follows:
Increase (Decrease)
Amount From Prior Year
------ --------------------
1999 1999 1998
- ----------------------------------------------------------------
(in millions)
Asia $175 $107 $27
Europe 142 9 62
North America 81 78 14
South America 1 (16) 8
Corporate and other (44) (62) 16
- ----------------------------------------------------------------
Revenues in 1999 increased 19 percent primarily as a result of acquisitions
in North America of some 6,100 megawatts of generating facilities in late 1998
and in 1999. Also, approximately 1,100 megawatts of owned generating capacity in
Asia went into commercial operation in late 1999.
In 1998, Southern Energy's revenues declined because its energy trading and
marketing operations -- $2.0 billion in 1997 -- were deconsolidated as of
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 1999 and 1998. Southern Energy's revenues in 1998 of
$1.9 billion increased by $48 million compared with comparable revenues in 1997
that exclude energy trading and marketing. This increase resulted primarily from
operations of assets obtained in domestic acquisitions.
The decline in 1998 operating expenses 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. Operating expenses and
interest charges increased in 1999 as a result of acquisitions and new
facilities being placed into service.
II-11
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 1999 Annual Report
Effects of Inflation
Southern Company's traditional business of the integrated Southeast utilities 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 lives. 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. The two major factors are the growth of
Southern Energy's operations and the ability of the integrated Southeast
utilities to achieve energy sales growth in a less regulated, more competitive
environment.
The traditional business or the five Southeast utilities currently operate as
vertically integrated companies providing electricity to customers within the
traditional service area of the southeastern United States. Prices for
electricity provided to retail customers are set by state public service
commissions under cost-based regulatory principles. Retail rates and earnings
are reviewed and adjusted periodically within certain limitations based on
earned return on equity. See Note 3 to the financial statements for additional
information about these and other regulatory matters.
Future earnings for the traditional business in the near term will depend
upon growth in energy sales, which is subject to a number of factors. These
factors include weather, competition, new short and long-term contracts with
neighboring utilities, energy conservation practiced by customers, the
elasticity of demand, and the rate of economic growth in the traditional 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's integrated
utilities are aggressively working to maintain and expand their 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 continues to
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 a company to recover its investments, including the regulatory
assets described in Note 1 to the financial statements, could have a material
adverse effect on financial condition and results of operations.
Continuing to be a low-cost producer could provide opportunities to increase
market share and profitability in markets that evolve with changing regulation.
Conversely, if Southern Company's integrated Southeast utilities do not remain
low-cost producers and provide quality service, then energy sales growth could
be limited, and this could significantly erode earnings.
II-12
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 1999 Annual Report
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.
On December 20, 1999, the Federal Energy Regulatory Commission (FERC) issued
its final rule on Regional Transmission Organizations (RTOs). The order
encourages utilities owning transmission systems to form RTOs on a voluntary
basis. To facilitate the development of RTOs, the FERC will convene regional
conferences for utilities, customers, and other members of the public to discuss
the formation of RTOs. In addition to participating in the regional conferences,
utilities owning transmission systems, including Southern Company, are required
to make a filing by October 15, 2000. The filing must contain either a proposal
for RTO participation or a description of the efforts made to participate in an
RTO, the reasons for non-participation, any obstacles to participation, and any
plans for further work toward participation. The RTOs that are proposed in the
filings should be operational by December 15, 2001. Southern Company is
evaluating this issue and formulating its response. The outcome of this matter
cannot now be determined.
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 trading and marketing,
distribution, and stand-alone generation. As the energy marketplace evolves,
Southern Energy continues to position the company as a major competitor. At
December 31, 1999, Southern Energy's total assets were $13.9 billion, and it had
ownership or control of over 14,000 megawatts of generating capacity. It has
another 5,000 megawatts under construction or advanced development.
In 1999, Southern Energy refined its business strategy to focus on a few key
geographic regions of the world. Its Asian subsidiary will focus primarily on
China, India, and the Philippines, while also pursuing opportunities in more
developed countries such as Australia and Singapore. In Europe, Southern Energy
will concentrate efforts in the countries that make up the North-South corridor
of continental Europe -- Scandinavia, Italy, Switzerland, Germany, the
Netherlands, and select countries in Eastern Europe. In South America, the
company is in the process of exiting Argentina and Chile and is reviewing
whether or not it will pursue additional opportunities in Brazil. In North
America, the company will target its efforts on four U.S. regions -- the
Northeast, the Midwest, Texas/Louisiana, and California/Desert Southwest -- and
also will pursue opportunities in Canada.
In the United States, Southern Energy plans to acquire, build, or gain access
to some 20,000 megawatts of generating capacity over the next several years in
order to ensure its success in the evolving competitive wholesale energy supply
business. Currently, Southern Energy owns or controls approximately 8,500
megawatts of capacity in the four targeted regions, with an additional 4,100
megawatts under construction or advanced development. All of these assets will
be closely linked with Southern Energy's energy trading and marketing business,
Southern Company Energy Marketing (SCEM).
In 1998, Southern Energy and Vastar completed the combination of their energy
trading and marketing activities to form a joint venture, SCEM. SCEM has the
rights to market virtually all of Vastar's natural gas production over a period
of 10 years. Southern Energy's current ownership interest in SCEM is 60 percent.
On July 1, 2001, this ownership interest will automatically increase to 75
percent. Southern Energy has the right -- exercisable during fiscal year 2002 --
to acquire an additional 5 percent interest from Vastar for $80 million. Also,
Vastar has the right -- exercisable in the period from December 1, 2002 through
January 2, 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.
II-13
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 1999 Annual Report
Southern Company has filed with the Securities and Exchange Commission (SEC)
a request to invest up to nearly $6 billion in Southern Energy's domestic and
international business. The current SEC authority is $4.1 billion, of which $2.7
billion has been invested as of December 31, 1999.
Southern Company is involved in various matters being litigated. See Note 3
to the financial statements for information regarding material issues that could
possibly affect future earnings.
Compliance costs related to 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 integrated Southeast utilities 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 Standard
The FASB has issued Statement No. 133, Accounting for Derivative Instruments and
Hedging Activities, which must be adopted by January 2001. 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.
Year 2000 Challenge
The work undertaken by Southern Company subsidiaries to prepare critical
computer systems and other date sensitive devices to function correctly in the
Year 2000 was successful. There were no material incidents reported and no
disruption of electric service within the service area of the traditional
business. There were no reports of significant events regarding third parties
that impacted revenues or expenses.
For the traditional business, original projected total costs for Year 2000
readiness were approximately $91 million. Final projected costs are $94 million
of which $3 million is projected to be spent in 2000 and $6 million was billed
to non-affiliated companies. These costs include labor necessary to identify,
test, and renovate affected devices and systems, and costs for reporting
requirements to state and federal agencies. From its inception through December
31, 1999, the Year 2000 program costs, recognized primarily as expense, amounted
to $85 million based on Southern Company's ownership interest.
Also, Southern Energy experienced no material incidents or disruption of
electric service for its domestic and international operations. In addition to
the traditional business costs, Southern Energy's final costs for Year 2000
readiness were approximately $17 million -- based on their ownership interest.
Southern Energy's original projected costs were $24 million.
II-14
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 1999 Annual Report
FINANCIAL CONDITION
Overview
Southern Company's financial condition continues to remain strong. In 1999, the
integrated Southeast utilities' earnings were at the high end of their allowed
range of return on equity, and Southern Energy reported strong earnings growth
in 1999. These factors drove the record consolidated net income of $1.3 billion
in 1999. Consolidated net income -- excluding non-recurring charges -- in 1999
increased $78 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 down to 50 percent. The
quarterly dividend declared in January 2000 continued to be 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. This policy supports Southern Company's
strategic goal to become the best investment in the electric utility business.
Gross property additions to utility plant were $2.6 billion in 1999. The
majority of funds needed for gross property additions since 1996 has been
provided from operating activities. Southern Energy acquired $1.3 billion of
generating assets in 1999 and sold the supply system of South Western
Electricity -- Southern Energy owned 49 percent -- for $256 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 valuation 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 $27 million at December 31, 1999. Based on the
company's overall interest rate exposure at December 31, 1999, 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. To hedge its
net investment in these countries, 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. As a result of these swaps,
a 10 percent 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, Chile, Trinidad and
Tobago, 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.
II-15
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 1999 Annual Report
Also, the company has currency exposure related to its investment in
Companhia Energetica de Minas Gerais (CEMIG) which has not been hedged. Revenues
at CEMIG and dividends from CEMIG are denominated in Brazilian reals; however, a
significant portion of debt incurred to finance CEMIG is required to be repaid
in other currencies. The devaluation of the real in January 1999 resulted in a
net reduction in other comprehensive income of $83 million.
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, natural gas, and energy trading business in North
America and Europe. The North American trading business 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, 1999,
outstanding guarantees related to the estimated fair value of net contractual
commitments were approximately $146 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 were
$12.0 billion and $11.9 billion for 1999, respectively; and $9.2 billion and
$9.1 billion for 1998, respectively.
In 1999, Southern Energy created a European trading operation in Amsterdam.
The business provides risk management services associated with the energy
industry to its customers in the European market.
To estimate and manage the market risk of its trading and marketing
portfolios, the trading businesses employ 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 5 days to 3 months, 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 VAR analysis of the overall commodity price
risk exposure of the trading businesses at December 31, 1999, management does
not anticipate a materially adverse effect on the company's consolidated
financial statements as a result of market fluctuations.
Due to cost-based rate regulations, the integrated Southeast utilities 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 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, 1999, 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."
Capital Structure
Southern Company's ratio of common equity to total capitalization -- including
short-term debt -- was 32.7 percent in 1999, compared with 37.4 percent in 1998,
and 38.6 percent in 1997.
II-16
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 1999 Annual Report
During 1999, the integrated Southeast utilities sold, through public
authorities, $349 million of pollution control revenue bonds. In addition,
capital and preferred securities of $250 million were issued in 1999. The
companies continued to reduce financing costs by retiring higher-cost bonds and
preferred stock. Retirements of bonds, including maturities, totaled $1.2
billion during 1999, $1.7 billion during 1998, and $507 million during 1997. As
a result, the composite interest rate on long-term debt decreased from 6.9
percent at December 31, 1996 to 6.5 percent at December 31, 1999. Retirements of
preferred stock totaled $86 million during 1999, $239 million during 1998, and
$660 million during 1997.
In April 1999, Southern Company announced the repurchase of up to 50 million
shares of its common stock over a two-year period through open market or
privately negotiated transactions. The program did not establish a target stock
price or timetable for specific repurchases. Under this program, 32.8 million
shares were repurchased through December 31, 1999. Funding for the program was
provided from Southern Company's commercial paper program. At the close of 1999,
the company's common stock market value was 23 1/2 per share, compared with book
value of $13.82 per share. The market-to-book value ratio was 170 percent at the
end of 1999, compared with 207 percent at year-end 1998, and 186 percent at
year-end 1997.
Capital Requirements for Construction
The construction program of Southern Company is budgeted at $3.0 billion for
2000, $3.8 billion for 2001, and $3.9 billion for 2002. 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 integrated Southeast utilities have approximately 5,200 megawatts of
combustion turbine generating capacity scheduled to be placed in service by
2002. Approximately 1,400 megawatts of this new capacity will be dedicated to
the wholesale market. Southern Energy has approximately 1,000 megawatts of owned
capacity under construction. Significant construction of transmission and
distribution facilities and upgrading of generating plants will be continuing
for the traditional business in the Southeast.
Other Capital Requirements
In addition to the funds needed for the construction program, approximately $2.1
billion will be required by the end of 2002 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.
Environmental Matters
On November 3, 1999, the Environmental Protection Agency (EPA) brought a civil
action in the U.S. District Court against Alabama Power, Georgia Power, and the
system service company. The complaint alleges violations of the prevention of
significant deterioration and new source review provisions of the Clean Air Act
with respect to five coal-fired generating facilities in Alabama and Georgia.
The civil action requests penalties and injunctive relief, including an order
requiring the installation of the best available control technology at the
affected units. The EPA concurrently issued to the integrated Southeast
utilities a notice of violation related to 10 generating facilities, which
includes the five facilities mentioned previously. In early 2000, the EPA filed
a motion to amend its complaint to add the violations alleged in its notice of
violation, and to add Gulf Power, Mississippi Power, and Savannah Electric as
defendants. The complaint and notice of violation are similar to those
brought against and issued to several other electric utilities. These complaints
and notices of violation allege that the utilities had failed to secure
necessary permits or install additional pollution equipment when performing
maintenance and construction at coal burning plants constructed or under
construction prior to 1978. Southern Company believes that its integrated
utilities complied with applicable laws and the EPA's regulations and
interpretations in effect at the time the work in question took place. The Clean
Air Act authorizes civil penalties of up to $27,500 per day per violation at
each generating unit. Prior to January 30, 1997, the penalty was $25,000 per
day. An adverse outcome of this matter could require substantial capital
expenditures that cannot be determined at this time and possibly require payment
of substantial penalties. This could affect future results of operations, cash
flows, and possibly financial condition if such costs are not recovered through
regulated rates.
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.
II-17
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 1999 Annual Report
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 nitrogen oxide and sulfur dioxide
emissions compliance totaled approximately $300 million.
For Phase II sulfur dioxide compliance, Southern Company currently uses
emission allowances and increased fuel switching. Also, equipment to control
nitrogen oxide emissions was installed on additional system fossil-fired units
as necessary to meet Phase II limits and ozone non-attainment requirements for
metropolitan Atlanta through 2000. Compliance for Phase II and initial ozone
non-attainment requirements increased total estimated construction expenditures
by approximately $105 million.
The States of Georgia and Alabama have proposed or drafted rules to address
one-hour ozone non-attainment in the Atlanta and Birmingham areas. Additional
nitrogen oxide emission controls will be required on certain generating plants
by May 1, 2003. It is expected that seven generating plants will be affected in
the Atlanta area and two plants in the Birmingham area. Additional construction
expenditures for compliance with these new rules are currently estimated at
approximately $850 million.
A significant portion of costs related to the acid rain and ozone
nonattainment 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 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 reduction rule to the states for implementation. The final rule affects 22
states, including Alabama and Georgia. The EPA's July 1997 standards and the
September 1998 rule are being challenged in the courts by several states and
industry groups. Implementation of the final state rules for these three
initiatives could require substantial further reductions in nitrogen oxide and
sulfur dioxide emissions from fossil-fired generating facilities and other
industries in these states. Additional compliance costs and capital expenditures
resulting from the implementation of these rules and standards 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: additional controls for hazardous
air pollutant emissions; control strategies to reduce regional haze; and
hazardous waste disposal requirements. The impact of any 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 $4 million in 1999, $6 million in 1998, and $4 million in 1997.
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
II-18
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 1999 Annual Report
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 2000 -- 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 integrated Southeast utilities 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. In recent years, financings primarily have utilized unsecured debt and
trust preferred securities.
To meet short-term cash needs and contingencies, Southern Company had at the
beginning of 2000 approximately $466 million of cash and cash equivalents and
$5.7 billion of unused credit arrangements with banks.
Cautionary Statement Regarding Forward-Looking
Information
Southern Company's 1999 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 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; 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 Southern Energy 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, 1999, 1998, and 1997
Southern Company and Subsidiary Companies 1999 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------
1999 1998 1997
- -----------------------------------------------------------------------------------------------------------------------------
(in millions)
Operating Revenues:
Retail sales $ 8,086 $ 8,272 $ 7,647
Sales for resale 823 896 886
Southern Energy revenues 2,268 1,903 3,837
Other revenues 408 332 241
- -----------------------------------------------------------------------------------------------------------------------------
Total operating revenues 11,585 11,403 12,611
- -----------------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
Fuel 2,720 2,371 2,281
Purchased power 954 1,243 3,033
Other 2,199 2,112 1,930
Maintenance 945 887 763
Depreciation and amortization 1,307 1,539 1,367
Taxes other than income taxes 612 599 572
Write down of assets 69 342 -
- -----------------------------------------------------------------------------------------------------------------------------
Total operating expenses 8,806 9,093 9,946
- -----------------------------------------------------------------------------------------------------------------------------
Operating Income 2,779 2,310 2,665
Other Income:
Interest income 164 243 152
Gain on asset sales 315 59 24
Equity in earnings of unconsolidated subsidiaries 94 123 35
Other, net 94 (2) -
- -----------------------------------------------------------------------------------------------------------------------------
Earnings Before Interest, Minority Interests, and Income Taxes 3,446 2,733 2,876
- -----------------------------------------------------------------------------------------------------------------------------
Interest Charges and Other:
Interest on long-term debt 698 712 678
Interest on notes payable 183 108 112
Amortization of debt discount, premium, and expense, net 125 65 34
Other interest charges 53 68 49
Minority interests in subsidiaries 183 80 29
Distributions on capital and preferred securities of subsidiaries 182 149 120
Preferred dividends of subsidiaries 20 25 43
- -----------------------------------------------------------------------------------------------------------------------------
Total interest charges and other, net 1,444 1,207 1,065
- -----------------------------------------------------------------------------------------------------------------------------
Earnings Before Income Taxes 2,002 1,526 1,811
Income taxes 726 549 839
- -----------------------------------------------------------------------------------------------------------------------------
Consolidated Net Income $ 1,276 $ 977 $ 972
=============================================================================================================================
Common Stock Data:
Average number of shares of common stock outstanding (in millions) 685 697 685
Basic and diluted earnings per share of common stock $1.86 $1.40 $1.42
Cash dividends paid per share of common stock $1.34 $1.34 $1.30
- -----------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
II-20
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1999, 1998, and 1997
Southern Company and Subsidiary Companies 1999 Annual Report
- --------------------------------------------------------------------------------------------------------------------------
1999 1998 1997
- ---------------------------------------------------------------------------------------------------------------------------
(in millions)
Operating Activities:
Consolidated net income $ 1,276 $ 977 $ 972
Adjustments to reconcile consolidated net income
to net cash provided from operating activities --
Depreciation and amortization 1,522 1,773 1,592
Deferred income taxes and investment tax credits 137 (22) (5)
Gain on asset sales (315) (61) (25)
Write down of assets 69 342 -
Equity in earnings of unconsolidated subsidiaries (94) (123) (35)
Other, net 172 (76) (29)
Changes in certain current assets and liabilities
excluding effects from acquisitions --
Receivables, net (213) 151 (229)
Fossil fuel stock (26) (35) 53
Materials and supplies (50) (10) 21
Accounts payable (147) (17) 138
Other 392 (151) 172
- ---------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities 2,723 2,748 2,625
- ---------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (2,560) (2,005) (1,859)
Southern Energy business and asset acquisitions, net of cash acquired (1,800) (998) (2,925)
Sales of property 285 281 32
Other (139) 86 (13)
- ---------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities (4,214) (2,636) (4,765)
- ---------------------------------------------------------------------------------------------------------------------------
Financing Activities:
Increase (decrease) in notes payable, net 2,131 (353) 509
Proceeds --
Other long-term debt 2,646 2,973 2,499
Capital and preferred securities 250 435 1,321
Preferred stock - 200 -
Common stock 24 234 360
Redemptions --
First mortgage bonds (890) (1,487) (168)
Other long-term debt (957) (599) (802)
Capital and preferred securities (100) - -
Preferred stock (86) (239) (660)
Common stock repurchased (862) (125) -
Payment of common stock dividends (921) (933) (889)
Other (150) 53 126
- ---------------------------------------------------------------------------------------------------------------------------
Net cash provided from (used for) financing activities 1,085 159 2,296
- ---------------------------------------------------------------------------------------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents (406) 271 156
Cash and Cash Equivalents at Beginning of Year 872 601 445
- ---------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 466 $ 872 $ 601
===========================================================================================================================
Supplemental Cash Flow Information:
Cash paid during the year for --
Interest (net of amount capitalized) $1,011 $998 $876
Income taxes $642 $839 $823
Southern Energy business and asset acquisitions --
Fair value of assets acquired $1,832 $1,072 $4,768
Less cash paid 1,800 998 2,925
- ---------------------------------------------------------------------------------------------------------------------------
Liabilities assumed $ 32 $ 74 $1,843
===========================================================================================================================
The accompanying notes are an integral part of these statements.
II-21
CONSOLIDATED BALANCE SHEETS
At December 31, 1999 and 1998
Southern Company and Subsidiary Companies 1999 Annual Report
- -----------------------------------------------------------------------------------------------------------------------
Assets 1999 1998
- -----------------------------------------------------------------------------------------------------------------------
(in millions)
Current Assets:
Cash and cash equivalents $ 466 $ 872
Special deposits 72 87
Receivables, less accumulated provisions for uncollectible accounts
of $59 million in 1999 and $113 million in 1998 1,652 1,692
Unrecovered retail fuel clause revenue 244 105
Fossil fuel stock, at average cost 311 252
Materials and supplies, at average cost 585 515
Other 199 183
- -----------------------------------------------------------------------------------------------------------------------
Total current assets 3,529 3,706
- -----------------------------------------------------------------------------------------------------------------------
Property, Plant, and Equipment:
In service 36,763 35,169
Less accumulated provision for depreciation 14,076 13,239
- -----------------------------------------------------------------------------------------------------------------------
22,687 21,930
Nuclear fuel, at amortized cost 227 217
Construction work in progress 1,630 1,782
- -----------------------------------------------------------------------------------------------------------------------
Total property, plant, and equipment 24,544 23,929
- -----------------------------------------------------------------------------------------------------------------------
Other Property and Investments:
Equity investments in unconsolidated subsidiaries 1,376 1,549
Property rights, net of accumulated amortization of
$227 million in 1999 and $169 million in 1998 2,202 1,185
Goodwill, net of accumulated amortization of
$164 million in 1999 and $106 million in 1998 2,106 2,125
Other intangibles, net of accumulated amortization of
$13 million in 1999 and $1 million in 1998 447 154
Nuclear decommissioning trusts, at fair value 658 516
Leveraged leases 556 264
Other 580 374
- -----------------------------------------------------------------------------------------------------------------------
Total other property and investments 7,925 6,167
- -----------------------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets:
Deferred charges related to income taxes 987 1,036
Prepaid pension costs 590 491
Debt expense, being amortized 145 129
Premium on reacquired debt, being amortized 217 294
Other 459 439
- -----------------------------------------------------------------------------------------------------------------------
Total deferred charges and other assets 2,398 2,389
- -----------------------------------------------------------------------------------------------------------------------
Total Assets $38,396 $36,191
=======================================================================================================================
The accompanying notes are an integral part of these balance sheets.
II-22
CONSOLIDATED BALANCE SHEETS (continued)
At December 31, 1999 and 1998
Southern Company and Subsidiary Companies 1999 Annual Report
- -----------------------------------------------------------------------------------------------------------------------
Liabilities and Stockholders' Equity 1999 1998
- -----------------------------------------------------------------------------------------------------------------------
(in millions)
Current Liabilities:
Securities due within one year $ 576 $ 1,526
Notes payable 3,915 1,828
Accounts payable 895 1,027
Customer deposits 133 125
Taxes accrued --
Income taxes 155 49
Other 264 299
Interest accrued 281 233
Vacation pay accrued 120 112
Other 794 542
- -----------------------------------------------------------------------------------------------------------------------
Total current liabilities 7,133 5,741
- -----------------------------------------------------------------------------------------------------------------------
Long-term debt (See accompanying statements) 11,747 10,472
- -----------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 4,505 4,481
Deferred credits related to income taxes 640 715
Accumulated deferred investment tax credits 693 723
Employee benefits provisions 513 474
Prepaid capacity revenues 80 96
Other 460 609
- -----------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 6,891 7,098
- -----------------------------------------------------------------------------------------------------------------------
Minority interests in subsidiaries 725 535
- -----------------------------------------------------------------------------------------------------------------------
Company or subsidiary obligated mandatorily redeemable
capital and preferred securities (See accompanying statements) 2,327 2,179
- -----------------------------------------------------------------------------------------------------------------------
Cumulative preferred stock of subsidiaries (See accompanying statements) 369 369
- -----------------------------------------------------------------------------------------------------------------------
Common stockholders' equity (See accompanying statements) 9,204 9,797
- -----------------------------------------------------------------------------------------------------------------------
Total Liabilities and Stockholders' Equity $38,396 $36,191
=======================================================================================================================
Commitments and Contingent Matters (Notes 1, 2, 3, 4, 5, 7, 12, and 13)
- -----------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these balance sheets.
II-23
CONSOLIDATED STATEMENTS OF CAPITALIZATION
At December 31, 1999 and 1998
Southern Company and Subsidiary Companies 1999 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------------
1999 1998 1999 1998
- -----------------------------------------------------------------------------------------------------------------------------------
(in millions) (percent of total)
Long-Term Debt of Subsidiaries:
First mortgage bonds --
Maturity Interest Rates
------- -------------
1999 6.13% to 8.67% $ - $ 373
2000 6.00% to 8.67% 200 209
2001 8.67% - 9
2002 8.67% - 10
2003 6.13% to 8.67% 325 635
2004 6.60% to 8.67% 35 45
2005 through 2009 6.07% to 8.67% 105 165
2010 through 2014 8.67% - 80
2015 through 2019 8.67% - 38
2020 through 2024 7.30% to 9.00% 559 764
2025 through 2026 6.88% to 7.88% 117 137
- -----------------------------------------------------------------------------------------------------------------------------------
Total first mortgage bonds 1,341 2,465
- -----------------------------------------------------------------------------------------------------------------------------------
Long-term notes payable --
6.13% to 11.00% due 1999-2002 - 437
6.38% to 11.00% due 2000-2002 279 -
5.35% to 9.75% due 2003-2004 901 361
5.49% to 10.50% due 2005 760 551
6.80% to 9.70% due 2006 593 582
5.76% to 10.25% due 2007 583 447
3.07% to 10.56% due 2008-2015 1,605 959
6.38% to 8.12% due 2018-2038 801 803
6.63% to 7.13% due 2039-2048 1,029 729
Adjustable rates (3.81% to 8.63% at 1/1/00)
due 1999-2007 1,887 1,958
- -----------------------------------------------------------------------------------------------------------------------------------
Total long-term notes payable 8,438 6,827
- -----------------------------------------------------------------------------------------------------------------------------------
Other long-term debt --
Pollution control revenue bonds --
Collateralized:
4.38% to 6.75% due 2000-2026 617 954
Variable rates (3.70% to 4.85% at 1/1/00)
due 2011-2025 120 639
Non-collateralized:
5.25% to 7.25% due 2003-2034 263 110
Variable rates (3.50% to 6.03% at 1/1/00)
due 2011-2037 1,510 880
- -----------------------------------------------------------------------------------------------------------------------------------
Total other long-term debt 2,510 2,583
- -----------------------------------------------------------------------------------------------------------------------------------
Capitalized lease obligations 97 135
- -----------------------------------------------------------------------------------------------------------------------------------
Unamortized debt premium (discount), net (63) (98)
- -----------------------------------------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
requirement -- $800 million) 12,323 11,912
Less amount due within one year 576 1,440
- -----------------------------------------------------------------------------------------------------------------------------------
Long-term debt excluding amount due within one year 11,747 10,472 49.7% 45.9%
- -----------------------------------------------------------------------------------------------------------------------------------
11-24
CONSOLIDATED STATEMENTS OF CAPITALIZATION (continued)
At December 31, 1999 and 1998
Southern Company and Subsidiary Companies 1999 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------------
1999 1998 1999 1998
- -----------------------------------------------------------------------------------------------------------------------------------
(in millions) (percent of total)
Company or Subsidiary Obligated Mandatorily
Redeemable Capital and Preferred Securities:
$25 liquidation value --
6.85% to 7.00% 435 235
7.13% to 7.38% 297 297
7.60% to 7.63% 415 415
7.75% 649 649
8.14% to 9.00% 481 583
Auction rate (6.42% at 1/1/00) 50 -
- -----------------------------------------------------------------------------------------------------------------------------------
Total company or subsidiary obligated mandatorily
redeemable capital and preferred securities (annual
distribution requirement -- $176 million) 2,327 2,179 9.8 9.6
- -----------------------------------------------------------------------------------------------------------------------------------
Cumulative Preferred Stock of Subsidiaries:
$100 par or stated value --
4.20% to 7.00% 99 135
$25 par or stated value --
5.20% to 5.83% 200 200
Adjustable and auction rates -- at 1/1/00:
4.22% to 4.50% 70 120
- -----------------------------------------------------------------------------------------------------------------------------------
Total (annual dividend requirement -- $19 million) 369 455
Less amount due within one year - 86
- -----------------------------------------------------------------------------------------------------------------------------------
Total cumulative preferred stock of subsidiaries
excluding amount due within one year 369 369 1.6 1.6
- -----------------------------------------------------------------------------------------------------------------------------------
Common Stockholders' Equity:
Common stock, par value $5 per share --
Authorized -- 1 billion shares
Issued -- 1999: 701 million shares
-- 1998: 700 million shares
Treasury -- 1999: 35 million shares
-- 1998: 2 million shares
Par value 3,503 3,499
Paid-in capital 2,480 2,463
Treasury, at cost (919) (58)
Retained earnings 4,232 3,878
Accumulated other comprehensive income (92) 15
- -----------------------------------------------------------------------------------------------------------------------------------
Total common stockholders' equity 9,204 9,797 38.9 42.9
- -----------------------------------------------------------------------------------------------------------------------------------
Total Capitalization $23,647 $22,817 100.0% 100.0%
===================================================================================================================================
The accompanying notes are an integral part of these statements.
II-25
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY
For the Years Ended December 31, 1999, 1998, and 1997
Southern Company and Subsidiary Companies 1999 Annual Report
Common Stock Accumulated
--------------------------------------- Other
Par Paid In Retained Comprehensive
Value Capital Treasury Earnings Income Total
- -------------------------------------------------------------------------------------------------------------------------
(in millions)
Balance at January 1, 1997 $3,385 $2,053 $ - $3,764 $ 14 $9,216
Net income - - - 972 - 972
Other comprehensive income - - - - (7) (7)
Stock issued 82 278 - - - 360
Cash dividends - - - (889) - (889)
Other - - - (5) - (5)
- -------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1997 3,467 2,331 - 3,842 7 9,647
Net income - - - 977 - 977
Other comprehensive income - - - - 8 8
Stock issued 32 132 70 - - 234
Stock repurchased, at cost - - (125) - - (125)
Cash dividends - - - (933) - (933)
Other - - (3) (8) - (11)
- -------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1998 3,499 2,463 (58) 3,878 15 9,797
Net income - - - 1,276 - 1,276
Other comprehensive income - - - - (107) (107)
Stock issued 4 17 1 - - 22
Stock repurchased, at cost - - (861) - - (861)
Cash dividends - - - (921) - (921)
Other - - (1) (1) - (2)
- -------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1999 $3,503 $2,480 $(919) $4,232 $ (92) $9,204
=========================================================================================================================
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 1999, 1998, and 1997
Southern Company and Subsidiary Companies 1999 Annual Report
- -----------------------------------------------------------------------------------------------------------------------
1999 1998 1997
- --------------------------------------------------------------------------------------------------------------------------
(in millions)
Consolidated Net Income $1,276 $977 $972
Other comprehensive income:
Foreign currency translation adjustments (165) 12 (10)
Less applicable income taxes (benefits) (58) 4 (3)
- --------------------------------------------------------------------------------------------------------------------------
Consolidated Comprehensive Income $1,169 $985 $965
==========================================================================================================================
The accompanying notes are an integral part of these statements.
II-26
NOTES TO FINANCIAL STATEMENTS
Southern Company and Subsidiary Companies 1999 Annual Report
1. Summary of Significant Accounting
Policies
General
Southern Company is the parent company of five integrated Southeast utilities, 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 integrated Southeast utilities -- Alabama Power,
Georgia Power, Gulf Power, Mississippi Power, and Savannah Electric -- provide
electric service in four states. Contracts among the integrated Southeast
utilities -- related to 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 integrated Southeast utilities
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. Southern Nuclear provides services to Southern Company's
nuclear power plants. Southern Energy acquires, develops, builds, owns, and
operates power production and delivery facilities and provides a broad range of
energy-related services to utilities and industrial companies in selected
countries around the world. Southern Energy businesses include independent power
projects, integrated utilities, a distribution company, and energy trading and
marketing businesses outside the southeastern United States.
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 integrated Southeast
utilities 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. The equity method is used for subsidiaries
in which the company has significant influence but does not control. 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 integrated Southeast utilities 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 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:
1999 1998
- ---------------------------------------------------------------
(in millions)
Deferred income tax charges $ 987 $1,036
Premium on reacquired debt 217 294
Department of Energy assessments 52 57
Vacation pay 87 81
Postretirement benefits 33 36
Deferred income tax credits (640) (715)
Storm damage reserves (29) (24)
Other, net 144 162
- ---------------------------------------------------------------
Total $ 851 $ 927
===============================================================
In the event that a portion of a company's operations is no longer subject to
the provisions of FASB Statement No. 71, the company would be required to write
off related 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-27
NOTES (continued)
Southern Company and Subsidiary Companies 1999 Annual Report
Revenues and Fuel Costs
Revenues are accrued for service rendered but unbilled at the end of each fiscal
period. Fuel costs are expensed as the fuel is used. Electric rates for the
integrated Southeast utilities 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 regulated 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 $137
million in 1999, $133 million in 1998, and $144 million in 1997. 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. 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. Activities for adding dry cask storage
capacity and for potentially increasing spent fuel pool rack capacity at Plant
Hatch during 2000 are in progress. Planning for additional on-site spent fuel
storage capacity at Plant Farley is also in progress, with the intent to place
additional on-site spent fuel storage capacity in operation as early as 2005. In
addition, through Southern Nuclear, Alabama Power and Georgia Power are members
of Private Fuel Storage, LLC, a joint utility effort to develop a private spent
fuel storage facility for temporary storage of spent nuclear fuel. This facility
is planned to begin operation as early as the year 2003.
Also, the Energy Policy Act of 1992 required the establishment 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, 1999, under this law to be approximately $28 million and $21
million. These obligations are recorded in the Consolidated Balance Sheets.
Depreciation and Nuclear Decommissioning
Depreciation of the original cost of plant in service is provided primarily by
using composite straight-line rates, which approximated 3.5 percent in 1999 and
3.4 percent in 1998 and 1997. 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
$314 million in 1998 and $159 million in 1997. Georgia Power did not record any
additional depreciation in 1999. 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
II-28
NOTES (continued)
Southern Company and Subsidiary Companies 1999 Annual Report
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
of December 31, 1999, 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. Rates used in the assumptions were approved by the
respective public service commissions.
Annual provisions for nuclear decommissioning are based on an annuity method
as approved by the respective state public service commissions. The amount
expensed in 1999 and fund balances were as follows:
Plant Plant Plant
Farley Hatch Vogtle
- ---------------------------------------------------------------
(in millions)
Amount expensed in 1999 $18 $17 $9
Accumulated provisions:
External trust funds,
at fair value $287 $222 $149
Internal reserves 40 22 12
- ---------------------------------------------------------------
Total $327 $244 $161
===============================================================
Alabama Power's decommissioning costs for ratemaking are based on the site
study. Effective January 1, 1999, the Georgia Public Service Commission
(GPSC)increased Georgia Power's 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. 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.
Property, Plant, and Equipment
Property, plant, and equipment is stated at original cost less regulatory
disallowances and impairments. 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
II-29
NOTES (continued)
Southern Company and Subsidiary Companies 1999 Annual Report
replacement of minor items of property is charged to maintenance expense. The
cost of replacements of property -- exclusive of minor items of property -- is
capitalized.
Property Rights
Property rights primarily consist of leasehold interests in Southern Energy's
Asian power generation facilities that are developed under build, operate, and
transfer agreements with the government-owned utility. These construction costs
for Southern Energy are initially recorded as construction work in progress, and
- -- after completion -- they are recorded as leasehold interests. These costs are
amortized over the period -- ranging from 12 to 29 years -- that the facility is
operated before transfer to the government-owned utility.
Goodwill and Other Intangible Assets
Goodwill, which represents the excess of cost over the fair value of assets of
businesses acquired, is amortized on a straight-line basis over periods from 30
to 40 years. Other intangible assets are amortized on a straight-line basis over
periods from 15 to 30 years.
Leveraged Leases
Southern Energy has several leveraged lease agreements -- ranging from 21 to 30
years -- that primarily relate to international energy generation, distribution,
and transportation assets. The investment income earned from these leveraged
leases is immaterial for all periods presented.
Impairment of Long-Lived Assets and Intangibles
Southern Company evaluates long-lived assets -- including goodwill and
identifiable intangibles -- when events or changes in circumstances indicate
that the carrying value of such assets may not be recoverable. The determination
of whether an impairment has occurred is based on an estimate of undiscounted
future cash flows attributable to the assets, as compared to the carrying value
of the assets. If an impairment has occurred, the amount of the impairment
recognized is determined by estimating the fair value of the assets and
recording a provision for loss if the carrying value is greater than the fair
value. For assets identified as held for sale, the carrying value is compared to
their estimated fair value less the cost to sell in order to determine if an
impairment provision is required. Until the assets are disposed of, their
estimated fair value is reevaluated when circumstances or events change.
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.
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 Energy'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. Gains and losses on foreign currency
transactions are not material for all periods presented.
Comprehensive Income
Comprehensive income -- consisting of net income and foreign currency
translation adjustments net of taxes -- 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.
II-30
NOTES (continued)
Southern Company and Subsidiary Companies 1999 Annual Report
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 of the
hedged item when the 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 Energy's international operations are exposed to the effects of
foreign currency exchange rate fluctuations. To protect against this exposure,
currency swaps are used to hedge the 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. Non-trading hedging
activities are classified in the same category as the item hedged in the
company's cash flow statement.
Non-trading financial derivative instruments held at December 31, 1999, were
as follows:
Year of Unrecognized
Maturity or Notional Gain
Type Termination Amount (Loss)
- ------------------------------- --------------------------
(in millions)
Interest rate
swaps: 2000-2012 $1,910 $(3)
2001-2012 (pound)600 $(49)
2002-2007 DM691 $(5)
Cross currency
swaps 2001-2007 (pound)414 $(11)
Cross currency
swaption 2003 DM435 $11
- -----------------------------------------------------------------
(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.
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, 1999 $12,226 $11,557
At December 31, 1998 11,777 11,626
Capital and preferred securities:
At December 31, 1999 2,327 2,015
At December 31, 1998 2,179 2,288
- --------------------------------------------------------------
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
During 1999, Southern Energy created an energy trading company in Amsterdam,
which provides risk management services associated with the energy industry to
its customers in the European market. These services are provided primarily
through a variety of exchange-traded energy contracts including forward
contracts, futures contracts, option contracts, and financial swap agreements.
These contractual commitments, which represent risk management assets and
liabilities, are accounted for using the mark-to-market method of accounting.
Accordingly, they are reflected at fair value, net of future delivery costs, in
the Consolidated Balance Sheets.
Net unrealized gains from risk management services are immaterial at December
31, 1999. The volumetric weighted average maturity of the contractual
commitments was 1.35 years. The net notional amount of the risk management
assets and liabilities at December 31, 1999 was 5.3 billion kilowatt-hours. The
notional amount is indicative only of the volume of activity and not of the
amount exchanged by the parties to the financial instruments. Consequently,
II-31
NOTES (continued)
Southern Company and Subsidiary Companies 1999 Annual Report
these amounts are not a measure of market risk. The averages for 1999 were based
on month-end balances. The fair value of these assets and liabilities at
December 31, 1999 was $1 million and $5 million, respectively.
The Amsterdam trading operations involve elements of credit risk. The trading
operation has attempted to mitigate this risk by establishing controls to
determine and monitor the creditworthiness of counterparties. The company
monitors credit risk on both an individual and group counterparty basis.
Accordingly, the company does not anticipate any material impact to its
financial position or results of operations as a result of counterparty
nonperformance.
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 integrated Southeast utilities fund trusts to the extent
required by their respective regulatory commissions. The measurement date for
plan assets and obligations 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
-------------------
1999 1998
- --------------------------------------------------------------
(in millions)
Balance at beginning of year $4,170 $3,701
Service cost 111 99
Interest cost 265 273
Benefits paid (213) (201)
Actuarial (gain) loss (251) 298
- --------------------------------------------------------------
Balance at end of year $4,082 $4,170
==============================================================
Plan Assets
-----------------
1999 1998
- --------------------------------------------------------------
(in millions)
Balance at beginning of year $5,978 $5,931
Actual return on plan assets 1,008 223
Employer contributions - 4
Benefits paid (308) (180)
- --------------------------------------------------------------
Balance at end of year $6,678 $5,978
==============================================================
The accrued pension costs recognized in the Consolidated Balance Sheets were
as follows:
1999 1998
- ---------------------------------------------------------------
(in millions)
Funded status $ 2,596 $ 1,808
Unrecognized transition obligation (76) (89)
Unrecognized prior service cost 149 119
Unrecognized net gain (2,079) (1,347)
- ---------------------------------------------------------------
Prepaid asset recognized in the
Consolidated Balance Sheets $ 590 $ 491
===============================================================
Components of the pension plans' net periodic cost were as follows:
1999 1998 1997
- ---------------------------------------------------------------
(in millions)
Service cost $ 111 $ 99 $ 94
Interest cost 265 273 271
Expected return on
plan assets (451) (425) (394)
Recognized net gain (42) (47) (42)
Net amortization 2 (9) (9)
- ---------------------------------------------------------------
Net pension cost (income) $(115) $(109) $ (80)
===============================================================
Postretirement Benefits
Changes during the year in the accumulated benefit obligations and in the fair
value of plan assets were as follows:
Accumulated
Benefit Obligations
--------------------
1999 1998
- ---------------------------------------------------------------
(in millions)
Balance at beginning of year $1,037 $ 935
Service cost 21 18
Interest cost 69 69
Benefits paid (36) (35)
Actuarial (gain) loss (95) 50
- ----------------------------------------------------------------
Balance at end of year $ 996 $1,037
================================================================
II-32
NOTES (continued)
Southern Company and Subsidiary Companies 1999 Annual Report
Plan Assets
------------------
1999 1998
- ---------------------------------------------------------------
(in millions)
Balance at beginning of year $336 $294
Actual return on plan assets 36 8
Employer contributions 60 69
Benefits paid (37) (35)
- ---------------------------------------------------------------
Balance at end of year $395 $336
===============================================================
The accrued postretirement costs recognized in the Consolidated Balance
Sheets were as follows:
1999 1998
- ---------------------------------------------------------------
(in millions)
Funded status $(601) $(701)
Unrecognized transition obligation 203 219
Unrecognized prior service cost 1 -
Unrecognized net loss (gain) 11 117
Fourth quarter contributions 25 30
- ---------------------------------------------------------------
Accrued liability recognized in the
Consolidated Balance Sheets $(361) $(335)
===============================================================
Components of the postretirement plans' net periodic cost were as follows:
1999 1998 1997
- --------------------------------------------------------------
(in millions)
Service cost $ 21 $ 18 $ 18
Interest cost 69 69 66
Expected return on
plan assets (26) (21) (18)
Recognized net gain 2 2 3
Net amortization 15 14 17
- --------------------------------------------------------------
Net postretirement cost $ 81 $ 82 $ 86
==============================================================
The weighted average rates assumed in the actuarial calculations for both
the pension plans and postretirement benefits were:
1999 1998
- ---------------------------------------------------------------
Discount 7.50% 6.75%
Annual salary increase 5.00 4.25
Long-term return on plan assets 8.50 8.50
- ---------------------------------------------------------------
An additional assumption used in measuring the accumulated postretirement
benefit obligation was a weighted average medical care cost trend rate of 7.74
percent for 1999, decreasing gradually to 5.50 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,
1999 as follows:
1 Percent 1 Percent
Increase Decrease
- ----------------------------------------------------------------
(in millions)
Benefit obligation $73 $(62)
Service and interest costs 6 (5)
- ----------------------------------------------------------------
Work Force Reduction Programs
Southern Company has incurred additional costs for work force reduction
programs. The costs related to these programs were $30 million, $32 million, and
$50 million for the years 1999, 1998, and 1997, respectively. In addition,
certain costs of these programs were deferred and are being amortized in
accordance with regulatory treatment.
3. CONTINGENCIES AND REGULATORY
MATTERS
Alabama Power Lake Martin 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. Alabama Power has appealed 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.
Additional actions have been filed by other land owners in the same
subdivision on Lake Martin against the same defendants, including Alabama Power.
The plaintiffs assert substantially the same allegations as in the current
proceeding being appealed. The final outcome of these actions cannot now be
determined.
II-33
NOTES (continued)
Southern Company and Subsidiary Companies 1999 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, 1999, 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.
Environmental Litigation
On November 3, 1999, the EPA brought a civil action in the U.S. District Court
against Alabama Power, Georgia Power, and the system service company. The
complaint alleges violations of the prevention of significant deterioration and
new source review provisions of the Clean Air Act with respect to five
coal-fired generating facilities in Alabama and Georgia. The civil action
requests penalties and injunctive relief, including an order requiring the
installation of the best available control technology at the affected units. The
Clean Air Act authorizes civil penalties of up to $27,500 per day, per violation
at each generating unit. Prior to January 30, 1997, the penalty was $25,000 per
day.
The EPA concurrently issued to the integrated Southeast utilities a notice of
violation related to 10 generating facilities, which includes the five
facilities mentioned previously. In early 2000, the EPA filed a motion to amend
its complaint to add the violations alleged in its notice of violation, and to
add Gulf Power, Mississippi Power, and Savannah Electric as defendants. The
complaint and notice of violations are similar to those brought against and
issued to several other electric utilities. These complaints and notices of
violation allege that the utilities had failed to secure necessary permits or
install additional pollution equipment when performing maintenance and
construction at coal burning plants constructed or under construction prior to
1978. Southern Company believes that its integrated utilities complied with
applicable laws and the EPA's regulations and interpretations in effect at the
time the work in question took place.
An adverse outcome of this matter could require substantial capital
expenditures that cannot be determined at this time and possibly require payment
of substantial penalties. This could affect future results of operations, cash
flows, and possibly financial condition if such costs are not recovered through
regulated rates.
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. As a result of the bankruptcy filing, the
investment in MESC was deconsolidated. 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 was in
response to Kimberly-Clark Tissue Company's (Kimberly-Clark) announcement in May
1998 of plans to close its pulp mill, effective September 1, 1999. The pulp mill
had historically provided 50 percent of MESC's revenues.
As a result of settlement discussions with Kimberly-Clark and MESC's
bondholders, Southern Company recorded in September 1999 an after-tax write down
of $69 million, primarily representing Southern Company's investment in MESC. At
December 31, 1999, MESC had total assets of $395 million and senior debt
outstanding of $193 million of first mortgage bonds and $73 million related to
tax-exempt bonds. In connection with MESC's bond financings, Southern Company
provided certain limited guarantees, in lieu of funding debt service and
maintenance reserve accounts with cash. As of December 31, 1999, Southern
Company had paid $38 million pursuant to the guarantees. Southern Company
continues to have guarantees outstanding of certain potential environmental and
other obligations of MESC that represent a maximum contingent liability of $21
million at December 31, 1999.
MESC, an unofficial committee of its bondholders, and Kimberly-Clark have
reached a tentative agreement to settle disputes arising from the shutdown of
Kimberly-Clark's pulp mill in Mobile, Alabama, and to reconfigure energy
services at the site. MESC has reached a separate agreement with Southern Energy
to develop and operate a 165-megawatt cogeneration facility at the site,
including providing a combustion turbine for such facility. The bankruptcy court
approved both agreements.
II-34
NOTES (continued)
Southern Company and Subsidiary Companies 1999 Annual Report
The finalization of the proposed settlement between MESC and Kimberly-Clark
requires further agreements to be negotiated between the parties and certain
other conditions to be met, including having a plan of reorganization for MESC
be approved by the bankruptcy court and become effective by no later than
October 30, 2000. If these conditions, as well as others set out in the
settlement agreement filed with the bankruptcy court, are not met, then the
proposed settlement would no longer be effective. The final outcome of this
matter cannot now be determined.
Southern Energy Brazilian Investment
In September 1999, a Brazilian appellate court granted a temporary injunction
that suspended the effectiveness of a shareholders' agreement for Companhia
Energetica de Minas Gerais (CEMIG). This ruling suspends the shareholders'
agreement -- including Southern Energy's super majority voting rights -- while
the action to determine the validity of the agreement is litigated in the lower
court. Southern Energy intends to pursue its legal rights in this matter and to
have all of its rights restored regarding CEMIG. Southern Energy does not
anticipate that this temporary suspension of the shareholders' agreement will
have a significant effect on its financial condition or results of operation.
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.
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. Alabama Power did not
record any additional amounts in 1999 or 1997.
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 the 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 were decreased by $262 million
effective January 1, 1999, and by an additional $24 million effective January 1,
2000. In addition, the order provided for $85 million annually to be applied to
accelerated amortization or depreciation of assets, and up to an additional $50
million annually in 2000 and 2001 of any earnings above the 12.5 percent return.
In 1999, Georgia Power -- in accordance with the rate order -- recorded $85
million of additional amortization of premium on reacquired debt.
II-35
NOTES (continued)
Southern Company and Subsidiary Companies 1999 Annual Report
Two-thirds of any additional earnings above the 12.5 percent return in any
year will be applied to rate reductions and the remaining one-third retained by
Georgia Power. In 1999, Georgia Power's return was above 12.5 percent, and
accordingly, it recorded $79 million as an estimate of revenues to be refunded
to customers in 2000. 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 $3.0 billion in 2000, $3.8 billion in 2001, and $3.9
billion in 2002. 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, 1999, significant
purchase commitments were outstanding in connection with the construction
program. The integrated Southeast utilities have approximately 5,200 megawatts
of combustion turbine generating capacity scheduled to be placed in service by
2002. Southern Energy has under construction approximately 1,000 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. FINANCING AND COMMITMENTS
Financing
The amount and timing of additional equity capital to be raised in 2000 -- as
well as in subsequent years -- will be contingent on Southern Company's
investment opportunities. Equity capital may be provided from any combination of
public offerings, private placements, or the company's stock plans.
The integrated Southeast utilities' 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 2000, unused credit arrangements with banks totaled $5.7
billion, of which $3.1 billion expires during 2000, $1.1 billion during 2001 and
2002, and $1.5 billion during 2003 and 2004. The following table outlines the
credit arrangements by company:
Amount of Credit
-------------------------------------
Expires
--------------------
2001 &
Company Total Unused 2000 beyond
- -------- ---------------------------------------
(in millions)
Alabama Power $ 907 $ 907 $ 517 $ 390
Georgia Power 1,252 1,252 752 500
Gulf Power 103 103 103 -
Mississippi Power 104 104 104 -
Savannah Electric 61 26 26 -
Southern Company 2,000 2,000 1,000 1,000
Southern Energy 3,021 1,256 574 682
Other 60 51 51 -
- --------------------------------------------------------------
Total $7,508 $5,699 $3,127 $2,572
==============================================================
Approximately $2.5 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 $5.7 billion in unused credit, $1.85 billion, $1.0
billion, $800 million, and $780 million are syndicated credit arrangements of
Southern Company, Georgia Power, Southern Energy, and Alabama Power,
respectively. These facilities also require the payment of agent fees.
II-36
NOTES (continued)
Southern Company and Subsidiary Companies 1999 Annual Report
A portion of the $5.7 billion unused credit with banks is allocated to
provide liquidity support to the companies' variable rate pollution control
bonds. The amount of variable rate pollution control bonds requiring liquidity
support as of December 31, 1999, was $674 million.
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.
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,
1999, were as follows:
Purchased
Year Fuel Power
- ----- ------------------------
(in millions)
2000 $1,629 $ 81
2001 1,351 81
2002 1,153 97
2003 1,012 99
2004 872 95
2005 and thereafter 3,429 1,006
- ---------------------------------------------------------------
Total commitments $9,446 $1,459
===============================================================
Operating Leases
Southern Company has operating lease agreements with various terms and
expiration dates. These expenses totaled $67 million, $56 million, and $36
million for 1999, 1998, and 1997, respectively. At December 31, 1999, estimated
minimum rental commitments for noncancelable operating leases were as follows:
Year Amounts
- ---- ------------
(in millions)
2000 $ 64
2001 83
2002 89
2003 82
2004 82
2005 and thereafter 526
- ------------------------------------------------------------------
Total minimum payments $926
==================================================================
Long-Term Service Agreements
Southern Energy has entered into several long-term service agreements for the
maintenance and repair of its combustion turbine or combined cycle generating
plants. These agreements may be terminated in the event a planned construction
project is canceled. At December 31, 1999, the annual amounts committed are as
follows:
Year Amounts
- ---- ---------------
(in millions)
2000 $ 3
2001 8
2002 28
2003 51
2004 62
2005 and thereafter 591
- ----------------------------------------------------------------
Total minimum payments $743
================================================================
Energy Trading and Marketing Commitments
In 1998, Southern Energy and Vastar Resources (Vastar) completed the combination
of their energy trading and marketing activities to form a joint venture,
Southern Company Energy Marketing (SCEM). SCEM buys and sells physical and
financial energy commodities and financial instruments and provides
energy-related products and services. SCEM's gross revenues and cost of sales
for 1999 were $12.0 billion and $11.9 billion, respectively.
Southern Energy's current ownership interest in SCEM is 60 percent. The
equity method of accounting is used because of Vastar's significant
II-37
NOTES (continued)
Southern Company and Subsidiary Companies 1999 Annual Report
participation rights. On July 1, 2001, this ownership interest will
automatically increase to 75 percent. Southern Energy has the right --
exercisable during fiscal year 2002 -- to acquire an additional 5 percent
interest from Vastar for $80 million. Also, Vastar has the right -- exercisable
in the period from December 1, 2002 through January 2, 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.
Southern Company and Vastar have separately made guarantees to certain
counterparties regarding performance of contractual commitments by SCEM.
Southern Company and Vastar have agreed to indemnify each other against losses
under such guarantees in proportion to their respective ownership shares of
SCEM. At December 31, 1999, outstanding guarantees related to the estimated fair
value of net contractual commitments were approximately $146 million. Based upon
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.
Southern Energy has guaranteed certain minimum annual cash distributions,
subject to exclusions, payable by SCEM to Vastar. For 1999, this distribution,
after adjustments, was $17 million. These distributions before any adjustments
total $85 million for the period 2000-2002.
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. 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 jointly with OPC, the Municipal Electric Authority of
Georgia, the city of Dalton, Georgia, Florida Power &Light Company (FP&L), and
Jacksonville Electric Authority (JEA). In addition, Georgia Power has joint
ownership agreements with OPC for the Rocky Mountain project and with Florida
Power Corporation (FPC) for a combustion turbine unit at Intercession City,
Florida.
At December 31, 1999, 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% $3,297 $1,630
Plant Hatch
(nuclear) 50.1 857 604
Plant Miller
(coal)
Units 1 and 2 91.8 740 297
Plant Scherer
(coal)
Units 1 and 2 8.4 112 51
Plant Wansley
(coal) 53.5 299 145
Rocky Mountain
(pumped storage) 25.4 169 66
Intercession City
(combustion turbine) 33.3 11 *
- ---------------------------------------------------------------
*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 integrated Southeast utilities 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
II-38
NOTES (continued)
Southern Company and Subsidiary Companies 1999 Annual Report
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 $174 million in 1999, $196 million in 1998,
and $203 million in 1997.
Unit power from specific generating plants is currently being sold to FP&L,
FPC, JEA, and the city of Tallahassee, Florida. Under these agreements,
approximately 1,600 megawatts of capacity is scheduled to be sold in 2000.
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
2000 with a minimum of three years notice -- until the expiration of the
contracts in 2010.
8. INCOME TAXES
At December 31, 1999, the tax-related regulatory assets and liabilities were
$987 million and $640 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:
1999 1998 1997
- --------------------------------------------------------------
(in millions)
Total provision for income taxes:
Federal --
Current $ 486 $ 451 $ 547
Deferred -- current year 186 195 188
-- reversal of
prior years (145) (208) (160)
- --------------------------------------------------------------
527 438 575
- --------------------------------------------------------------
State --
Current 85 106 104
Deferred -- current year 16 28 15
-- reversal of
prior years (10) (31) (19)
- --------------------------------------------------------------
91 103 100
- --------------------------------------------------------------
International 108 8 164
- --------------------------------------------------------------
Total $ 726 $ 549 $ 839
==============================================================
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:
1999 1998
- --------------------------------------------------------------
(in millions)
Deferred tax liabilities:
Accelerated depreciation $3,439 $3,315
Property basis differences 1,516 1,667
Other 585 403
- --------------------------------------------------------------
Total 5,540 5,385
- --------------------------------------------------------------
Deferred tax assets:
Federal effect of state deferred taxes 102 104
Other property basis differences 221 239
Deferred costs 134 132
Pension and other benefits 90 79
Other 420 293
- ---------------------------------------------------------------
Total 967 847
- ---------------------------------------------------------------
Net deferred tax liabilities 4,573 4,538
Portion included in current assets, net (68) (57)
- ---------------------------------------------------------------
Accumulated deferred income taxes
in the Consolidated Balance Sheets $4,505 $4,481
===============================================================
Deferred investment tax credits are amortized over the lives 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 $35 million in 1999, $38 million in 1998, and $30 million in
1997. At December 31, 1999, all investment tax credits available to reduce
federal income taxes payable had been utilized.
A reconciliation of the federal statutory income tax rate -- which excludes
the effect of minority interests and preferred dividends -- to the effective
income tax rate is as follows:
1999 1998 1997
- ---------------------------------------------------------------
Federal statutory rate 35.0% 35.0% 35.0%
State income tax,
net of federal deduction 2.8 4.1 3.4
Non-deductible book
depreciation 1.3 4.1 2.3
Differences in foreign tax rates (5.1) (6.4) -
Windfall profits tax - - 8.0
Difference in prior years'
deferred and current tax rate (0.9) (1.3) (1.5)
Other (0.2) (1.8) (1.9)
- ---------------------------------------------------------------
Effective income tax rate 32.9% 33.7% 45.3%
===============================================================
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.
II-39
NOTES (continued)
Southern Company and Subsidiary Companies 1999 Annual Report
The undistributed earnings of foreign subsidiaries aggregated $435
million as of December 31, 1999, and these subsidiaries' earnings are not
subject to U.S. income tax until distributed. Of the total undistributed
earnings, provisions for U.S. taxes have not been made on $210 million related
to earnings that are intended to be reinvested indefinitely.
9. COMMON STOCK
Stock Repurchase Programs
In April 1999, Southern Company's Board of Directors approved the repurchase of
up to 50 million shares of Southern Company's common stock over a two-year
period through open market or privately negotiated transactions. The program did
not establish a target stock price or timetable for specific repurchases. Under
this program, 32.8 million shares have been repurchased through December 31,
1999. Funding for the program was provided from Southern Company's commercial
paper program.
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 was 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 were repurchased and 2.4 million
shares were reissued.
Shares Reserved
At December 31, 1999, a total of 47 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, 1999, 355 current and former employees participated in the
Performance Stock Plan. The maximum number of shares of common stock that may be
issued under the 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
three 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
Company Board of Directors in accordance with the plan. Stock option activity in
1998 and 1999 for the plan is summarized below:
Shares Average
Subject Option Price
To Option Per Share
- --------------------------------------------------------------
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 (604,238) 20.21
- --------------------------------------------------------------
Balance at December 31, 1998 6,431,292 22.77
Options granted 2,108,818 26.56
Options canceled (27,995) 25.54
Options exercised (56,708) 19.51
- --------------------------------------------------------------
Balance at December 31, 1999 8,455,407 $23.73
==============================================================
Shares reserved for future grants:
At December 31, 1997 38,241,376
At December 31, 1998 36,598,001
At December 31, 1999 34,515,156
- --------------------------------------------------------------
Options exercisable:
At December 31, 1998 2,653,591
At December 31, 1999 4,525,349
- --------------------------------------------------------------
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
------------------------------
1999 1998 1997
- --------------------------------------------------------------
(in thousands)
As reported shares 685,163 696,944 685,033
Effect of options 580 739 201
- --------------------------------------------------------------
Diluted shares 685,743 697,683 685,234
==============================================================
II-40
NOTES (continued)
Southern Company and Subsidiary Companies 1999 Annual Report
Common Stock Dividend Restrictions
The income of Southern Company is derived primarily from equity in earnings of
its subsidiaries. At December 31, 1999, consolidated retained earnings included
$3.5 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, 1999, capital securities of
$950 million and preferred securities of $1.4 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:
1999 1998
- --------------------------------------------------------------
(in millions)
Bond improvement fund requirements $ 14 $ 23
Less:
Portion to be satisfied by certifying
property additions 9 14
- --------------------------------------------------------------
Cash requirements 5 9
First mortgage bond maturities
and redemptions 200 868
Other long-term debt maturities 371 563
- --------------------------------------------------------------
Total $576 $1,440
==============================================================
The first mortgage bond improvement fund requirements amount to 1 percent of
each outstanding series of bonds authenticated under the indentures prior to
January 1 of each year, other than those issued to collateralize pollution
control 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
integrated Southeast utilities 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 2004
applicable to other long-term debt are as follows: $371 million in 2000; $501
million in 2001; $1.0 billion in 2002; $435 million in 2003; and $1.46 billion
in 2004.
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
$9.5 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.
II-41
NOTES (continued)
Southern Company and Subsidiary Companies 1999 Annual Report
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 12 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 $19 million and $21 million,
respectively.
For all on-site property damage insurance policies for commercial nuclear
power plants, the NRC requires that the proceeds of such policies 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. ACQUISITIONS AND ASSET SALES
Acquisitions
Southern Energy completed several acquisitions in both 1999 and 1998. In 1999, a
$801 million acquisition of 3,065 megawatts of generating capacity from Pacific
Gas &Electric in northern California was completed. Additionally, Southern
Energy acquired 1,794 megawatts of generating capacity from Orange and Rockland
Utilities Inc. and Consolidated Edison Inc. for $476 million. A 9.9 percent
interest in Shandong International Power Development Company was purchased in
1999 for $107 million.
Southern Energy paid $537 million in 1998 to Commonwealth Electric for 1,245
megawatts of generating capacity. Also in 1998, Southern Energy acquired a 3.6
percent economic interest in CEMIG -- a Brazilian utility -- for $274 million.
Assets Sold
Southern Energy's significant asset sales in 1999 and 1998 related to its United
Kingdom subsidiary South Western Electricity (SWEB). The supply system of SWEB
was sold in 1999 for $256 million of which Southern Energy owned 49 percent. The
remaining distribution business was renamed Western Power Distribution. In 1998,
Southern Energy sold a 26 percent interest in SWEB for $170 million.
Assets for Sale
In December 1998, Southern Energy designed and implemented a plan to dispose of
its Argentinean and Chilean investments. As a result, 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, 1999 was $92 million. These assets impacted the Consolidated
Statements of Income as follows:
Operating Operating Consolidated
Year Revenues Income Net Income
- ---- -----------------------------------------
(in millions)
1999 $171 $23 $2
1998 180 37 5
1997 180 37 5
Depreciation expense was suspended beginning January 1999, and the after-tax
amount of depreciation recorded in 1998 was $16 million. Southern Energy has
been actively pursuing and/or negotiating with potential buyers for its assets
in Argentina and Chile. In early 2000, Southern Energy announced an agreement to
sell its Argentinean assets substantially at the adjusted carrying value with no
material gain or loss expected to be recognized in 2000.
II-42
NOTES (continued)
Southern Company and Subsidiary Companies 1999 Annual Report
14. SEGMENT AND RELATED INFORMATION
Southern Company's principal business segment is the five integrated Southeast
utilities that provide electric service in four states. The other reportable
business segment is Southern Energy, which includes international operations and
the competitive energy supply businesses in North America outside the Southeast.
Intersegment revenues are not material. Financial data for business segments,
products and services, and geographic areas are as follows:
Business Segments
Integrated Southern Energy All
Southeast ------------------------------------------ Other Reconciling
Year Utilities International Domestic Total (Note) Eliminations Consolidated
- ---- -------------------------------------------------------------------------------------------------
(in millions)
1999
- ----
Operating revenues $ 9,125 $1,532 $ 736 $ 2,268 $ 222 $ (30) $11,585
Depreciation and amortization 961 261 61 322 24 - 1,307
Interest income 64 88 86 174 42 (116) 164
Net interest charges 700 264 219 483 136 (78) 1,241
Income taxes 675 85 41 126 (62) (13) 726
Write down of generating assets - - 69 69 - - 69
Net income from equity
method subsidiaries - 100 (6) 94 - - 94
Segment net income (loss) 1,073 346 (18) 328 (101) (24) 1,276
Total assets 25,251 9,370 4,502 13,872 461 (1,188) 38,396
Investments in equity
method subsidiaries 11 1,195 171 1,366 - (1) 1,376
Gross property additions 1,854 447 232 679 27 - 2,560
Increase in goodwill - - 48 48 - - 48
- -----------------------------------------------------------------------------------------------------------------------------------
Integrated Southern Energy All
Southeast -------------------------------------------- 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 703 (101) (22) (123) (12) (19) 549
Write down 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 24,420 9,578 2,869 12,447 1,438 (2,114) 36,191
Investments in equity
method subsidiaries 10 1,363 176 1,539 - - 1,549
Gross property additions 1,298 586 63 649 58 - 2,005
Increase in goodwill - 30 261 291 - - 291
- -----------------------------------------------------------------------------------------------------------------------------------
II-43
NOTES (continued)
Southern Company and Subsidiary Companies 1999 Annual Report
Integrated Southern Energy All
Southeast -------------------------------------------- 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 687 181 (6) 175 (17) (154) 691
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 24,796 9,225 1,832 11,057 1,225 (1,823) 35,255
Investments in equity
method subsidiaries 10 1,024 134 1,158 - - 1,168
Gross property additions 1,080 720 1 721 58 - 1,859
Increase in goodwill - 1,649 - 1,649 - - 1,649
- -----------------------------------------------------------------------------------------------------------------------------------
(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. Amounts for Southern Energy exclude interest
expense to parent Southern Company.
Products and Services
Revenues
------------------------------------------------------------------------------------------------------------------
Integrated
Southeast Utilities Southern Energy
--------------------------------------------- ----------------------------------------------------------------
Energy
Trading And
Year Retail Wholesale Other Total Generation Distribution Marketing Other Total
- ---- ------------------------------------------------------------------------------------------------------------------
(in millions)
1999 $8,086 $823 $216 $9,125 $1,222 $ 976 $ - $70 $2,268
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
- -----------------------------------------------------------------------------------------------------------------------------------
Geographic Areas
Revenues
----------------------------------------------------------------------------------------------------
International
-------------------------------------------------------------
All
Year Domestic Europe Asia Other Total Consolidated
- ---- ----------------------------------------------------------------------------------------------------
(in millions)
1999 $10,053 $ 976 $342 $214 $1,532 $11,585
1998 9,637 1,273 273 220 1,766 11,403
1997 10,863 1,282 247 219 1,748 12,611
- -----------------------------------------------------------------------------------------------------------------------------------
II-44
NOTES (continued)
Southern Company and Subsidiary Companies 1999 Annual Report
Long-Lived Assets
--------------------------------------------------------------------------------------------------
International
-----------------------------------------------------------------------------
All
Year Domestic Europe Asia Other Total Consolidated
- ---- --------------------------------------------------------------------------------------------------
(in millions)
1999 $24,266 $2,449 $4,029 $1,725 $8,203 $32,469
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
- ----------------------------------------------------------------------------------------------------------------------------------
15. Quarterly Financial Information (Unaudited)
Summarized quarterly financial data for 1999 and 1998 are as follows:
Per Common Share
-------------------------------------------------------
Operating Operating Consolidated Price Range
Quarter Ended Revenues Income Net Income Earnings Dividends High Low
- -------------- ------------------------------------ --------------------------------------------------------
(in millions)
March 1999 $2,442 $ 485 $224 $0.32 $0.335 29 5/8 23 1/4
June 1999 2,791 668 314 0.45 0.335 29 3/16 22 3/4
September 1999 3,736 1,109 615 0.90 0.335 28 25
December 1999 2,616 517 123 0.19 0.335 27 1/8 22 1/16
March 1998 $2,495 $ 573 $242 $0.35 $0.335 28 11/16 23 15/16
June 1998 2,913 648 270 0.39 0.335 29 25 1/16
September 1998 3,457 1,068 517 0.74 0.335 29 13/16 25 1/4
December 1998 2,538 21 (52) (0.08) 0.335 31 9/16 27 3/16
- ---------------------------------------------------------------------------------------------------------------------------
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 13.
II-45
SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA 1995-1999
Southern Company and Subsidiary Companies 1999 Annual Report
1999 1998 1997 1996 1995
- ----------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in millions) $11,595 $11,403 $12,611 $10,358 $9,180
Consolidated Net Income (in millions) $1,276 $977 $972 $1,127 $1,103
Basic and Diluted Earnings Per Share of Common Stock $1.86 $1.40 $1.42 $1.68 $1.66
Cash Dividends Paid Per Share of Common Stock $1.34 $1.34 $1.30 $1.26 $1.22
Return on Average Common Equity (percent) 13.43 10.04 10.30 12.53 13.01
Total Assets (in millions) $38,396 $36,191 $35,255 $30,230 $30,522
Gross Property Additions (in millions) $2,560 $2,005 $1,859 $1,229 $1,401
Southern Energy Business and Asset Acquisitions $1,800 $998 $2,925 $- $1,416
- ----------------------------------------------------------------------------------------------------------------------------
Capitalization (in millions):
Common stock equity $ 9,204 $ 9,797 $ 9,647 $ 9,216 $ 8,772
Preferred stock and securities 2,696 2,548 2,237 1,402 1,432
Long-term debt 11,747 10,472 10,274 7,938 8,274
- ----------------------------------------------------------------------------------------------------------------------------
Total excluding amounts due within one year $23,647 $22,817 $22,158 $18,556 $18,478
============================================================================================================================
Capitalization Ratios (percent):
Common stock equity 38.9 42.9 43.5 49.7 47.5
Preferred stock and securities 11.4 11.2 10.1 7.6 7.7
Long-term debt 49.7 45.9 46.4 42.7 44.8
- ----------------------------------------------------------------------------------------------------------------------------
Total excluding amounts due within one year 100.0 100.0 100.0 100.0 100.0
============================================================================================================================
Other Common Stock Data:
Book value per share (year-end) $13.82 $14.04 $13.91 $13.61 $13.10
Market price per share:
High 29 5/8 31 9/16 26 1/4 25 7/8 25
Low 22 1/16 23 15/16 19 7/8 21 1/8 19 3/8
Close 23 1/2 29 1/16 25 7/8 22 5/8 24 5/8
Market-to-book ratio (year-end) (percent) 170.0 207.0 186.0 166.2 188.0
Price-earnings ratio (year-end) (times) 12.6 20.8 18.2 13.5 14.8
Dividends paid (in millions) $921 $933 $889 $846 $811
Dividend yield (year-end) (percent) 5.7 4.6 5.0 5.6 5.0
Dividend payout ratio (percent) 72.2 95.6 91.5 75.1 73.5
Shares outstanding (in thousands):
Average 685,163 696,944 685,033 672,590 665,064
Year-end 665,796 697,747 693,423 677,036 669,543
Stockholders of record (year-end) 174,179 187,053 200,508 215,246 225,739
- -----------------------------------------------------------------------------------------------------------------------------
Customers for Integrated Southeast Utilities
(year-end) (in thousands):
Residential 3,339 3,277 3,220 3,157 3,100
Commercial 513 497 479 464 450
Industrial 15 15 16 17 17
Other 4 5 5 5 5
- -----------------------------------------------------------------------------------------------------------------------------
Total 3,871 3,794 3,720 3,643 3,572
=============================================================================================================================
Employees (year-end):
Traditional business 26,269 25,206 24,682 25,034 26,452
Southern Energy 6,680 6,642 5,620 3,743 5,430
- -----------------------------------------------------------------------------------------------------------------------------
Total 32,949 31,848 30,302 28,777 31,882
=============================================================================================================================
II-46
SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA 1995-1999 (continued)
Southern Company and Subsidiary Companies 1999 Annual Report
1999 1998 1997 1996 1995
- ----------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in millions):
Residential $ 3,105 $ 3,163 $ 2,837 $ 2,894 $2,840
Commercial 2,743 2,763 2,595 2,559 2,485
Industrial 2,237 2,267 2,139 2,136 2,206
Other 1 79 76 76 72
- ----------------------------------------------------------------------------------------------------------------------------
Total retail 8,086 8,272 7,647 7,665 7,603
Sales for resale within service area 350 374 376 409 399
Sales for resale outside service area 473 522 510 429 415
- ----------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 8,909 9,168 8,533 8,503 8,417
Southern Energy 2,268 1,903 3,837 1,683 643
Other revenues 408 332 241 172 120
- ----------------------------------------------------------------------------------------------------------------------------
Total $11,585 $11,403 $12,611 $10,358 $9,180
============================================================================================================================
Kilowatt-Hour Sales (in millions):
Residential 43,402 43,503 39,217 40,117 39,147
Commercial 43,387 41,737 38,926 37,993 35,938
Industrial 56,210 55,331 54,196 52,798 51,644
Other 945 929 903 911 863
- ----------------------------------------------------------------------------------------------------------------------------
Total retail 143,944 141,500 133,242 131,819 127,592
Sales for resale within service area 9,440 9,847 9,884 10,935 9,472
Sales for resale outside service area 12,929 12,988 13,761 10,777 9,143
- ----------------------------------------------------------------------------------------------------------------------------
Total 166,313 164,335 156,887 153,531 146,207
============================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 7.15 7.27 7.23 7.21 7.25
Commercial 6.32 6.62 6.67 6.74 6.91
Industrial 3.98 4.10 3.95 4.04 4.27
Total retail 5.62 5.85 5.74 5.81 5.96
Sales for resale 3.68 3.92 3.75 3.86 4.38
Total sales 5.36 5.58 5.44 5.54 5.76
Average Annual Kilowatt-Hour
Use Per Residential Customer 13,107 13,379 12,296 12,824 12,722
Average Annual Revenue Per Residential Customer $937.81 $972.89 $889.50 $925.12 $922.83
Plant Nameplate Capacity Owned (year-end) (megawatts) 31,197 31,161 31,146 31,076 30,733
Maximum Peak-Hour Demand (megawatts):
Winter 25,203 21,108 22,969 22,631 21,422
Summer 30,578 28,934 27,334 27,190 27,420
System Reserve Margin (at peak) (percent) 8.5 12.8 15.0 14.0 9.4
Annual Load Factor (percent) 59.2 60.0 59.4 62.3 59.5
Plant Availability (percent):
Fossil-steam 83.3 85.2 88.2 86.4 86.7
Nuclear 89.9 87.8 88.8 89.7 88.3
- ----------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 73.1 72.8 74.7 73.3 72.5
Nuclear 15.7 15.4 16.5 16.7 16.4
Hydro 2.3 3.9 4.3 4.1 4.1
Oil and gas 2.8 3.3 1.7 1.5 1.7
Purchased power 6.1 4.6 2.8 4.4 5.3
- ----------------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0 100.0 100.0
============================================================================================================================
II-47
ALABAMA POWER COMPANY
FINANCIAL SECTION
II-48
MANAGEMENT'S REPORT
Alabama Power Company 1999 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 16, 2000
II-49
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, 1999 and 1998, and the related
statements of income, common stockholder's equity, and cash flows for each of
the three years in the period ended December 31, 1999. 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 auditing standards generally
accepted in the United States. 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 11-59 through 11-77)
referred to above present fairly, in all material respects, the financial
position of Alabama Power Company as of December 31, 1999 and 1998, and the
results of its operations and its cash flows for each of the three years in the
period ended December 31, 1999, in conformity with accounting principles
generally accepted in the United States.
/s/Arthur Andersen LLP
Birmingham, Alabama
February 16, 2000
II-50
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Alabama Power Company 1999 Annual Report
RESULTS OF OPERATIONS
Earnings
Alabama Power Company's 1999 net income after dividends on preferred stock was
$400 million, representing a $23 million (6 percent) increase from the prior
year. This improvement is primarily attributable to a decrease in amortization
related to premiums paid to reacquire debt 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 1998, earnings were $377 million, representing a 0.3 percent increase
from the prior year. This increase was due 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 related
to premiums paid to reacquire debt pursuant to an APSC order.
The return on average common equity for 1999 was 13.85 percent compared to
13.63 percent in 1998, and 13.76 percent in 1997.
Revenues
Operating revenues for 1999 were $3.4 billion, reflecting a slight decrease from
1998. The following table summarizes the principal factors that have affected
operating revenues for the past three years:
Increase (Decrease) From Prior Year
-----------------------------------------
1999 1998 1997
-----------------------------------------
(in thousands)
Retail --
Growth and price
changes $ 27,893 $ 75,642 $ 33,813
Weather (17,871) 55,282 (22,973)
Fuel cost recovery
and other 20,418 138,944 31,353
- ---------------------------------------------------------------------
Total retail 30,440 269,868 42,193
- ---------------------------------------------------------------------
Sales for resale --
Non affiliates (33,596) 17,950 39,354
Affiliates (11,123) (58,233) (54,825)
- ---------------------------------------------------------------------
Total sales for resale (44,719) (40,283) (15,471)
Other operating
revenues 13,380 7,677 1,614
- ---------------------------------------------------------------------
Total operating
revenues $ (899) $237,262 $ 28,336
=====================================================================
Percent change (0.03)% 7.53% 0.91%
- ---------------------------------------------------------------------
Retail revenues of $2.8 billion in 1999 increased
$30 million (1.1 percent) from the prior year, compared with an increase of $270
million (10.7 percent) in 1998. The primary contributors to the increase in
revenues in 1999 were continued growth in the Company's service territory, as
well as an increase in fuel revenues. These increases were offset by the effect
of milder temperatures in 1999 as compared to 1998.
The $13 million (25.2 percent) increase in other operating revenues in 1999
as compared to 1998 was due primarily to an increase in steam sales in
conjunction with the operation of the Company's co-generation facilities. The
increase is the result of two new co-generation facilities placed in service in
1999.
Retail revenues in 1998 increased $270 million (10.7 percent) over 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
II-51
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 1999 Annual Report
increased fuel revenues. Fuel revenues were higher in 1998 as compared to 1997
due to higher fuel costs and an increase in purchased power. 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.
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. Revenues from long-term power contracts have both a capacity and
energy component. 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 of the unit power contracts were as
follows:
1999 1998 1997
-------------------------------------------
(in millions)
Capacity $122 $142 $136
Energy 112 118 135
------------------------------------------------------------
Total $234 $260 $271
=============================================================
Capacity revenues from non-affiliates decreased 13.9 percent in 1999
compared to the prior year. This decrease is attributable to the lowering of the
equity return under formula rate contracts, as well as other adjustments and
true-ups related to contractual pricing. Capacity revenues from non-affiliates
in 1998 increased 4.1 percent compared to 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 did not have a significant impact on earnings.
Kilowatt-hour (KWH) sales for 1999 and the percent change by year were as
follows:
KWH Percent Change
-------------------------------------------
1999 1999 1998 1997
-------------------------------------------
(millions)
Residential 15,699 (0.6)% 10.2% (1.8)%
Commercial 12,314 3.4 5.1 3.9
Industrial 21,943 1.7 4.2 3.6
Other 201 2.3 8.3 (6.3)
-----------
Total retail 50,157 1.4 6.2 1.9
Sales for resale -
Non-affiliates 12,438 5.0 (3.2) 29.9
Affiliates 5,032 (15.8) (33.5) (12.6)
-----------
Total 67,627 0.5% (0.9)% 3.7%
- ------------------------------------------------------------------
The increases in 1999 and 1998 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 2.9 percent
annually on average during 2000 through 2004.
Expenses
Total operating expenses of $2.5 billion for 1999 were down $13.4 million or 0.5
percent compared with 1998. This decrease was mainly due to a $15 million
decrease in fuel and purchased power costs and a $23 million decrease in
maintenance expense, offset by an increase in taxes other than income taxes of
$12 million.
Total operating expenses of $2.5 billion for 1998 were up $203 million or
8.8 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.
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
II-52
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 1999 Annual Report
fuel per net KWH generated were as follows:
----------------------------
1999 1998 1997
----------------------------
Total generation
(billions of KWHs) 63 63 65
Sources of generation
(percent) --
Coal 72 72 72
Nuclear 20 18 20
Hydro 5 8 8
Oil & Gas 3 2 *
Average cost of fuel per net
KWH generated
(cents) -- 1.44 1.54 1.49
- ----------------------------------------------------------------
* Not meaningful because of minimal generation from fuel source.
Total fuel and purchased power costs of $1.1 billion in 1999 decreased $15
million (1 percent), while total energy sales increased 329 million kilowatt
hours (0.5 percent) compared with the amounts recorded in 1998. Continued
efforts to control energy costs helped lower the average cost of fuel per net
kilowatt hour generated in 1999.
Fuel and purchased power costs in 1998 increased $111 million (11 percent)
over 1997 due primarily to lower levels of nuclear and hydro generation, which
were replaced by the use of peaking units and purchased power.
Purchased power consists primarily of purchases from affiliates in 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.
The 7.5 percent decrease in maintenance expense in 1999 as compared to 1998
is primarily attributable to a decrease in distribution expenses. The 23.8
percent increase in maintenance expenses in 1998 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.
Depreciation and amortization expense increased 2.6 percent in 1999 and
1998. These increases reflect additions to property, plant, and equipment.
Taxes other than income taxes increased $12 million (6.0 percent) in 1999 as
compared to 1998. This increase is attributable to increases in real and
personal property taxes and public utility license taxes.
Total net interest and other charges decreased $38 million (12.3 percent) in
1999. This decrease results primarily from a decrease in the amortization of
premiums on reacquired debt pursuant to an APSC order. Total net interest and
other charges increased $55.7 million (22 percent) in 1998 primarily due to an
increase in the amortization of premiums on reacquired debt, pursuant to an APSC
order. See Note 3 to the financial statements under "Retail Rate Adjustment
Procedures" for additional details.
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 lives. 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, including the ability of the Company to achieve energy sales
growth in 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.
II-53
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 1999 Annual Report
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, new short and long-term contracts with
neighboring utilities, energy conservation practiced by customers, the
elasticity of demand, and the rate of economic growth in the Company's
traditional 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/or 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.
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 continues to
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 and results of operations.
Continuing to be a low-cost producer could provide opportunities to increase
market share and profitability in markets that evolve with changing regulation.
Conversely, if the Company does not remain a low-cost producer and provide
quality service, then energy sales growth could be limited, and this could
significantly erode earnings.
On December 20, 1999, the Federal Energy Regulatory Commission (FERC) issued
its final rule on Regional Transmission Organizations (RTOs). The order
encourages utilities owning transmission systems to form RTOs on a voluntary
basis. To facilitate the development of RTOs, the FERC will convene regional
conferences for utilities, customers, and other members of the public to discuss
the formation of RTOs. In addition to participating in the regional conferences,
utilities owning transmission systems, including Southern Company, are required
to make a filing by October 15, 2000. The filing must contain either a proposal
for RTO participation or a description of the efforts made to participate in an
RTO, the reasons for non-participation, any obstacles to participation, and any
plans for further work toward participation. The RTOs that are proposed in the
filings should be operational by December 15, 2001. The Company is evaluating
this issue and formulating its response. The outcome of this matter cannot
presently be determined.
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
II-54
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 1999 Annual Report
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.
New Accounting Standard
The FASB has issued Statement No. 133, Accounting for Derivative Instruments and
Hedging Activities, which must be adopted by January 1, 2001. 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.
Year 2000 Challenge
The work undertaken by the Company to prepare critical computer systems and
other date sensitive devices to function correctly in the Year 2000 was
successful. There were no material incidents reported and no disruption of
electric service within the service area. There were no reports of significant
events regarding third parties that impacted revenues or expenses.
For the Company, original projected total costs for Year 2000 readiness,
including the Company's share of costs of Southern Nuclear Operating Company,
were approximately $36 million; revised projected costs are $33 million. These
costs include labor necessary to identify, test, and renovate affected devices
and systems, and costs for fulfilling reporting requirements to state and
federal agencies. From its inception through December 31, 1999, the Year 2000
program costs, recognized primarily as expense, amounted to $32 million.
Exposure to Market Risk
Due to cost-based rate regulation, the Company has 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
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, 1999,
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, 1999, a near-term 100 basis point
change in interest rates would not materially affect the financial statements.
II-55
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 1999 Annual Report
FINANCIAL CONDITION
Overview
The Company's financial condition remained stable in 1999. 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 $809 million in 1999. The
majority of funds needed for gross property additions for the last several years
have been provided from operating activities, principally from earnings and
non-cash charges to income such as depreciation and deferred income taxes. The
Statements of Cash Flows provide additional details.
Capital Structure
The Company's ratio of common equity to total capitalization -- including
short-term debt -- was 42.4 percent in 1999 and 1998, and 44.7 percent in 1997.
During 1999, the Company issued $650 million of senior notes, the proceeds
of which were used primarily to redeem first mortgage bonds and repay short-term
indebtedness, and the Company redeemed $50 million of preferred stock.
Additionally, in February 1999, Alabama Power Capital Trust III, of which
the Company owns all of the common securities, issued $50 million of auction
rate mandatorily redeemable preferred securities. See Note 9 to the financial
statements for additional information.
Capital Requirements
Capital expenditures are estimated to be $831 million for 2000, $743 million for
2001, and $860 million for 2002. See Note 4 to the financial statements for
additional details.
Actual construction costs may vary from estimates 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.
Other Capital Requirements
In addition to the funds needed for the capital budget, approximately $100
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
On November 3, 1999, the Environmental Protection Agency (EPA), brought a civil
action against the Company in the U. S. District Court. The complaint alleges
violations of the prevention of significant deterioration and new source review
provisions of the Clean Air Act with respect to coal-fired generating facilities
at the Company's Plants Miller, Barry and Gorgas. The civil action requests
penalties and injunctive relief, including an order requiring the installation
of the best available control technology at the affected units. The EPA
concurrently issued a notice of violation to the Company relating to these
specific facilities, as well as Plants Greene County and Gaston. In early 2000,
the EPA filed a motion to amend its complaint to add the violations alleged in
its notice of violation. The complaint and the notice of violation are similar
to those brought against and issued to several other electric utilities. The
complaint and the notice of violation allege that the Company failed to secure
necessary permits or install additional pollution control equipment when
performing maintenance and construction at coal burning plants constructed or
under construction prior to 1978. The Company believes that it complied with
applicable laws and EPA regulations and interpretations in effect at the time
the work in question took place. The Clean Air Act authorizes civil penalties
of up to $27,500 per day per violation at each generating unit. Prior to
January 30, 1997, the penalty was $25,000 per day. An adverse outcome of this
matter could require substantial capital expenditures that cannot be determined
at this time and possibly require payment of substantial penalties. This could
affect future results of operations, cash flows, and possibly financial
condition if such costs are not recovered through regulated rates.
II-56
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 1999 Annual Report
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 integrated Southeast utilities 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 currently uses emission
allowances and increased fuel switching, and/or the installation of flue gas
desulfurization equipment at selected plants. Also, equipment to control
nitrogen oxide emissions was installed on additional system fossil-fired units
as necessary to meet Phase II limits. Compliance for Phase II increased total
estimated construction expenditures in 1999 by approximately $65 million.
The State of Alabama and the EPA are currently evaluating draft plans to
reach attainment with the one hour standard for ozone in the Birmingham
non-attainment area. Provisions of that plan would require nitrogen oxide
reductions at certain Company facilities by May 2003. The Company estimates the
capital cost to comply with the plan to be approximately $138 million, all of
which remains to be spent.
A significant portion of costs related to the acid rain and ozone
non-attainment 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 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 reduction rule to the states for implementation. The final rule affects 22
states including Alabama. The EPA's July 1997 standards and the September 1998
rule are being challenged in the courts by several states and industry groups.
Implementation of the final state rules for these three initiatives could
require substantial further reductions in nitrogen oxide and sulfur dioxide
emissions from fossil-fired generating facilities and other industries in these
states. Additional compliance costs and capital expenditures resulting from the
implementation of these rules and standards 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: additional controls for hazardous
air pollutant emissions and control strategies to reduce regional haze. The
impact of any new standards will depend on the development and implementation of
applicable regulations.
In addition to rules and pending changes to rules under the Clean Air Act,
the Company must comply with other environmental laws and regulations including
water discharge permits, solid and hazardous waste disposal, use of materials
controlled by the Toxic Substances Control Act, and reporting requirements under
the Comprehensive Environmental Response, Compensation, and Liability Act. Under
these various requirements and regulations, the Company could incur costs to
implement water discharge requirements, clean up properties containing hazardous
substances, or replace equipment rendered useless by changing requirements. The
exact impact of any requirements would depend on specific regulatory actions and
cannot be determined at this time.
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-57
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 1999 Annual Report
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. The Company has no restrictions on the
amounts of unsecured indebtedness it may incur. However, to issue additional
first mortgage bonds and preferred stock, the Company must comply with certain
earnings coverage requirements designated in its mortgage indenture and
corporate charter. The Company's coverages are at a level that would permit any
necessary amount of security sales at current interest and dividend rates.
As required by the Nuclear Regulatory Commission and as ordered by the APSC,
the Company has established external trust funds for nuclear decommissioning
costs. In 1994, the Company also established an external trust fund for
postretirement benefits as ordered by the APSC. The cumulative effect of funding
these items over a long period will diminish internally funded capital and may
require capital from other sources. For additional information concerning
nuclear decommissioning costs, see Note 1 to the financial statements under
"Depreciation and Nuclear Decommissioning."
Cautionary Statement Regarding Forward-Looking
Information
The Company's 1999 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; 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-58
STATEMENTS OF INCOME
For the Years Ended December 31, 1999, 1998, and 1997
Alabama Power Company 1999 Annual Report
- ------------------------------------------------------------------------------------------------------------------------
1999 1998 1997
- ------------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Revenues:
Retail sales $2,811,117 $2,780,677 $2,510,809
Sales for resale --
Non-affiliates 415,377 448,973 431,023
Affiliates 92,439 103,562 161,795
Other revenues 66,541 53,161 45,484
- ------------------------------------------------------------------------------------------------------------------------
Total operating revenues 3,385,474 3,386,373 3,149,111
- ------------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
Fuel 855,632 900,309 896,014
Purchased power --
Non-affiliates 93,204 92,998 41,795
Affiliates 180,563 150,897 95,538
Other 531,696 527,954 510,203
Maintenance 277,724 300,383 242,691
Depreciation and amortization 347,574 338,822 330,377
Taxes other than income taxes 204,645 193,049 185,062
- ------------------------------------------------------------------------------------------------------------------------
Total operating expenses 2,491,038 2,504,412 2,301,680
- ------------------------------------------------------------------------------------------------------------------------
Operating Income 894,436 881,961 847,431
Other Income (Expense):
Interest income 55,896 68,553 37,844
Equity in earnings of unconsolidated subsidiaries (Note 6) 2,650 5,271 5,250
Other, net (24,861) (37,050) (39,506)
- ------------------------------------------------------------------------------------------------------------------------
Earnings Before Interest and Income Taxes 928,121 918,735 851,019
- ------------------------------------------------------------------------------------------------------------------------
Interest Charges and Other:
Interest on long-term debt 191,895 192,426 167,172
Interest on notes payable 9,865 11,012 22,787
Amortization of debt discount, premium and expense, net (Note 3) 11,159 42,494 9,645
Other interest charges 32,316 40,008 31,250
Distributions on preferred securities of subsidiary (Note 9) 24,662 22,354 21,763
- ------------------------------------------------------------------------------------------------------------------------
Total interest charges and other, net 269,897 308,294 252,617
- ------------------------------------------------------------------------------------------------------------------------
Earnings Before Income Taxes 658,224 610,441 598,402
Income taxes (Note 8) 241,880 218,575 207,877
- ------------------------------------------------------------------------------------------------------------------------
Net Income 416,344 391,866 390,525
Dividends on Preferred Stock 16,464 14,643 14,586
- ------------------------------------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred Stock $ 399,880 $ 377,223 $ 375,939
========================================================================================================================
The accompanying notes are an integral part of these statements.
II-59
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1999, 1998, and 1997
Alabama Power Company 1999 Annual Report
- -------------------------------------------------------------------------------------------------------------------------
1999 1998 1997
- -------------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Activities:
Net income $ 416,344 $ 391,866 $ 390,525
Adjustments to reconcile net income
to net cash provided from operating activities --
Depreciation and amortization 403,332 425,167 394,572
Deferred income taxes and investment tax credits, net 29,039 79,430 (12,429)
Other, net (12,661) (66,739) (11,353)
Changes in certain current assets and liabilities --
Receivables, net 33,509 49,747 (30,268)
Fossil fuel stock (1,344) (9,052) 7,518
Materials and supplies (17,968) 11,932 6,191
Accounts payable (38,556) 26,583 (9,745)
Energy cost recovery, retail (97,869) (95,427) 7,108
Other 5,930 (9,803) 13,318
- -------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities 719,756 803,704 755,437
- -------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (809,044) (610,132) (451,167)
Other (72,218) (52,940) (51,791)
- -------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities (881,262) (663,072) (502,958)
- -------------------------------------------------------------------------------------------------------------------------
Financing Activities:
Increase (decrease) in notes payable, net 96,824 (306,882) (57,971)
Proceeds --
Other long-term debt 751,650 1,462,990 258,800
Preferred securities 50,000 - 200,000
Preferred stock - 200,000 -
Capital contributions from parent company 204,347 30,000 -
Redemptions --
First mortgage bonds (470,000) (771,108) (74,951)
Other long-term debt (104,836) (107,776) (951)
Preferred stock (50,000) (88,000) (184,888)
Payment of preferred stock dividends (15,788) (15,596) (22,524)
Payment of common stock dividends (399,600) (367,100) (339,600)
Other (15,864) (66,869) (16,024)
- -------------------------------------------------------------------------------------------------------------------------
Net cash provided from (used for) financing activities 46,733 (30,341) (238,109)
- -------------------------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents (114,773) 110,291 14,370
Cash and Cash Equivalents at Beginning of Period 134,248 23,957 9,587
- -------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ 19,475 $ 134,248 $ 23,957
=========================================================================================================================
Supplemental Cash Flow Information:
Cash paid during the period for --
Interest (net of amount capitalized) $229,305 $234,360 $209,919
Income taxes (net of refunds) 170,121 188,942 207,653
- -------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
II-60
BALANCE SHEETS
At December 31, 1999 and 1998
Alabama Power Company 1999 Annual Report
- -----------------------------------------------------------------------------------------------------------------
Assets 1999 1998
- -----------------------------------------------------------------------------------------------------------------
(in thousands)
Current Assets:
Cash and cash equivalents $ 19,475 $ 134,248
Receivables --
Customer accounts receivable 265,900 272,872
Unrecovered retail fuel clause revenue 168,627 70,758
Other accounts and notes receivable 42,137 32,394
Affiliated companies 40,083 39,981
Accumulated provision for uncollectible accounts (4,117) (1,855)
Refundable income taxes 17,997 52,117
Fossil fuel stock, at average cost 84,582 83,238
Materials and supplies, at average cost 167,637 149,669
Other 46,011 45,550
- -----------------------------------------------------------------------------------------------------------------
Total current assets 848,332 878,972
- -----------------------------------------------------------------------------------------------------------------
Property, Plant, and Equipment:
In service (Note 1) 11,783,078 11,352,838
Less accumulated provision for depreciation 4,901,384 4,666,513
- -----------------------------------------------------------------------------------------------------------------
6,881,694 6,686,325
Nuclear fuel, at amortized cost 106,836 95,575
Construction work in progress 715,153 525,359
- -----------------------------------------------------------------------------------------------------------------
Total property, plant, and equipment 7,703,683 7,307,259
- -----------------------------------------------------------------------------------------------------------------
Other Property and Investments:
Equity investments in unconsolidated subsidiaries (Note 6) 34,891 34,298
Nuclear decommissioning trusts (Note 1) 286,653 232,183
Other 12,156 12,915
- -----------------------------------------------------------------------------------------------------------------
Total other property and investments 333,700 279,396
- -----------------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets:
Deferred charges related to income taxes (Note 8) 330,405 362,953
Prepaid pension costs 213,971 169,393
Debt expense, being amortized 9,563 8,602
Premium on reacquired debt, being amortized 83,895 83,440
Department of Energy assessments (Note 1) 27,685 31,088
Other 97,470 104,595
- -----------------------------------------------------------------------------------------------------------------
Total deferred charges and other assets 762,989 760,071
- -----------------------------------------------------------------------------------------------------------------
Total Assets $9,648,704 $9,225,698
=================================================================================================================
The accompanying notes are an integral part of these balance sheets.
II-61
BALANCE SHEETS
At December 31, 1999 and 1998
Alabama Power Company 1999 Annual Report
- ------------------------------------------------------------------------------------------------------------------
Liabilities and Stockholder's Equity 1999 1998
- ------------------------------------------------------------------------------------------------------------------
(in thousands)
Current Liabilities:
Securities due within one year (Note 11) $ 100,943 $ 521,209
Notes payable 96,824 -
Accounts payable --
Affiliated 91,315 79,844
Other 140,842 188,074
Customer deposits 31,704 29,235
Taxes accrued --
Income taxes 100,569 82,219
Other 18,295 17,559
Interest accrued 26,365 38,166
Vacation pay accrued 30,112 28,390
Other 84,267 79,095
- ------------------------------------------------------------------------------------------------------------------
Total current liabilities 721,236 1,063,791
- ------------------------------------------------------------------------------------------------------------------
Long-term debt (See accompanying statements) 3,190,378 2,646,566
- ------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes (Note 8) 1,240,344 1,202,971
Deferred credits related to income taxes (Note 8) 265,102 315,735
Accumulated deferred investment tax credits 260,367 271,611
Employee benefits provisions 82,298 81,115
Prepaid capacity revenues (Note 7) 79,703 96,080
Other 155,901 149,250
- ------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 2,083,715 2,116,762
- ------------------------------------------------------------------------------------------------------------------
Company obligated mandatorily redeemable preferred
securities of subsidiary trusts holding company junior
subordinated notes (See accompanying statements) (Note 9) 347,000 297,000
- ------------------------------------------------------------------------------------------------------------------
Cumulative preferred stock (See accompanying statements) 317,512 317,512
- ------------------------------------------------------------------------------------------------------------------
Common stockholder's equity (See accompanying statements) 2,988,863 2,784,067
- ------------------------------------------------------------------------------------------------------------------
Total Liabilities and Stockholder's Equity $9,648,704 $9,225,698
==================================================================================================================
The accompanying notes are an integral part of these balance sheets.
II-62
STATEMENTS OF CAPITALIZATION
At December 31, 1999 and 1998
Alabama Power Company 1999 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------------
1999 1998 1999 1998
- ----------------------------------------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
Long-Term Debt:
First mortgage bonds --
Maturity Interest Rates
-------- --------------
August 1, 1999 6.375% $ - $ 170,000
March 1, 2000 6.00% 100,000 100,000
January 1, 2003 7.00% - 125,000
February 1, 2003 6.75% - 175,000
2023 through 2024 7.30% - 9.00% 500,000 500,000
- ----------------------------------------------------------------------------------------------------------------------------------
Total first mortgage bonds 600,000 1,070,000
- ----------------------------------------------------------------------------------------------------------------------------------
Senior notes --
5.35% due November 15, 2003 156,200 156,200
7.125% due August 15, 2004 250,000 -
5.49% due November 1, 2005 225,000 225,000
7.125% due October 1, 2007 200,000 -
5.375% due October 1, 2008 160,000 160,000
6.25% to 7.125% due 2010-2048 1,207,622 1,008,800
- ----------------------------------------------------------------------------------------------------------------------------------
Total senior notes 2,198,822 1,550,000
- ----------------------------------------------------------------------------------------------------------------------------------
Other long-term debt --
Pollution control revenue bonds --
Collateralized:
5.50% to 6.50% due 2023-2024 24,400 126,050
Variable rates (4.75% to 4.85% at 1/1/00)
due 2015-2017 89,800 89,800
Non-collateralized:
7.25% due 2003 - 1,000
Variable rates (3.50% to 6.03% at 1/1/00)
due 2021-2028 425,940 324,290
- ----------------------------------------------------------------------------------------------------------------------------------
Total other long-term debt 540,140 541,140
- ----------------------------------------------------------------------------------------------------------------------------------
Capitalized lease obligations 5,111 6,119
- ----------------------------------------------------------------------------------------------------------------------------------
Unamortized debt premium (discount), net (52,752) (49,484)
- ----------------------------------------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
requirement -- $215.9 million) 3,291,321 3,117,775
Less amount due within one year 100,943 471,209
- ----------------------------------------------------------------------------------------------------------------------------------
Long-term debt excluding amount due within one year $3,190,378 $2,646,566 46.6% 43.8%
- ----------------------------------------------------------------------------------------------------------------------------------
II-63
STATEMENTS OF CAPITALIZATION (continued) At December 31, 1999 and 1998
Alabama Power Company 1999 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------------
1999 1998 1999 1998
- ----------------------------------------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
Company Obligated Mandatorily
Redeemable Preferred Securities:
$25 liquidation value --
7.375% $ 97,000 $97,000
7.60% 200,000 200,000
Auction rate (6.42% at 1/1/00) 50,000 -
- ---------------------------------------------------------------------------------------------------------------------------------
Total (annual distribution requirement -- $25.6 million) 347,000 297,000 5.1 4.9
- ----------------------------------------------------------------------------------------------------------------------------------
Cumulative Preferred Stock:
$100 par or stated value --
4.20% to 4.92% 47,512 47,512
$25 par or stated value --
5.20% to 5.83% 200,000 200,000
Auction rates -- at 1/1/00
4.22% to 4.50% 70,000 120,000
- ----------------------------------------------------------------------------------------------------------------------------------
Total (annual dividend requirement -- $15.9 million) 317,512 367,512
Less amount due within one year - 50,000
- ----------------------------------------------------------------------------------------------------------------------------------
Total excluding amount due within one year 317,512 317,512 4.6 5.2
- ----------------------------------------------------------------------------------------------------------------------------------
Common Stockholder's Equity:
Common stock, par value $40 per share --
Authorized - 6,000,000 shares
Outstanding - 5,608,955 shares in 1999 and 1998
Par value 224,358 224,358
Paid-in capital 1,538,992 1,334,645
Premium on Preferred Stock 99 99
Retained earnings 1,225,414 1,224,965
- ----------------------------------------------------------------------------------------------------------------------------------
Total common stockholder's equity 2,988,863 2,784,067 43.7 46.1
- ----------------------------------------------------------------------------------------------------------------------------------
Total Capitalization $6,843,753 $6,045,145 100.0% 100.0%
==================================================================================================================================
The accompanying notes are an integral part of these statements.
II-64
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
For the Years Ended December 31, 1999, 1998, and 1997
Alabama Power Company 1999 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------
Premium on
Common Paid-In Preferred Retained
Stock Capital Stock Earnings Total
- -----------------------------------------------------------------------------------------------------------------------------
(in thousands)
Balance at January 1, 1997 $224,358 $1,304,645 $146 $1,185,128 $2,714,277
Net income after dividends on preferred stock - - - 375,939 375,939
Cash dividends on common stock - - - (339,600) (339,600)
Other - - (47) - (47)
- -----------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1997 224,358 1,304,645 99 1,221,467 2,750,569
Net income after dividends on preferred stock - - - 377,223 377,223
Capital contributions from parent company - 30,000 - - 30,000
Cash dividends on common stock - - - (367,100) (367,100)
Other - - - (6,625) (6,625)
- -----------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1998 224,358 1,334,645 99 1,224,965 2,784,067
Net income after dividends on preferred stock - - - 399,880 399,880
Capital contributions from parent company - 204,347 - - 204,347
Cash dividends on common stock - - - (399,600) (399,600)
Other - - - 169 169
- -----------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1999 $224,358 $1,538,992 $99 $1,225,414 $2,988,863
=============================================================================================================================
The accompanying notes are an integral part of these statements.
II-65
NOTES TO FINANCIAL STATEMENTS
Alabama Power Company 1999 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 integrated Southeast utilities,
Southern Company Services (SCS), 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 integrated Southeast utilities --Alabama Power
Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company,
and Savannah Electric and Power Company-- provide electric service in four
states. Contracts among the integrated Southeast utilities - related to
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). SCS
provides, at cost, specialized services to Southern Company and its subsidiary
companies. Southern LINC provides digital wireless communications services to
the integrated Southeast utilities 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. Southern Nuclear provides
services to Southern Company's nuclear power plants. Southern Energy acquires,
develops, builds, owns, and operates power production and delivery facilities
and provides a broad range of energy-related services to utilities and
industrial companies in selected countries around the world. Southern Energy
businesses include independent power projects, integrated utilities, a
distribution company, and energy trading and marketing businesses outside the
southeastern United States.
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 its 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.
Related-Party Transactions
The Company has an agreement with SCS under which the following services are
rendered to the Company at cost: general and design engineering, purchasing,
accounting and statistical, finance and treasury, tax, information resources,
marketing, auditing, insurance and pension, human resources, systems and
procedures, and other services with respect to business and operations and power
pool transactions. Costs for these services amounted to $218 million, $201
million, and $154 million during 1999, 1998, and 1997, respectively.
The Company also has an agreement with Southern Nuclear to operate Plant
Farley and provide the following nuclear-related services at cost: general
executive and advisory services; general operations, management and technical
services; administrative services including procurement, accounting,
statistical, and employee relations; and other services with respect to business
and operations. Costs for these services amounted to $135 million, $137 million,
and $117 million during 1999, 1998, and 1997, respectively.
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.
II-66
NOTES (continued)
Alabama Power Company 1999 Annual Report
Regulatory assets and (liabilities) reflected in the Balance Sheets at
December 31 relate to the following:
1999 1998
-----------------------
(in millions)
Deferred income tax charges $ 330 $ 363
Deferred income tax credits (265) (316)
Premium on reacquired debt 84 83
Department of Energy assessments 28 31
Vacation pay 30 28
Natural disaster reserve (19) (19)
Other, net 59 51
- ----------------------------------------------------------------
Total $ 247 $ 221
================================================================
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 related 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 values.
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. 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 regulated 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 continue 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 $63
million in 1999, $59 million in 1998, and $68 million in 1997. 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 contract, 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. Planning for additional
on-site spent fuel storage capacity at Plant Farley is in progress, with the
intent to place additional on-site spent fuel storage capacity in operation as
early as 2005. In addition, through Southern Nuclear, the Company is a member of
Private Fuel Storage, LLC, a joint utility effort to develop a private spent
fuel storage facility for temporary storage of spent nuclear fuel. This facility
is planned to begin operation as early as the year 2003.
Also, the Energy Policy Act of 1992 required the establishment of a Uranium
Enrichment Decontamination and Decommissioning Fund, which is 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, 1999, under this law to be approximately $28 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 1999 and 1998, and 3.3 percent in 1997. 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
II-67
NOTES (continued)
Alabama Power Company 1999 Annual Report
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.
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 -- based on the most current study 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 amount expensed in 1999 and fund balances as of
December 31, 1999 were:
(in millions)
Amount expensed in 1999 $ 18
-------------------------------------------------------------
Accumulated provisions:
External trust funds, at fair value $ 287
Internal reserves 40
-------------------------------------------------------------
Total $ 327
=============================================================
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. The Company expects the APSC 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.
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 8.8 percent in 1999, 9.0 percent in 1998, and 5.8 percent in 1997.
AFUDC, net of income tax, as a percent of net income after dividends on
preferred stock was 4.7 percent in 1999, 1.8 percent in 1998, and 0.8 percent in
1997.
Property, Plant, and Equipment
Property, plant, and equipment 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
II-68
NOTES (continued)
Alabama Power Company 1999 Annual Report
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 capitalized.
Financial Instruments
The Company's 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, 1999 $3,286 $3,045
At December 31, 1998 3,112 3,195
Preferred Securities:
At December 31, 1999 347 299
At December 31, 1998 297 307
--------------------------------------------------------------
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. At
December 31, 1999, the reserve balance was $19 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 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 APSC and FERC. The measurement date for plan assets and obligations is
September 30 of each year.
The weighted average rates assumed in the actuarial calculations for both
the pension and postretirement benefit plans were:
1999 1998
- ---------------------------------------------------------------
Discount 7.50% 6.75%
Annual salary increase 5.00 4.25
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
---------------------------
1999 1998
- ---------------------------------------------------------------
(in millions)
Balance at beginning of year $868 $813
Service cost 23 22
Interest cost 57 59
Benefits paid (51) (51)
Actuarial (gain) loss and
employee transfers (24) 25
- ---------------------------------------------------------------
Balance at end of year $873 $868
===============================================================
Plan Assets
---------------------------
1999 1998
- ---------------------------------------------------------------
(in millions)
Balance at beginning of year $1,461 $1,521
Actual return on plan assets 245 9
Benefits paid (51) (51)
Employee transfers (8) (18)
- ---------------------------------------------------------------
Balance at end of year $1,647 $1,461
===============================================================
II-69
NOTES (continued)
Alabama Power Company 1999 Annual Report
The accrued pension costs recognized in the Balance Sheets were as
follows:
1999 1998
- ---------------------------------------------------------------
(in millions)
Funded status $ 774 $ 593
Unrecognized transition obligation (25) (30)
Unrecognized prior service cost 36 39
Unrecognized net actuarial gain (571) (433)
- ---------------------------------------------------------------
Prepaid asset recognized in the
Balance Sheets $ 214 $ 169
===============================================================
Components of the pension plans' net periodic cost were as follows:
1999 1998 1997
- ---------------------------------------------------------------
(in millions)
Service cost $ 23 $ 22 $ 20
Interest cost 57 59 58
Expected return on plan assets (109) (102) (95)
Recognized net actuarial gain (14) (16) (13)
Net amortization (2) (2) (2)
- ---------------------------------------------------------------
Net pension income $ (45) $ (39) $(32)
===============================================================
Postretirement Benefits
Changes during the year in the accumulated benefit obligations and in the fair
value of plan assets were as follows:
Accumulated
Benefit Obligations
---------------------------
1999 1998
- ---------------------------------------------------------------
(in millions)
Balance at beginning of year $278 $252
Service cost 5 5
Interest cost 18 19
Benefits paid (10) (12)
Actuarial (gain) loss and
employee transfers (27) 14
- ---------------------------------------------------------------
Balance at end of year $264 $278
===============================================================
Plan Assets
---------------------------
1999 1998
- ---------------------------------------------------------------
(in millions)
Balance at beginning of year $137 $125
Actual return on plan assets 18 4
Employer contributions 16 20
Benefits paid (10) (12)
- ---------------------------------------------------------------
Balance at end of year $161 $137
===============================================================
The accrued postretirement costs recognized in the Balance Sheets were
as follows:
1999 1998
- ---------------------------------------------------------------
(in millions)
Funded status $(103) $(141)
Unrecognized transition obligation 53 57
Unrecognized net actuarial
(gain) loss (12) 22
Fourth quarter contributions 8 8
- ---------------------------------------------------------------
Accrued liability recognized in the
Balance Sheets $ (54) $ (54)
===============================================================
Components of the plans' net periodic cost were as follows:
1999 1998 1997
- ---------------------------------------------------------------
(in millions)
Service cost $ 5 $ 5 $ 4
Interest cost 18 18 18
Expected return on plan assets (11) (9) (7)
Net amortization 4 4 4
- ---------------------------------------------------------------
Net postretirement cost $ 16 $ 18 $ 19
===============================================================
An additional assumption used in measuring the accumulated postretirement
benefit obligations was a weighted average medical care cost trend rate of 7.74
percent for 1999, decreasing gradually to 5.50 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,
1999 as follows:
1 Percent 1 Percent
Increase Decrease
- ---------------------------------------------------------------
(in millions)
Benefit obligation $ 17 $ (15)
Service and interest costs 1 (1)
===============================================================
Work Force Reduction Programs
The Company has incurred additional costs for work force reduction programs. The
costs related to these programs were $5.6 million, $19.4 million and $33.0
million for the years 1999, 1998 and 1997, 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 $1.2 million at
December 31, 1999.
II-70
NOTES (continued)
Alabama Power Company 1999 Annual Report
3. CONTINGENCIES AND REGULATORY
MATTERS
Lake Martin 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. The Company has appealed these judgments 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.
Additional actions have been filed by other landowners in the same
subdivision on Lake Martin against the same defendants, including the Company.
The plaintiffs assert substantially the same allegations as in the current
proceeding being appealed. The final outcome of these actions cannot now be
determined.
Environmental Protection Agency Litigation
On November 3, 1999, the Environmental Protection Agency (EPA), brought a civil
action against the Company in the U. S. District Court. The complaint alleges
violations of the prevention of significant deterioration and new source review
provision of the Clean Air Act with respect to coal-fired generating facilities
at the Company's Plants Miller, Barry and Gorgas. The civil action requests
penalties and injunctive relief, including an order requiring the installation
of the best available control technology at the affected units beginning at the
point of the alleged violations. The EPA concurrently issued a notice of
violation to the Company relating to these specific facilities, as well as
Plants Greene County and Gaston. In early 2000, the EPA filed a motion to
amend its complaint to add the violations alleged in its notice of violation.
The complaint and the notice of violation are similar to those brought against
and issued to several other electric utilities. The complaint and the notice of
violation allege that the Company failed to secure necessary permits or install
additional pollution control equipment when performing maintenance and
construction at coal burning plants constructed or under construction prior to
1978. The Company believes that it complied with applicable laws and the EPA's
regulations and interpretations in effect at the time the work in question took
place. The Clean Air Act authorizes civil penalties of up to $27,500 per day per
violation at each generating unit. Prior to January 30, 1997, the penalty was
$25,000 per day. An adverse outcome of this matter could require substantial
capital expenditures that cannot be determined at this time and possibly require
payment of substantial penalties. This could affect future results of
operations, cash flows, and possibly financial condition if such costs are not
recovered through regulated rates.
Retail Rate Adjustment Procedures
In November 1982, the APSC adopted rates that provide for periodic adjustments
based upon the Company's earned return on end-of-period retail common equity.
The rates also provide for adjustments to recognize the placing of new
generating facilities in retail service. Both increases and decreases have been
placed into effect since the adoption of these rates. The rate adjustment
procedures allow a return on common equity range of 13.0 percent to 14.5 percent
and limit increases or decreases in rates to 4 percent in any calendar year.
In June 1995, the APSC issued a rate order granting the Company's request
for gradual adjustments to move toward parity among customer classes. This order
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 Company did not
record any additional amounts in 1999 or 1997.
II-71
NOTES (continued)
Alabama Power Company 1999 Annual Report
The Company's ratemaking procedures will remain in effect until the APSC
votes to modify or discontinue them.
4. CAPITAL BUDGET
The Company's capital expenditures are currently estimated to total $831 million
in 2000, $743 million in 2001, and $860 million in 2002. Some of the more
significant items included in the Company's capital budget are as follows:
(i) The Company is replacing all six steam generators at Plant Farley. The
estimated remaining costs associated with this project, which will be
completed in 2001, amount to $100 million.
(ii) The Company is also constructing and installing 1,075 megawatts of capacity
and associated substation facilities at Plant Barry. Half of the capacity
is scheduled to go in service in 2000, with the remainder going in service
in 2001. The remaining projected expenditures related to these facilities
are $181 million.
(iii)Cogeneration facilities, with a capacity of 200 megawatts, are being
constructed in Theodore, Alabama, and will go in service in 2001. The
estimated remaining costs associated with this project total $81 million.
(iv) The capital budget reflects $472 million related to projected generation
capacity scheduled to be placed into service in 2003 and beyond.
In addition to the above items, significant construction will continue
related to transmission and distribution facilities and the upgrading of
generating plants.
The capital budget is subject to periodic review and revision, and actual
capital costs incurred may vary from estimates 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.
5. FINANCING 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. The Company has no restrictions on the
amounts of unsecured indebtedness it may incur. However, to issue additional
first mortgage bonds and preferred stock, the Company must comply with certain
earnings coverage requirements designated in its mortgage indenture and
corporate charter. The 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 $907 million
(including $418 million of such lines which are dedicated to funding purchase
obligations relating to variable rate pollution control bonds). Of these lines,
$517 million expire at various times during 2000 and $390 million expire in
2004. 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
II-72
NOTES (continued)
Alabama Power Company 1999 Annual Report
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, 1999, 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.
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, 1999, were as follows:
Year Commitments
- ---- ----------------
(in millions)
2000 $ 715
2001 672
2002 561
2003 469
2004 472
2005 - 2026 2,019
- ---------------------------------------------------------------
Total commitments $4,908
===============================================================
Operating Leases
The Company has entered into coal rail car rental agreements with various terms
and expiration dates. These expenses totaled $17.8 million in 1999, $5.8 million
in 1998, and $3.0 million in 1997. At December 31, 1999, estimated minimum
rental commitments for noncancellable operating leases were as follows:
Year Commitments
- ---- -----------------
(in millions)
2000 $ 20.0
2001 19.6
2002 19.2
2003 18.8
2004 18.4
2005 - 2017 64.3
- --------------------------------------------------------------
Total minimum payments $160.3
==============================================================
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 $92 million in 1999, $74 million
in 1998 and $73 million in 1997, 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.
II-73
NOTES (continued)
Alabama Power Company 1999 Annual Report
At December 31, 1999, the capitalization of SEGCO consisted of $50 million
of equity and $72 million of long-term debt on which the annual interest
requirement is $4.3 million. SEGCO paid dividends totaling $4.3 million in 1999,
$8.7 million in 1998, and $10.6 million in 1997, of which one-half of each was
paid to the Company. SEGCO's net income was $5.4 million, $7.5 million, and $8.5
million for 1999, 1998 and 1997, respectively.
The Company's percentage ownership and investment in jointly-owned
generating plants at December 31, 1999, 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 $ 97 $ 45
Plant Miller
Units 1 and 2 740 297
----------------------------------------------------------
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 $122 million in 1999, $142 million in 1998, and $136 million in
1997.
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 1,250 megawatts of capacity are scheduled to be sold through 2000.
Thereafter, these sales will remain at that approximate level -- unless reduced
by FP&L, FPC, and JEA for the periods after 2000 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,
1999, $81.5 million of such bonds was held by the escrow agent under the
contracts.
8. INCOME TAXES
At December 31, 1999, the tax-related regulatory assets and liabilities were
$330 million and $265 million, respectively. These assets are attributable to
tax benefits flowed through to customers in prior years and to taxes applicable
II-74
NOTES (continued)
Alabama Power Company 1999 Annual Report
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 income tax provisions are as follows:
1999 1998 1997
--------------------------------
(in millions)
Total provision for income taxes:
Federal --
Current $194 $123 $197
Deferred --
Current year (6) 59 33
Reversal of prior years 30 13 (44)
- -----------------------------------------------------------------
218 195 186
- -----------------------------------------------------------------
State --
Current 19 16 23
Deferred --
Current year 1 5 1
Reversal of prior years 4 2 (2)
- -----------------------------------------------------------------
24 23 22
- -----------------------------------------------------------------
Total $242 $218 $208
=================================================================
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:
1999 1998
-------------------
(in millions)
Deferred tax liabilities:
Accelerated depreciation $ 884 $ 861
Property basis differences 419 435
Fuel cost adjustment 65 29
Premium on reacquired debt 31 29
Pensions 60 50
Other 11 17
- -----------------------------------------------------------------
Total 1,470 1,421
- -----------------------------------------------------------------
Deferred tax assets:
Capacity prepayments 24 28
Other deferred costs 25 25
Postretirement benefits 22 20
Unbilled revenue 13 16
Other 63 56
- -----------------------------------------------------------------
Total 147 145
- -----------------------------------------------------------------
Net deferred tax liabilities 1,323 1,276
Portion included in current liabilities, net (83) (73)
- -----------------------------------------------------------------
Accumulated deferred income taxes
in the Balance Sheets $1,240 $1,203
=================================================================
Deferred investment tax credits are amortized over the lives 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 1999, 1998, and 1997. At December 31, 1999, 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:
1999 1998 1997
--------------------------
Federal statutory rate 35.0% 35.0% 35.0%
State income tax,
net of federal deduction 2.4 2.5 2.4
Non-deductible book
depreciation 1.6 1.5 1.5
Differences in prior years'
deferred and current tax rates (1.3) (1.6) (2.3)
Other (0.9) (1.6) (1.9)
- ---------------------------------------------------------------
Effective income tax rate 36.8% 35.8% 34.7%
===============================================================
II-75
NOTES (continued)
Alabama Power Company 1999 Annual Report
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.
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
Trust III 2/1999 50 Auction 52 2/2029
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, Alabama Power Capital Trust III (Trust III), of which
the Company owns all of the common securities, issued $50 million of auction
rate mandatorily redeemable preferred securities. The distribution rate of these
variable securities was 6.42% at January 1, 2000.
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. No principal or interest on these first mortgage bonds is payable
unless and until a default occurs on the installment purchase agreements.
In 1997, 1998, and 1999 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 2004 are as follows: $0.9 million in 2000, $0.8 million in 2001, $0.9
million in 2002, $0.9 million in 2003 and $1.0 million in 2004.
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:
1999 1998
------------------------
(in thousands)
First mortgage bond maturities
and redemptions $100,000 $470,000
Other long-term debt maturities
(Note 10) 943 1,209
-------------------------------------------------------------
Total long-term debt due within
one year 100,943 471,209
-------------------------------------------------------------
Preferred stock to be redeemed - 50,000
-------------------------------------------------------------
Total $100,943 $521,209
=============================================================
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.
12. NUCLEAR INSURANCE
Under the Price-Anderson Amendments Act of 1988 (the 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 $9.5 billion for public liability claims
II-76
NOTES (continued)
Alabama Power Company 1999 Annual Report
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 costs of replacement power in an
amount up to $3.5 million per week (starting 12 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 $19 million.
For all on-site property damage insurance policies for commercial nuclear
power plants, the NRC requires that the proceeds of such policies 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. 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, 1999, 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 1999 and 1998 are as follows:
Net Income
After
Dividends
Quarter Operating Operating on Preferred
Ended Revenues Income Stock
- -------------------- --------------------------------------------
(in millions)
March 1999 $ 714 $162 $ 63
June 1999 823 209 93
September 1999 1,116 388 201
December 1999 733 136 43
March 1998 $ 717 $173 $ 66
June 1998 864 235 95
September 1998 1,058 342 174
December 1998 748 132 42
- -----------------------------------------------------------------
The Company's business is influenced by seasonal weather conditions.
II-77
SELECTED FINANCIAL AND OPERATING DATA 1995-1999
Alabama Power Company 1999 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------------
1999 1998 1997 1996 1995
- ----------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands) $3,385,474 $3,386,373 $3,149,111 $3,120,775 $3,024,774
Net Income after Dividends
on Preferred Stock (in thousands) $399,880 $377,223 $375,939 $371,490 $360,894
Cash Dividends
on Common Stock (in thousands) $399,600 $367,100 $339,600 $347,500 $285,000
Return on Average Common Equity (percent) 13.85 13.63 13.76 13.75 13.61
Total Assets (in thousands) $9,648,704 $9,225,698 $8,812,867 $8,733,846 $8,744,360
Gross Property Additions (in thousands) $809,044 $610,132 $451,167 $425,024 $551,781
- ----------------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $2,988,863 $2,784,067 $2,750,569 $2,714,277 $2,690,374
Preferred stock 317,512 317,512 255,512 340,400 440,400
Company obligated mandatorily
redeemable preferred securities 347,000 297,000 297,000 97,000 -
Long-term debt 3,190,378 2,646,566 2,473,202 2,354,006 2,374,948
- ----------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $6,843,753 $6,045,145 $5,776,283 $5,505,683 $5,505,722
==================================================================================================================================
Capitalization Ratios (percent):
Common stock equity 43.7 46.1 47.6 49.3 48.9
Preferred stock 4.6 5.3 4.4 6.2 8.0
Company obligated mandatorily
redeemable preferred securities 5.1 4.9 5.2 1.7 -
Long-term debt 46.6 43.7 42.8 42.8 43.1
- ----------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0 100.0 100.0 100.0
==================================================================================================================================
Security Ratings:
First Mortgage Bonds -
Moody's A1 A1 A1 A1 A1
Standard and Poor's A+ A+ A+ A+ A+
Duff & Phelps AA- AA- AA- AA- A+
Preferred Stock -
Moody's a2 a2 a2 a2 a2
Standard and Poor's A- A A A A
Duff & Phelps A A 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 1,120,574 1,106,217 1,092,161 1,073,559 1,058,197
Commercial 188,368 182,738 177,362 171,827 166,480
Industrial 4,897 5,020 5,076 5,100 5,338
Other 735 733 728 732 725
- ----------------------------------------------------------------------------------------------------------------------------------
Total 1,314,574 1,294,708 1,275,327 1,251,218 1,230,740
==================================================================================================================================
Employees (year-end): 6,792 6,631 6,531 6,865 7,261
- ----------------------------------------------------------------------------------------------------------------------------------
II-78
SELECTED FINANCIAL AND OPERATING DATA 1995-1999 (continued)
Alabama Power Company 1999 Annual Report
- ---------------------------------------------------------------------------------------------------------------------------------
1999 1998 1997 1996 1995
- ---------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $ 1,145,646 $1,133,435 $ 997,507 $ 998,806 $ 997,069
Commercial 807,098 779,169 724,148 696,453 670,453
Industrial 843,090 853,550 775,591 759,628 805,596
Other 15,283 14,523 13,563 13,729 13,619
- ---------------------------------------------------------------------------------------------------------------------------------
Total retail 2,811,117 2,780,677 2,510,809 2,468,616 2,486,737
Sales for resale - non-affiliates 415,377 448,973 431,023 391,669 370,140
Sales for resale - affiliates 92,439 103,562 161,795 216,620 127,730
- ---------------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 3,318,933 3,333,212 3,103,627 3,076,905 2,984,607
Other revenues 66,541 53,161 45,484 43,870 40,167
- ---------------------------------------------------------------------------------------------------------------------------------
Total $3,385,474 $3,386,373 $3,149,111 $3,120,775 $3,024,774
=================================================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 15,699,081 15,794,543 14,336,408 14,593,761 14,383,231
Commercial 12,314,085 11,904,509 11,330,312 10,904,476 10,043,220
Industrial 21,942,889 21,585,117 20,727,912 19,999,258 19,862,577
Other 201,149 196,647 180,389 192,573 186,848
- ---------------------------------------------------------------------------------------------------------------------------------
Total retail 50,157,204 49,480,816 46,575,021 45,690,068 44,475,876
Sales for resale - non-affiliates 12,437,599 11,840,910 12,329,480 9,491,237 8,046,189
Sales for resale - affiliates 5,031,781 5,976,099 8,993,326 10,292,066 6,705,174
- ---------------------------------------------------------------------------------------------------------------------------------
Total 67,626,584 67,297,825 67,897,827 65,473,371 59,227,239
=================================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 7.30 7.18 6.96 6.84 6.93
Commercial 6.55 6.55 6.39 6.39 6.68
Industrial 3.84 3.95 3.74 3.80 4.06
Total retail 5.60 5.62 5.39 5.40 5.59
Sales for resale 2.91 3.10 2.78 3.07 3.38
Total sales 4.91 4.95 4.57 4.70 5.04
Residential Average Annual
Kilowatt-Hour Use Per Customer 14,097 14,370 13,254 13,705 13,686
Residential Average Annual
Revenue Per Customer $1,028.76 $1,031.21 $922.21 $937.95 $948.71
Plant Nameplate Capacity
Ratings (year-end) (megawatts) 11,151 11,151 11,151 11,151 10,831
Maximum Peak-Hour Demand (megawatts):
Winter 8,863 7,757 8,478 8,413 7,958
Summer 10,739 10,329 9,778 9,912 10,090
Annual Load Factor (percent) 59.7 62.9 62.7 61.3 59.2
Plant Availability (percent):
Fossil-steam 80.4 85.6 86.3 86.6 88.3
Nuclear 91.0 80.2 88.8 90.5 81.1
- ---------------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 64.1 65.3 65.7 67.0 67.1
Nuclear 17.8 16.3 17.9 18.5 17.1
Hydro 4.7 6.9 7.5 7.1 7.0
Oil and gas 1.1 1.5 0.7 0.4 0.4
Purchased power -
From non-affiliates 4.5 3.3 2.4 2.4 2.7
From affiliates 7.8 6.7 5.8 4.6 5.7
- ---------------------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0 100.0 100.0
=================================================================================================================================
II-79
GEORGIA POWER COMPANY
FINANCIAL SECTION
II-80
MANAGEMENT'S REPORT
Georgia Power Company 1999 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/David M. Ratcliffe
David M. Ratcliffe
President and Chief
Executive Officer
/s/Thomas A. Fanning
Thomas A. Fanning
Executive Vice President,
Treasurer and Chief
Financial Officer
February 16, 2000
II-81
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, 1999 and 1998, and the related statements
of income, common stockholders' equity, and cash flows for each of the three
years in the period ended December 31, 1999. 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 auditing standards generally
accepted in the United States. 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 11-91 through 11-110)
referred to above present fairly, in all material respects, the financial
position of Georgia Power Company as of December 31, 1999 and 1998, and the
results of its operations and its cash flows for each of the three years in the
period ended December 31, 1999, in conformity with accounting principles
generally accepted in the United States.
/s/Arthur Andersen LLP
Atlanta, Georgia
February 16, 2000
II-82
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Georgia Power Company 1999 Annual Report
RESULTS OF OPERATIONS
Earnings
Georgia Power Company's 1999 earnings totaled $541 million, representing a $29
million (5.1 percent) decrease from 1998. This earnings decrease is primarily
due to the recognition of interest income in 1998 as a result of the resolution
of tax issues with the Internal Revenue Service (IRS). Earnings from normal
operations increased due primarily to lower accelerated depreciation under the
1998 Georgia Public Service Commission (GPSC) rate order, sales growth and
decreased financing costs, partially offset by retail rate reductions under the
new order and lower wholesale revenues. Earnings for 1998 totaled $570 million,
representing a $24 million (4.0 percent) decrease from 1997. This earnings
decrease resulted primarily from higher operating expenses, accelerated
depreciation charges pursuant to a previous GPSC retail accounting order ending
December 1998, lower wholesale 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 the effect of the
IRS settlement.
Revenues
The following table summarizes the factors impacting operating revenues for the
1997-1999 period:
Increase (Decrease)
From Prior Year
--------------------------------
1999 1998 1997
--------------------------------
Retail - (in millions)
1998 GPSC rate order $(262) $ - $ -
Revenue subject to refund (79) - -
Sales growth 102 174 62
Weather (53) 101 (74)
Fuel cost recovery and other 44 45 (33)
- --------------------------------------------------------------------
Total retail (248) 320 (45)
- --------------------------------------------------------------------
Sales for resale -
Non-affiliates (49) (23) 1
Affiliates (5) 43 3
- --------------------------------------------------------------------
Total sales for resale (54) 20 4
- --------------------------------------------------------------------
Other operating revenues 21 13 10
- --------------------------------------------------------------------
Total operating revenues $(281) $ 353 $ (31)
====================================================================
Percent change (5.9)% 8.0% (0.7)%
- --------------------------------------------------------------------
Retail revenues of $4.1 billion in 1999 decreased $248 million (5.8 percent)
primarily due to retail rate reductions under the 1998 GPSC rate order. Pursuant
to the order, in 1999 the Company also recorded $79 million of revenue subject
to refund for estimated earnings above 12.5 percent retail return on common
equity. Refunds will be made to customers in 2000. See Note 3 to the financial
statements under "Retail Rate Orders" for additional information. 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.
Fuel revenues generally represent the direct recovery of fuel expense,
including the fuel component of purchased energy, and do not affect net income.
Wholesale revenues from sales to non-affiliated utilities decreased in 1999
and 1998 and were as follows:
1999 1998 1997
-------------------------------
(in millions)
Outside service area -
Long-term contracts $ 55 $ 51 $ 71
Other sales 74 93 79
Inside service area 81 115 132
- ---------------------------------------------------------------
Total $ 210 $ 259 $ 282
===============================================================
Revenues from long-term contracts outside the service area increased
slightly in 1999 due to increased energy sales and decreased in 1998 primarily
due to lower capacity charges and decreased energy sales. See Note 7 to the
financial statements for further information regarding these sales. Revenues
from other sales outside the service area decreased in 1999 and increased in
1998 primarily due to the effect of power marketing activities and were
generally offset by a corresponding decrease and increase, respectively, in
purchased power from non-affiliates. Wholesale revenues from customers within
the service area decreased in 1999 and 1998 primarily due to a decrease in
revenues under a power supply agreement with Oglethorpe Power Corporation (OPC).
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-83
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1999 Annual Report
Other operating revenues increased $21 million (21 percent) primarily due to
increased revenues from equipment rentals. In 1998, other operating revenues
increased $13 million (14.9 percent) primarily due to increased revenues from
the transmission of electricity.
Kilowatt-hour (KWH) sales for 1999 and the percent change by year were as
follows:
Percent Change
----------------------------
1999
KWH 1999 1998 1997
--------- -----------------------------
(in billions)
Residential 19.4 (0.4)% 12.6% (3.0)%
Commercial 23.7 3.7 8.2 1.5
Industrial 27.3 0.1 2.2 1.9
Other 0.6 1.5 1.0 0.4
--------
Total retail 71.0 1.1 6.9 0.4
--------
Sales for resale -
Non-affiliates 5.0 (21.4) (5.2) (13.6)
Affiliates 1.8 (11.9) 19.4 44.6
--------
Total sales for resale 6.8 (19.1) (0.3) (6.0)
--------
Total sales 77.8 (1.0) 6.0 (0.3)
========
- ------------------------------------------------------------------
Residential sales decreased 0.4 percent in 1999 due to moderate summer
temperatures, while commercial sales increased 3.7 percent due to strong
regional economic growth. Industrial sales remained fairly constant. 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.
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:
1999 1998 1997
-------------------------
Total generation
(billions of KWH) 69.3 69.1 66.5
Sources of generation
(percent) --
Coal 75.5 73.3 74.8
Nuclear 21.6 21.6 21.8
Hydro 1.0 2.6 2.7
Oil and gas 1.9 2.5 0.7
Average cost of fuel per net
KWH generated
(cents) -- 1.34 1.36 1.32
- ---------------------------------------------------------------
Fuel expense increased 0.3 percent in 1999 due to a slight increase in
generation, partially offset by a lower average cost of fuel. 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.
Purchased power expense decreased slightly in 1999. Purchased power expense
in 1998 increased $70 million (21.9 percent) over the prior year primarily due
to higher energy demands and power marketing activities. As discussed earlier,
the expense associated with energy purchased for power marketing activities is
generally offset by revenue when resold to non-affiliates.
Other operation and maintenance expenses increased 1.6 percent in 1999
primarily due to increased generating plant maintenance, partially offset by a
reduction in the charges related to the implementation of a customer service
system in 1998, decreased year 2000 readiness costs, and decreased employee
benefit provisions. Other operation and maintenance expenses increased 15.5
percent in 1998 primarily due to expenses related to the customer service system
discussed above, modification of certain information systems for year 2000
compliance discussed below, an increase in outage costs at generating
facilities, and increased line maintenance.
II-84
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1999 Annual Report
Depreciation and amortization decreased $346 million in 1999 primarily due
to higher depreciation charges recognized in 1998 under the prior GPSC
accounting order and the completion in 1998 of the amortization of deferred
Plant Vogtle costs. Depreciation and amortization increased $121 million in 1998
primarily due to accelerated depreciation of generating plant pursuant to the
previous retail accounting order and an increase in plant-in-service. See Note 3
to the financial statements under "Retail Rate Orders" for additional
information.
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 in 1998. See Note 3 to the financial statements under
"Rocky Mountain Status" for additional information.
Interest income decreased in 1999 primarily due to the 1998 recognition of
$73 million in interest income resulting from the resolution of tax issues with
the IRS and the State of Georgia. Other, net decreased in 1999 due primarily to
increased bad debt expense related to consumer energy efficiency improvement
financing.
Financing costs decreased in 1999 and 1998. These changes were primarily due
to the refinancing or retirement of securities. The Company refinanced or
retired $775 million and $754 million of securities in 1999 and 1998,
respectively. Dividends on preferred stock decreased $4 million and $13 million
in 1999 and 1998, respectively. Pursuant to the new three-year retail rate order
which the Company began operating under on January 1, 1999, the Company recorded
$85 million in accelerated amortization of premium on reacquired debt. Other
interest charges decreased $12 million in 1999 primarily due to the recognition
in 1998 of interest related to tax issues. Distributions on preferred securities
of subsidiary companies increased $11 million and $7 million in 1999 and 1998,
respectively, primarily due to the issuance of additional mandatorily redeemable
preferred securities in 1999 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.
On January 1, 1999, the Company began operating under a new three-year
retail rate order. 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 above 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 above the 12.5 percent return will be applied to rate
reductions, with the remaining one-third retained by the Company. Pursuant to
the order, in 1999 the Company recorded $85 million in accelerated amortization
of premium on reacquired debt. The Company also recorded $79 million of revenue
subject to refund for estimated earnings above 12.5 percent. Refunds will be
made to customers in 2000. 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 Orders" for additional information.
II-85
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1999 Annual Report
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 from 1999 is projected to be approximately 2.9 percent
annually on average during 2000 through 2002.
The Company has entered into two purchase power agreements scheduled to
begin after 1999. The first agreement is for five years and will begin in June
2000. The agreement is for approximately 215 megawatts, and capacity payments
are estimated to be between $7 million and $8 million each year. The second
agreement is for seven years and will begin in June 2002. The agreement is for
approximately 310 megawatts during the first three years and approximately 465
megawatts during the remaining four years. Capacity payments are estimated to be
between $16 million and $17 million in each of the first three years and then
between $23 million and $24 million in each of the last four years of the
contract.
The Company is constructing a ten unit, 800 megawatt combustion turbine
peaking power plant that will serve the wholesale market. Units one through
eight will begin operation in 2000; units nine and ten will begin operation in
2001. The Company also plans to construct a 570 megawatt combined cycle unit
that will begin operation in 2002 and will also serve the wholesale market. The
Company has entered into wholesale contracts to sell 560 megawatts of the new
capacity. The Company is also planning to construct two 568 megawatt combined
cycle units at Plant Wansley, to begin operation in 2002. The Company has
applied to the GPSC for certification of these units to serve retail customers.
Savannah Electric (also a wholly-owned subsidiary of Southern Company) will
purchase 200 megawatts of capacity from these units. See Note 4 to the financial
statements under "Construction Program" for additional information.
Compliance costs related to current and future environmental laws,
regulations, and litigation could affect earnings if such costs are not fully
recovered. See "Environmental Issues" for further discussion of these matters.
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. 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.
On December 20, 1999, the Federal Energy Regulatory Commission (FERC) issued
its final rule on Regional Transmission Organizations (RTOs). The order
encourages utilities owning transmission systems to form RTOs on a voluntary
basis. To facilitate the development of RTOs, the FERC will convene regional
conferences for utilities, customers, and other members of the public to discuss
formation of RTOs. In addition to participating in the regional conferences,
utilities owning transmission systems, including the Company, are required to
make a filing by October 15, 2000. The filing must contain either a proposal for
RTO participation or a description of the efforts made to participate in an RTO,
the reasons for non-participation, any obstacles to participation, and any plans
for further work toward participation. The RTOs that are proposed in the filings
should be operational by December 15, 2001. The Company is evaluating the issue
and the outcome cannot now be determined.
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
II-86
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1999 Annual Report
transmission pricing and recovery of costs. The GPSC plans to release a report
on an initial assessment of the range of potential stranded costs in 2000. The
inability 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 Orders" 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.
Year 2000 Challenge
The work undertaken by the Company to prepare critical computer systems and
other date sensitive devices to function correctly in the Year 2000 was
successful. There were no material incidents reported and no disruption of
electric service within the service area. There were no reports of significant
events regarding third parties that impacted revenues or expenses.
For the Company, original projected total costs for Year 2000 readiness,
including the Company's share of costs of Southern Nuclear Operating Company,
were approximately $38 million. These costs include labor necessary to identify,
test, and renovate affected devices and systems, and costs for reporting
requirements to state and federal agencies. From its inception through December
31, 1999, the Year 2000 program costs, recognized as expense, amounted to $41
million. An additional $2 million is projected to be spent in 2000.
Exposure to Market Risks
Due to cost-based rate regulation, the Company currently has limited exposure to
market volatility in interest rates and prices of electricity. See the
discussion above for potential changes in industry structure. 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, 1999, 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, 1999, a near-term 100 basis point change in interest
rates would not materially affect the financial statements.
New Accounting Standard
The FASB has issued Statement No. 133, Accounting for Derivative Instruments and
Hedging Activities, which must be adopted by January 2001. This statement
establishes accounting and reporting standards for derivative instruments -
including certain derivative instruments embedded in other contracts - and for
II-87
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1999 Annual Report
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.
FINANCIAL CONDITION
Plant Additions
In 1999 gross utility plant additions were $790 million. These additions were
primarily related to transmission and distribution facilities, the purchase of
nuclear fuel and the construction of additional combustion turbine and combined
cycle units. The funds needed for gross property additions are currently
provided from operations, short or long-term debt, and from equity from
Southern. The Statements of Cash Flows provide additional details.
Financing Activities
In 1999 the Company continued to lower its financing costs by refinancing
higher-cost issues. New issues during 1997 through 1999 totaled $1.8 billion and
retirement or repayment of securities totaled $2.2 billion.
Special purpose subsidiaries of the Company have issued mandatorily
redeemable preferred securities. See Note 9 to the financial statements under
"Preferred Securities" for additional information.
Composite financing rates for long-term debt, preferred stock and preferred
securities for the years 1997 through 1999, as of year-end, were as follows:
1999 1998 1997
----------------------------------
Composite interest rate
on long-term debt 5.48% 5.64% 6.11%
Composite preferred
stock dividend rate 4.60 5.52 5.18
Composite preferred
securities dividend rate 7.49 7.89 7.89
- ------------------------------------------------------------------
Liquidity and Capital Requirements
Cash provided from operations decreased by $206 million in 1999, primarily due
to lower retail revenues.
The Company estimates that construction expenditures for the years 2000
through 2002 will total $1.2 billion, $1.5 billion and $1.5 billion,
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 are expected to total $168 million during 2000
through 2002.
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 $30 million each year in 2000,
2001 and 2002. 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 equity funds from Southern 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 2000. 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 also consisted of
unsecured debt and trust preferred securities. In this regard, the Company
II-88
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1999 Annual Report
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.
ENVIRONMENTAL ISSUES
Clean Air Act
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 are 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 currently uses
emission allowances and increased fuel switching. Also, equipment to control
nitrogen oxide emissions was installed on additional system fossil-fired units
as necessary to meet Phase II limits and ozone non-attainment requirements for
metropolitan Atlanta through 2000. Compliance for Phase II and initial ozone
non-attainment requirements increased total construction expenditures by $38
million.
The State of Georgia submitted a plan for nitrogen oxide emission reductions
in Atlanta's ozone non-attainment area on October 29, 1999. The Environmental
Protection Agency (EPA) found this plan to be deficient and required the State
to address the shortfalls of the plan. Based on the revised plan approved by the
Georgia Department of Natural Resources on January 26, 2000, the Company
estimates its capital expenditures to comply with the plan to be approximately
$713 million through 2003, of which $705 million remains to be spent. It is
still uncertain at this time what additional controls may be required at the
Company's plants beyond the recently submitted plan.
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.
Environmental Protection Agency Litigation
On November 3, 1999, the EPA brought a civil action in the U.S. District Court
for the Northern District of Georgia. The complaint alleges violations of the
prevention of significant deterioration and new source review provisions of the
Clean Air Act with respect to coal-fired generating facilities at the Company's
Bowen and Scherer plants. The civil action requests penalties and injunctive
relief, including an order requiring the installation of the best available
control technology at the affected units. The EPA concurrently issued a notice
of violation to the Company relating to these two plants. In early 2000, the
EPA filed a motion to amend its complaint to add the violations alleged in its
notice of violation. The complaint and the notice of violation are similar to
those brought against and issued to several other electric utilities. The
complaint and the notice of violation allege that the Company failed to secure
necessary permits or install additional pollution equipment when performing
maintenance and construction at coal burning plants constructed or under
construction prior to 1978. The Company believes that it complied with
applicable laws and the EPA's regulations and interpretations in effect at the
time the work in question took place. The Clean Air Act authorizes civil
penalties of up to $27,500 per day per violation at each generating unit. Prior
to January 30, 1997, the penalty was $25,000 per day. An adverse outcome of this
matter could require substantial capital expenditures that cannot be determined
at this time and possibly require payment of substantial penalties. This could
affect future results of operations, cash flows and possibly financial condition
unless such costs can be recovered through regulated rates.
II-89
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 1999 Annual Report
Other Environmental Issues
In July 1997, the 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 rule to the states for implementation. The final rule affects 22 states
including Georgia. The EPA's July 1997 standards and the September 1998 rule are
being challenged in the courts by several states and industry groups.
Implementation of the final state rules for these three initiatives could
require substantial further reductions in nitrogen oxide and sulfur dioxide
emissions from fossil-fired generating facilities and other industries in these
states. Additional compliance costs and capital expenditures resulting from the
implementation of these rules and standards cannot be determined until the
results of legal challenges are known, and the states have adopted their final
rules.
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 $4 million, $6
million and $4 million in 1999, 1998 and 1997, 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 "Other 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.
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 any new standards will depend on the
development and implementation of applicable regulations.
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 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 1999 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; 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-90
STATEMENTS OF INCOME
For the Years Ended December 31, 1999, 1998, 1997
Georgia Power Company 1999 Annual Report
- ---------------------------------------------------------------------------------------------------------------------------
1999 1998 1997
- ---------------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Revenues:
Retail sales $4,050,088 $4,298,217 $3,978,299
Sales for resale --
Non-affiliates 210,104 259,234 282,365
Affiliates 76,426 81,606 38,708
Other revenues 120,057 99,196 86,345
- ----------------------------------------------------------------------------------------------------------------------------
Total operating revenues 4,456,675 4,738,253 4,385,717
- ----------------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
Fuel 919,876 917,119 857,269
Purchased power --
Non-affiliates 214,573 229,960 143,409
Affiliates 174,989 161,003 177,240
Other 784,359 819,589 702,159
Maintenance 411,983 358,218 317,199
Depreciation and amortization 467,966 813,802 693,217
Taxes other than income taxes 202,853 204,623 207,192
Write down of Rocky Mountain plant - 33,536 -
- ----------------------------------------------------------------------------------------------------------------------------
Total operating expenses 3,176,599 3,537,850 3,097,685
- ----------------------------------------------------------------------------------------------------------------------------
Operating Income 1,280,076 1,200,403 1,288,032
Other Income (Expense):
Interest income 5,583 79,578 10,581
Equity in earnings of unconsolidated subsidiaries 2,721 3,735 4,266
Other, net (47,986) (38,277) (29,822)
- ----------------------------------------------------------------------------------------------------------------------------
Earnings Before Interest and Income Taxes 1,240,394 1,245,439 1,273,057
- ----------------------------------------------------------------------------------------------------------------------------
Interest Charges and Other:
Interest on long-term debt 162,303 180,746 194,344
Interest on notes payable 19,787 12,213 7,795
Amortization of debt discount, premium and expense, net (Note 3) 100,115 13,366 14,179
Other interest charges, net (2,336) 9,988 1,292
Distributions on preferred securities of subsidiary 65,774 54,327 47,369
- ----------------------------------------------------------------------------------------------------------------------------
Total interest charges and other, net 345,643 270,640 264,979
- ----------------------------------------------------------------------------------------------------------------------------
Earnings Before Income Taxes 894,751 974,799 1,008,078
Income taxes 351,639 398,632 395,155
- ----------------------------------------------------------------------------------------------------------------------------
Net Income 543,112 576,167 612,923
Dividends on Preferred Stock 1,729 5,939 18,927
- ----------------------------------------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred Stock $ 541,383 $ 570,228 $ 593,996
============================================================================================================================
The accompanying notes are an integral part of these statements.
II-91
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1999, 1998, and 1997
Georgia Power Company 1999 Annual Report
- --------------------------------------------------------------------------------------------------------------------------
1999 1998 1997
(in thousands)
Operating Activities:
Net income $ 543,112 $ 576,167 $ 612,923
Adjustments to reconcile net income to net
cash provided from operating activities --
Depreciation and amortization 578,878 867,637 674,286
Deferred income taxes and investment tax credits, net (34,930) (93,005) (21,425)
Allowance for equity funds used during construction (734) (3,235) (6,012)
Amortization of deferred Plant Vogtle costs - 50,412 120,577
Other, net 43,555 (6,781) 1,991
Changes in certain current assets and liabilities --
Receivables, net 21,665 (25,453) 13,387
Inventories (32,582) (11,156) 39,748
Payables 13,095 47,862 (10,007)
Taxes accrued (2,832) 22,139 (3,596)
Energy cost recovery, retail (26,862) (7,649) (20,103)
Other 93,620 (15,142) (30,026)
- ----------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities 1,195,985 1,401,796 1,371,743
- ----------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (790,464) (499,053) (475,921)
Other (27,454) 67,031 16,223
- ----------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities (817,918) (432,022) (459,698)
- ----------------------------------------------------------------------------------------------------------------------------
Financing Activities:
Increase (decrease) in notes payable, net 295,389 (25,378) (64,266)
Proceeds --
Senior notes 100,000 495,000 -
Pollution control bonds 238,000 89,990 284,700
Preferred securities 200,000 - 364,250
Capital contributions from parent company 155,777 235 85
Retirements --
First mortgage bonds (404,000) (558,250) (60,258)
Pollution control bonds (235,000) (89,990) (284,700)
Preferred securities (100,000) - -
Preferred stock (36,231) (106,064) (356,392)
Capital distributions to parent company - (270,000) (205,000)
Special deposits -- redemption funds - - 44,454
Payment of preferred stock dividends (984) (9,137) (26,917)
Payment of common stock dividends (543,000) (536,600) (520,000)
Other (29,630) (26,641) (20,024)
- ----------------------------------------------------------------------------------------------------------------------------
Net cash used for financing activities (359,679) (1,036,835) (844,068)
- ----------------------------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents 18,388 (67,061) 67,977
- ----------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at Beginning of Year 16,272 83,333 15,356
- ----------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $34,660 $16,272 $83,333
- ----------------------------------------------------------------------------------------------------------------------------
Supplemental Cash Flow Information:
Cash paid during the year for --
Interest (net of amount capitalized) $ 247,050 $ 269,524 $ 258,298
Income taxes (net of refunds) 394,457 480,318 427,596
- --------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
II-92
BALANCE SHEETS
At December 31, 1999 and 1998
Georgia Power Company 1999 Annual Report
- --------------------------------------------------------------------------------------------------------------------------
Assets 1999 1999
- --------------------------------------------------------------------------------------------------------------------------
(in thousands)
Current Assets:
Cash and cash equivalents $ 34,660 $ 16,272
Receivables --
Customer accounts receivable 438,161 439,420
Other accounts and notes receivable 102,544 99,574
Affiliated companies 16,006 16,817
ccumulated provision for uncollectible accounts (7,000) (5,500)
Fossil fuel stock, at average cost 126,298 104,133
Materials and supplies, at average cost 253,894 243,477
Other 63,990 73,280
- -------------------------------------------------------------------------------------------------------------------------
Total current assets 1,028,553 987,473
- -------------------------------------------------------------------------------------------------------------------------
Property, Plant, and Equipment:
In service 15,798,624 15,441,146
Less accumulated provision for depreciation 6,538,574 6,109,331
- -------------------------------------------------------------------------------------------------------------------------
9,260,050 9,331,815
Nuclear fuel, at amortized cost 119,288 121,169
Construction work in progress (Note 4) 425,975 189,849
- -------------------------------------------------------------------------------------------------------------------------
Total property, plant, and equipment 9,805,313 9,642,833
- -------------------------------------------------------------------------------------------------------------------------
Other Property and Investments:
Equity investments in unconsolidated subsidiaries (Note 4) 25,024 24,360
Nuclear decommissioning trusts 371,914 284,536
Other 33,766 34,781
- -------------------------------------------------------------------------------------------------------------------------
Total other property and investments 430,704 343,677
- -------------------------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets:
Deferred charges related to income taxes (Note 8) 590,893 604,488
Prepaid pension costs 145,801 103,606
Debt expense, being amortized 55,824 51,261
Premium on reacquired debt, being amortized 99,331 173,858
Other 120,441 126,422
- -------------------------------------------------------------------------------------------------------------------------
Total deferred charges and other assets 1,012,290 1,059,635
- -------------------------------------------------------------------------------------------------------------------------
Total Assets $12,276,860 $12,033,618
=========================================================================================================================
The accompanying notes are an integral part of these balance sheets.
II-93
BALANCE SHEETS
At December 31, 1999 and 1998
Georgia Power Company 1999 Annual Report
- ---------------------------------------------------------------------------------------------------------------------------------
Liabilities and Stockholder's Equity 1999 1998
- ---------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Current Liabilities:
Securities due within one year (Note 9) $ 155,772 $ 435,085
Notes payable 636,241 340,852
Accounts payable --
Affiliated 76,591 75,774
Other 346,785 326,317
Customer deposits 74,695 69,584
Taxes accrued --
Income taxes 7,914 15,801
Other 127,414 122,359
Interest accrued 58,665 60,187
Vacation pay accrued 38,143 34,443
Other 153,767 66,350
- ---------------------------------------------------------------------------------------------------------------------------------
Total current liabilities 1,675,987 1,546,752
- ---------------------------------------------------------------------------------------------------------------------------------
Long-Term Debt (See accompanying statements) 2,688,358 2,744,362
- ---------------------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes (Note 8) 2,202,565 2,249,613
Deferred credits related to income taxes (Note 8) 267,083 284,017
Accumulated deferred investment tax credits (Note 8) 367,114 381,914
Employee benefits provisions 181,529 177,148
Other 151,812 160,863
- ---------------------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 3,170,103 3,253,555
- ---------------------------------------------------------------------------------------------------------------------------------
Company Obligated Mandatorily Redeemable Preferred
Securities Of Subsidiary Trusts Holding Company Junior
Subordinated Notes (See accompanying statements) 789,250 689,250
- ---------------------------------------------------------------------------------------------------------------------------------
Cumulative Preferred Stock (See accompanying statements) 14,952 15,527
- ---------------------------------------------------------------------------------------------------------------------------------
Common Stockholder's Equity (See accompanying statements) 3,938,210 3,784,172
- ---------------------------------------------------------------------------------------------------------------------------------
Total Liabilities and Stockholder's Equity $12,276,860 $12,033,618
=================================================================================================================================
The accompanying notes are an integral part of these balance sheets.
II-94
STATEMENTS OF CAPITALIZATION
At December 31, 1999 and 1998
Georgia Power Company 1999 Annual Report
- ------------------------------------------------------------------------------------------------------------------------------------
1999 1998 1999 1998
- ------------------------------------------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
Long-Term Debt:
First mortgage bonds --
Maturity Interest Rates
--------- ---------------
September 1, 1999 6.125% $ - $ 195,000
March 1, 2000 6.00% 100,000 100,000
April 1, 2003 6.625% 200,000 200,000
August 1, 2003 6.35% 75,000 75,000
2005 6.07% 10,000 10,000
2008 6.875% 50,000 50,000
2023 through 2025 7.55% to 7.95% 57,000 266,000
- ----------------------------------------------------------------------------------------------------------
Total first mortgage bonds 492,000 896,000
- ----------------------------------------------------------------------------------------------------------
Pollution control bonds -- (Note 9)
Maturity Interest Rates
-------- --------------
2000 4.375% 50,000 50,000
2005 5.00% 57,000 57,000
2011 Variable (3.95% at 1/1/00) 10,450 10,450
2018-2019 6.00% to 6.35% 13,100 63,100
2020-2024 5.75% to 6.25% 192,270 377,270
2022-2024 Variable (3.70% to 5.05% at 1/1/00) 352,490 352,490
2025 6.00% to 6.10% 145,115 145,115
2025-2029 Variable (3.70% to 5.05% at 1/1/00) 475,765 475,765
2030-2034 Variable (3.70% to 5.05% at 1/1/00) 140,000 140,000
2034 5.25% to 5.45% 238,000 -
- ----------------------------------------------------------------------------------------------------------
Total pollution control bonds 1,674,190 1,671,190
- ----------------------------------------------------------------------------------------------------------
Senior notes -- (Note 9)
Maturity Interest Rates
-------- --------------
December 1, 2005 5.50% 150,000 150,000
December 31, 2038 6.60% 200,000 200,000
March 31, 2039 6.625% 100,000 -
December 31, 2047 6.875% 145,000 145,000
- ----------------------------------------------------------------------------------------------------------
Total senior notes 595,000 495,000
- ----------------------------------------------------------------------------------------------------------
Other long-term debt (Note 9) 85,851 86,280
- ----------------------------------------------------------------------------------------------------------
Unamortized debt discount, net (2,911) (4,679)
- ----------------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
requirement -- $156,062,000) 2,844,130 3,143,791
Less amount due within one year (Note 9) 155,772 399,429
- ------------------------------------------------------------------------------------------------------------------------------------
Total long-term debt excluding amount due within one year $2,688,358 $2,744,362 36.2 % 38.0 %
- ------------------------------------------------------------------------------------------------------------------------------------
II-95
STATEMENTS OF CAPITALIZATION (continued)
At December 31, 1999 and 1998
Georgia Power Company 1999 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------------
1999 1998 1999 1998
- -----------------------------------------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
Company Obligated Mandatorily
Redeemable Preferred Securities (Note 9):
$25 liquidation value -- 9.00% $ - $ 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
$25 liquidation value -- 6.85% 200,000 -
- -----------------------------------------------------------------------------------------------------------------------------------
Total (annual distribution requirement -- $59,104,000) 789,250 689,250 10.6 9.5
- -----------------------------------------------------------------------------------------------------------------------------------
Cumulative Preferred Stock, without par value:
Authorized -- 55,000,000 shares
Outstanding -- 149,520 shares at December 31, 1999
Outstanding -- 511,834 shares at December 31, 1998
$100 stated value --
4.60% to 6.60% 14,952 51,183
- ----------------------------------------------------------------------------------------------------------------------------------
Total cumulative preferred stock (annual dividend
requirement -- $688,000) 14,952 51,183
Less amount due within one year (Note 9) - 35,656
- -----------------------------------------------------------------------------------------------------------------------------------
Cumulative preferred stock excluding amount due within one year 14,952 15,527 0.2 0.2
- -----------------------------------------------------------------------------------------------------------------------------------
Common Stockholder's Equity:
Common stock, without par value --
Authorized -- 15,000,000 shares
Outstanding -- 7,761,500 shares 344,250 344,250
Paid-in capital 1,815,983 1,660,206
Premium on preferred stock 40 158
Retained earnings (Note 9) 1,777,937 1,779,558
- -----------------------------------------------------------------------------------------------------------------------------------
Total common stockholder's equity (See accompanying statement) 3,938,210 3,784,172 53.0 52.3
- -----------------------------------------------------------------------------------------------------------------------------------
Total Capitalization $ 7,430,770 $ 7,233,311 100.0 % 100.0 %
- -----------------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
II-96
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
For the Years Ended December 31, 1999, 1998, 1997
Georgia Power Company 1999 Annual Report
- ------------------------------------------------------------------------------------------------------------------------------
Premium on
Common Paid-In Preferred Retained
Stock Capital Stock Earnings Total
- ------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Balance at January 1, 1997 $344,250 $2,134,886 $ 371 $1,674,774 $4,154,281
Net income after dividends on preferred stock - - - 593,996 593,996
Capital distributions to parent company - (205,000) - - (205,000)
Capital contributions from parent company - 85 - - 85
Cash dividends on common stock - - - (520,000) (520,000)
Preferred stock transactions, net - - (211) (3,423) (3,634)
- ------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1997 344,250 1,929,971 160 1,745,347 4,019,728
Net income after dividends on preferred stock - - - 570,228 570,228
Capital distributions to parent company - (270,000) - - (270,000)
Capital contributions from parent company - 235 - - 235
Cash dividends on common stock - - - (536,600) (536,600)
Preferred stock transactions, net - - (2) 583 581
- ------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1998 344,250 1,660,206 158 1,779,558 3,784,172
Net income after dividends on preferred stock - - - 541,383 541,383
Capital contributions from parent company - 155,777 - - 155,777
Cash dividends on common stock - - - (543,000) (543,000)
Preferred stock transactions, net - - (118) (4) (122)
- ------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1999 $344,250 $1,815,983 $ 40 $1,777,937 $3,938,210
==============================================================================================================================
The accompanying notes are an integral part of these statements.
II-97
NOTES TO FINANCIAL STATEMENTS
Georgia Power Company 1999 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 integrated Southeast utilities, 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 integrated Southeast utilities (Alabama Power
Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company,
and Savannah Electric and Power Company) provide electric service in four
states. Contracts among the integrated Southeast utilities - related to 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 Company Energy Solutions develops new business opportunities related to
energy products and services. Southern Nuclear provides services to Southern
Company's nuclear power plants. Southern Energy acquires, develops, builds,
owns, and operates power production and delivery facilities and provides a broad
range of energy-related services to utilities and industrial companies in
selected countries around the world. Southern Energy's businesses include
independent power projects, integrated utilities, a distribution company, and
energy trading and marketing businesses outside the Southeastern United States.
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.
Certain prior years' data presented in the financial statements have been
reclassified to conform with current year presentation.
Related-Party Transactions
The Company has an agreement with SCS under which the following services are
rendered to the Company at cost: general and design engineering, purchasing,
accounting and statistical, finance and treasury, tax, information resources,
marketing, auditing, insurance and pension, human resources, systems and
procedures, and other services with respect to business and operations and power
pool operations. Costs for these services amounted to $253 million, $251
million, and $218 million during 1999, 1998, and 1997, respectively.
The Company has an agreement with Southern Nuclear under which the following
nuclear-related services are rendered to the Company at cost: general executive
and advisory services; general operations, management and technical services;
administrative services including procurement, accounting and statistical,
employee relations, and systems and procedures services; strategic planning and
budgeting services; and other services with respect to business and operations.
Costs for these services amounted to $270 million, $269 million, and $220
million during 1999, 1998, and 1997, respectively.
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 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. Pursuant to the terms of the GPSC's
1998 rate order, the Company recorded $85 million in 1999 of additional
amortization of premium on reacquired debt. See Note 3 under "Retail Rate
Orders" for additional information. Regulatory assets and (liabilities)
reflected in the Company's Balance Sheets at December 31 relate to the
following:
II-98
NOTES (continued)
Georgia Power Company 1999 Annual Report
1999 1998
-----------------------
(in millions)
Deferred income taxes $ 591 $ 604
Deferred income tax credits (267) (284)
Premium on reacquired debt 99 174
Corporate building lease 54 53
Vacation pay 47 44
Postretirement benefits 33 36
Department of Energy assessments 24 26
Deferred nuclear outage costs 26 24
Other, net 3 12
- ---------------------------------------------------------------
Total $ 610 $ 689
===============================================================
In the event that a portion of the Company's operations is no longer subject
to the provisions of Statement No. 71, the Company would be required to write
off related regulatory assets and liabilities 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 located
within the state of Georgia, and to wholesale customers in the Southeast.
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. 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 1999, $74 million in 1998, and $76 million in 1997. 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 and potentially additional spent
fuel pool rack capacity at Plant Hatch during 2000 are in progress. In addition,
through Southern Nuclear, Georgia Power is a member of Private Fuel Storage,
LLC, a joint utility effort to develop a private spent fuel storage facility for
temporary storage of spent nuclear fuel. This facility is planned to begin
operation as early as the year 2003.
Also, the Energy Policy Act of 1992 required the establishment 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,
1999, to be approximately $21.4 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
3.3 percent in 1999, 3.2 percent in 1998, and 3.1 percent in 1997. In addition,
the Company recorded accelerated depreciation of electric plant of $314 million
in 1998 and $159 million in 1997. The Company did not record any accelerated
depreciation in 1999. These charges are recorded in the accumulated provision
for depreciation. See Note 3 under "Retail Rate Orders" 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.
II-99
NOTES (continued)
Georgia Power Company 1999 Annual Report
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.
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 percent 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 1999 and fund
balance as of December 31, 1999 were:
Plant Plant
Hatch Vogtle
- ---------------------------------------------------------------
(in millions)
Amount expensed in 1999 $ 17 $ 9
===============================================================
(in millions)
Accumulated provisions:
External trust funds, at fair value $222 $149
Internal reserves 22 12
- ---------------------------------------------------------------
Total $244 $161
===============================================================
Effective January 1, 1999, the GPSC increased the annual provision for
decommissioning expenses to $26 million from $20 million in 1998 and 1997. 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 percent and an estimated trust earnings rate of 6.5 percent. 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.
II-100
NOTES (continued)
Georgia Power Company 1999 Annual Report
Allowance for Funds Used During Construction (AFUDC)
AFUDC represents the estimated debt and equity costs of capital funds that are
necessary to finance the construction of new facilities. While cash is not
realized currently from such allowance, it increases the revenue requirement
over the service life of the plant through a higher rate base and higher
depreciation expense. For the years 1999, 1998 and 1997, the average AFUDC rates
were 5.61 percent, 6.71 percent and 7.60 percent, respectively. AFUDC, net of
taxes, as a percentage of net income after dividends on preferred stock, was
less than 2.0 percent for 1999, 1998, and 1997.
Property, Plant, and Equipment
Property, plant, and equipment is stated at original cost, less regulatory
disallowances and impairments. 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
capitalized.
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, 1999 $2,758 $2,604
At December 31, 1998 3,058 3,105
Preferred securities:
At December 31, 1999 789 680
At December 31, 1998 689 716
- --------------------------------------------------------------
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 postretirement
trusts to the extent required by the GPSC and FERC. The measurement date for
plan assets and obligations is September 30 of each year.
The weighted average rates assumed in the actuarial calculations for both
the pension and postretirement benefit plans were:
1999 1998
- -----------------------------------------------------------------
Discount 7.50% 6.75%
Annual salary increase 5.00 4.25
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
---------------------------
1999 1998
- ----------------------------------------------------------------
(in millions)
Balance at beginning of year $1,217 $1,119
Service cost 33 30
Interest cost 80 82
Benefits paid (57) (55)
Actuarial (gain) loss and
employee transfers (68) 41
- ----------------------------------------------------------------
Balance at end of year $1,205 $1,217
================================================================
II-101
NOTES (continued)
Georgia Power Company 1999 Annual Report
Plan Assets
---------------------------
1999 1998
- ----------------------------------------------------------------
(in millions)
Balance at beginning of year $1,859 $1,931
Actual return on plan assets 313 11
Benefits paid (57) (55)
Employee transfers (8) (28)
- ----------------------------------------------------------------
Balance at end of year $2,107 $1,859
================================================================
The accrued pension costs recognized in the Balance Sheets
were as follows:
1999 1998
- ---------------------------------------------------------------
(in millions)
Funded status $ 902 $ 642
Unrecognized transition obligation (30) (35)
Unrecognized prior service cost 41 45
Unrecognized net actuarial gain (767) (548)
- ---------------------------------------------------------------
Prepaid asset recognized in the
Balance Sheets $ 146 $ 104
===============================================================
Components of the plans' net periodic cost were as follows:
1999 1998 1997
- ---------------------------------------------------------------
(in millions)
Service cost $ 33 $ 30 $ 30
Interest cost 80 82 82
Expected return on plan assets (137) (127) (121)
Recognized net actuarial gain (17) (20) (18)
Net amortization (1) (1) (1)
- ---------------------------------------------------------------
Net pension income $ (42) $ (36) $ (28)
===============================================================
Postretirement Benefits
Changes during the year in the accumulated benefit obligations and in the fair
value of plan assets were as follows:
Accumulated
Benefit Obligations
---------------------------
1999 1998
- ----------------------------------------------------------------
(in millions)
Balance at beginning of year $464 $435
Service cost 8 7
Interest cost 30 32
Benefits paid (19) (16)
Actuarial loss and employee
transfers (45) 6
- ----------------------------------------------------------------
Balance at end of year $438 $464
=================================================================
Plan Assets
---------------------------
1999 1998
- ----------------------------------------------------------------
(in millions)
Balance at beginning of year $150 $122
Actual return on plan assets 11 4
Employer contributions 35 40
Benefits paid (19) (16)
- ----------------------------------------------------------------
Balance at end of year $177 $150
================================================================
The accrued postretirement costs recognized in the Balance Sheets were
as follows:
1999 1998
- ---------------------------------------------------------------
(in millions)
Funded status $(261) $(314)
Unrecognized transition obligation 122 131
Unrecognized net actuarial loss 10 57
Fourth quarter contributions 14 19
- ---------------------------------------------------------------
Accrued liability recognized in the
Balance Sheets $(115) $(107)
===============================================================
Components of the plans' net periodic cost were as follows:
1999 1998 1997
- ---------------------------------------------------------------
(in millions)
Service cost $ 8 $ 7 $ 7
Interest cost 30 32 32
Expected return on plan assets (10) (9) (7)
Recognized net actuarial loss 1 1 1
Net amortization 9 9 9
- ---------------------------------------------------------------
Net postretirement cost $ 38 $40 $42
===============================================================
An additional assumption used in measuring the accumulated postretirement
benefit obligations was a weighted average medical care cost trend rate of 7.74
percent for 1999, decreasing gradually to 5.50 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,
1999 as follows:
1 Percent 1 Percent
Increase Decrease
- ---------------------------------------------------------------
(in millions)
Benefit obligation $ 36 $ (30)
Service and interest costs 3 (3)
===============================================================
II-102
NOTES (continued)
Georgia Power Company 1999 Annual Report
3. CONTINGENCIES & REGULATORY MATTERS
Retail Rate Orders
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 were decreased by $262 million on an annual basis effective January
1, 1999, and by an additional $24 million effective January 1, 2000. The order
further provides for $85 million in each year, plus up to $50 million of any
earnings above 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 above the 12.5 percent return will be applied to rate
reductions, with the remaining one-third retained by the Company. Pursuant to
the order, in 1999 the Company recorded $85 million in accelerated amortization
of premium on reacquired debt. The Company also recorded $79 million of revenue
subject to refund for estimated earnings above 12.5 percent retail return on
common equity. Refunds will be made to customers in 2000. This refund is
presented in the financial statements under other current liabilities on the
Balance Sheet. The Company will not file for a general base rate increase unless
its projected retail return on common equity falls below 10 percent, and is
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 above 12.5 percent were used to
accelerate the amortization of regulatory assets or depreciation of electric
plant. Additionally, the Company was required to record $14 million annually of
accelerated depreciation of electric plant. During 1998 and 1997, for earnings
above the 12.5 percent retail return, the Company recorded charges of $292
million and $135 million, respectively. These charges are presented in the
financial statements as depreciation expense of electric plant and as an
addition to the accumulated provision for depreciation.
Environmental Protection Agency (EPA) Litigation
On November 3, 1999, the EPA brought a civil action in the U.S. District Court
for the Northern District of Georgia. The complaint alleges violations of the
prevention of significant deterioration and new source review provisions of the
Clean Air Act with respect to coal-fired generating facilities at the Company's
Bowen and Scherer plants. The civil action requests penalties and injunctive
relief, including an order requiring the installation of the best available
control technology at the affected units beginning at the point of the alleged
violations. The Clean Air Act authorizes civil penalties of up to $27,500 per
day, per violation at each generating unit. Prior to January 30, 1997, the
penalty was $25,000 per day.
The EPA concurrently issued a notice of violation to the Company relating to
these two plants. In early 2000, the EPA filed a motion to amend its complaint
to add the violations alleged in its notice of violation. The complaint and the
notice of violation are similar to those brought against and issued to several
other electric utilities. The complaint and the notice of violation allege that
the Company failed to secure necessary permits or install additional pollution
equipment when performing maintenance and construction at coal burning plants
constructed or under construction prior to 1978. The Company believes that it
complied with applicable laws and the EPA's regulations and interpretations in
effect at the time the work in question took place
An adverse outcome of this matter could require substantial capital
expenditures that cannot be determined at this time and possibly require payment
of substantial penalties. This could affect future results of operations, cash
flows and possibly financial condition unless such costs can be recovered
through regulated rates.
Other Environmental Contingencies
The State of Georgia submitted a plan for nitrogen oxide emission reductions in
Atlanta's ozone non-attainment area on October 29, 1999. The EPA found this plan
to be deficient and required the State to address the shortfalls of the plan.
Based on the revised plan approved by the Georgia Department of Natural
Resources on January 26, 2000, the Company estimates its capital costs to comply
with the plan to be approximately $713 million through 2003, of which $705
million remains to be spent. It is still uncertain at this time what additional
controls may be required at the Company's plants beyond the recently submitted
plan.
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
II-103
NOTES (continued)
Georgia Power Company 1999 Annual Report
with respect to a site in Brunswick, Georgia. As of December 31, 1999, 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 31 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 ten electrical substations on the list at a cumulative cost of
approximately $3 million through December 31, 1999. The State has removed from
the list two power generation facilities following the assessment which
indicated no remediation was necessary. In addition, the Company has recognized
approximately $26 million in cumulative expenses through December 31, 1999 for
the assessment of the remaining sites on the list and the anticipated clean-up
cost for 12 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 determines whether remediation is
required. If all listed sites were required to be remediated, the Company could
incur expenses of up to approximately $6 million in additional clean-up costs
and construction expenditures of up to approximately $37 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.
Rocky Mountain Status
In June 1996, the GPSC initiated a review of the Rocky Mountain 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. Under the rate order approved by the GPSC on December 18,
1998, the Company accepted the rate base allowance and, in December 1998,
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.
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.
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 is
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.
In January 1997, the GPSC approved a performance award of approximately
$11.7 million for performance during the 1993-1995 period. This award was
collected through the retail fuel cost recovery provision and recognized in
income over the 36-month period ending in December 1999. In February 2000, the
GPSC approved a performance award of approximately $7.8 million for performance
during the 1996-1998 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 2000.
II-104
NOTES (continued)
Georgia Power Company 1999 Annual Report
4. COMMITMENTS
Construction Program
The Company is constructing a ten unit, 800 megawatt combustion turbine peaking
power plant. Units one through eight will begin operation in 2000; units nine
and ten will begin operation in 2001. The Company also plans to construct a 570
megawatt combined cycle unit that will begin operation in 2002, and an addition
of two 568 megawatt combined cycle units at Plant Wansley, to begin operation in
2002. 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
$1.2 billion in 2000, $1.5 billion in 2001, and $1.5 billion in 2002.
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,
1999 were as follows:
Minimum
Year Obligations
- ---- ------------
(in millions)
2000 $ 659
2001 475
2002 381
2003 328
2004 300
2005 and beyond 787
- ----------------------------------------------------------------
Total minimum obligations $2,930
================================================================
Additional commitments for coal and for nuclear fuel will be required in the
future to supply the Company's fuel needs.
Purchased Power Commitments
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
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:
1999 1998 1997
---------------------------------
(in millions)
Energy $51 $45 $45
Capacity 29 30 30
- --------------------------------------------------------------
Total $80 $75 $75
==============================================================
Kilowatt-hours 3,338 3,146 3,038
- --------------------------------------------------------------
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 $57 million, $56 million, and
$54 million in 1999, 1998, and 1997, respectively. The current projected Plant
Vogtle capacity payments are:
Year Capacity Payments
- ---- ----------------------
(in millions)
2000 $ 60
2001 59
2002 58
2003 58
2004 55
2005 and beyond 594
- ----------------------------------------------------------------
Total capacity payments $ 884
================================================================
II-105
NOTES (continued)
Georgia Power Company 1999 Annual Report
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 has entered into other various long-term commitments for the
purchase of electricity. Estimated total long-term obligations at December 31,
1999 were as follows:
Year Other Obligations
- --- ----------------------
(in millions)
2000 $ 21
2001 22
2002 39
2003 41
2004 40
2005 and beyond 412
- ----------------------------------------------------------------
Total other obligations $ 575
================================================================
Operating Leases
The Company has entered into coal rail car rental agreements with various terms
and expiration dates. These expenses totaled $11 million for 1999, $13 million
for 1998, and $11 million for 1997. At December 31, 1999, estimated minimum
rental commitments for these noncancelable operating leases were as follows:
Year Minimum Obligations
- ---- --------------------------
(in millions)
2000 $ 12
2001 13
2002 13
2003 13
2004 13
2005 and beyond 115
- -----------------------------------------------------------------
Total minimum obligations $ 179
=================================================================
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 $9.5 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 12 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 should 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.
II-106
NOTES (continued)
Georgia Power Company 1999 Annual Report
6. JOINT OWNERSHIP AGREEMENTS
Except as otherwise noted, the Company has contracted to operate and maintain
all jointly owned generating facilities. The Company includes its proportionate
share of plant operating expenses in the corresponding operating expenses in the
Statements of Income.
The Company jointly owns the Rocky Mountain pumped storage hydroelectric
plant with OPC who is the operator of the plant. The Company also jointly owns
Plant McIntosh with Savannah Electric and Power Company who operates the plant.
The Company and Florida Power Corporation (FPC) jointly own a combustion turbine
unit operated by FPC.
At December 31, 1999, 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% $3,297* $1,630
Plant Hatch (nuclear) 50.1 857 604
Plant Wansley (coal) 53.5 299 145
Plant Scherer (coal)
Units 1 and 2 8.4 112 51
Unit 3 75.0 544 193
Plant McIntosh
Common Facilities 75.0 19 1
(combustion-turbine)
Rocky Mountain 25.4 169* 66
(pumped storage)
Intercession City 33.3 11 **
(combustion-turbine)
- --------------------------------------------------------------------
* Investment net of write-offs.
** Less than $1 million.
7. LONG-TERM POWER SALES AGREEMENTS
The Company and the other integrated Southeast utilities 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)
1999 $ 32 162
1998 32 162
1997 42 159
-------------------------------------
Unit power from specific generating plants is being sold to Florida Power &
Light Company (FP&L), FPC, Jacksonville Electric Authority (JEA), and the City
of Tallahassee, Florida. Under these agreements, the Company sold approximately
162 megawatts of capacity in 1999 and is scheduled to sell approximately 124
megawatts of capacity in 2000. After 2000, capacity sales will decline to
approximately 101 megawatts -- unless reduced by FP&L, FPC, and JEA -- until the
expiration of the contracts in 2010.
8. INCOME TAXES
At December 31, 1999, tax-related regulatory assets were $591 million and
tax-related regulatory liabilities were $267 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:
1999 1998 1997
-------------------------------
Total provision for income taxes: (in millions)
Federal:
Currently payable $ 333 $415 $352
Deferred -
Current year 114 131 49
Reversal of prior years (148) (218) (68)
Deferred investment tax
credits - 7 -
- -----------------------------------------------------------------
299 335 333
- -----------------------------------------------------------------
State:
Currently payable 54 77 65
Deferred -
Current year 5 18 8
Reversal of prior years (11) (31) (11)
Deferred investment tax
credits 5 - -
- -----------------------------------------------------------------
53 64 62
- -----------------------------------------------------------------
Total 352 399 395
=================================================================
II-107
NOTES (continued)
Georgia Power Company 1999 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:
1999 1998
-------------------
(in millions)
Deferred tax liabilities:
Accelerated depreciation $1,766 $1,670
Property basis differences 729 854
Other 155 158
- -----------------------------------------------------------------
Total 2,650 2,682
- -----------------------------------------------------------------
Deferred tax assets:
Other property basis differences 200 211
Federal effect of state deferred taxes 93 95
Other deferred costs 109 96
Disallowed Plant Vogtle buybacks 22 23
Other 26 21
- -----------------------------------------------------------------
Total 450 446
- -----------------------------------------------------------------
Net deferred tax liabilities 2,200 2,236
Portion included in current assets 3 13
- -----------------------------------------------------------------
Accumulated deferred income taxes
in the Balance Sheets $2,203 $2,249
=================================================================
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 $20 million in 1999, $22 million in 1998, and $15 million in 1997.
At December 31, 1999, 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:
1999 1998 1997
--------------------------
Federal statutory rate 35% 35% 35%
State income tax, net of
federal deduction 4 4 4
Non-deductible book
depreciation 2 6 4
Other (2) (4) (4)
- ---------------------------------------------------------------
Effective income tax rate 39% 41% 39%
===============================================================
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.
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,
1999, $881 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
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
Trust IV 2/1999 200.00 6.85 206 3/2029
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.
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.
II-108
NOTES (continued)
Georgia Power Company 1999 Annual Report
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 $457.5 million of its
first mortgage bonds outstanding at December 31, 1999, 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
The Company incurred debt in connection with the issuance of 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 2000, the Company had unused credit arrangements with banks
totaling $1.3 billion, of which $752 million expires at various times during
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 20, 2000, 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.
Approximately $162 million of the $752 million arrangements expiring during
2000 allow for two-year term loans executable upon expiration date of the
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.
These unused credit arrangements provide liquidity support to the Company's
variable rate pollution control bonds. The amount of variable rate pollution
control bonds outstanding requiring that liquidity support as of December 31,
1999, was $250 million.
In addition, the Company borrows under uncommitted lines of credit with
banks and through a $500 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 1999.
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, 1999 and 1998, 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, 1999 and 1998, the interest and lease amortization deferred on
the Balance Sheets are $54 million and $53 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.
II-109
NOTES (continued)
Georgia Power Company 1999 Annual Report
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:
1999 1998
------------------
(in millions)
Bond improvement fund requirements $ 5 $ 9
Capital lease - current portion 1 -
First mortgage bond maturities
and redemptions 100 390
Pollution control bond maturities
and redemptions 50 -
- ---------------------------------------------------------------
Total long-term debt 156 399
Preferred stock - 36
- ---------------------------------------------------------------
Total $156 $435
===============================================================
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.
Redemption of Securities
The Company plans to continue, to the extent possible, 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. 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 1999 and 1998 is as follows:
Net Income
After
Dividends on
Operating Operating Preferred
Quarter Ended Revenues Income Stock
- ---------------------------------------------------------------------
(in millions)
--------------------------------------------
March 1999 $ 931 $224 $ 92
June 1999 1,092 299 138
September 1999 1,466 557 296
December 1999 968 200 15
March 1998 $ 984 $257 $ 106
June 1998 1,226 286 137
September 1998 1,530 514 255
December 1998 998 143 72
- ---------------------------------------------------------------------
Under the 1998 rate order, the Company recorded $85 million of accelerated
amortization which was recorded monthly throughout 1999 as an operating expense.
See Note 3 to the financial statements under "Retail Rate Orders" for additional
information. In December 1999, in accordance with the order, the Company
reclassified this $85 million to amortization of premium on reacquired debt. The
1999 fourth quarter operating income reflects this reclassification.
The quarterly operating income data above has been reclassified to reflect
the Company's current presentation of income tax expense.
The Company's business is influenced by seasonal weather conditions.
II-110
SELECTED FINANCIAL AND OPERATING DATA 1995-1999
Georgia Power Company 1999 Annual Report
- --------------------------------------------------------------------------------------------------------------------------------
1999 1998 1997 1996 1995
- --------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands) $4,456,675 $4,738,253 $4,385,717 $4,416,779 $4,405,338
Net Income after Dividends
on Preferred Stock (in thousands) $541,383 $570,228 $593,996 $580,327 $608,862
Cash Dividends
on Common Stock (in thousands) $543,000 $536,600 $520,000 $475,500 $451,500
Return on Average Common Equity (percent) 14.02 14.61 14.53 13.73 14.43
Total Assets (in thousands) $12,276,860 $12,033,618 $12,573,728 $13,006,635 $13,470,275
Gross Property Additions (in thousands) $790,464 $499,053 $475,921 $428,220 $480,449
- --------------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $3,938,210 $3,784,172 $4,019,728 $4,154,281 $4,299,012
Preferred stock 14,952 15,527 157,247 464,611 692,787
Company obligated mandatorily
redeemable preferred securities 789,250 689,250 689,250 325,000 100,000
Long-term debt 2,688,358 2,744,362 2,982,835 3,200,419 3,315,460
- --------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $7,430,770 $7,233,311 $7,849,060 $8,144,311 $8,407,259
================================================================================================================================
Capitalization Ratios (percent):
Common stock equity 53.0 52.3 51.2 51.0 51.1
Preferred stock 0.2 0.2 2.0 5.7 8.2
Company obligated mandatorily
redeemable preferred securities 10.6 9.5 8.8 4.0 1.2
Long-term debt 36.2 38.0 38.0 39.3 39.5
- --------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0 100.0 100.0 100.0
================================================================================================================================
Security Ratings:
First Mortgage Bonds -
Moody's A1 A1 A1 A1 A1
Standard and Poor's A+ A+ A+ A+ A+
Duff & Phelps AA- AA- AA- AA- AA-
Preferred Stock -
Moody's a2 a2 a2 a2 a2
Standard and Poor's A- A A A A
Duff & Phelps A+ A+ A+ A+ A
Unsecured Long-Term Debt -
Moody's A2 A2 A2 A2 A2
Standard and Poor's A A A A A
Duff & Phelps A+ A+ A+ A+ A+
================================================================================================================================
Customers (year-end):
Residential 1,632,450 1,596,488 1,561,675 1,531,453 1,500,024
Commercial 229,524 221,180 211,672 205,087 198,624
Industrial 8,958 9,485 9,988 10,424 10,796
Other 3,060 3,034 2,748 2,645 2,568
- --------------------------------------------------------------------------------------------------------------------------------
Total 1,873,992 1,830,187 1,786,083 1,749,609 1,712,012
================================================================================================================================
Employees (year-end): 8,961 8,371 8,354 10,346 11,061
- --------------------------------------------------------------------------------------------------------------------------------
II-111
SELECTED FINANCIAL AND OPERATING DATA 1995-1999 (continued)
Georgia Power Company 1999 Annual Report
- -------------------------------------------------------------------------------------------------------------------------------
1999 1998 1997 1996 1995
- -------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $ 1,410,099 $1,486,699 $ 1,326,787 $ 1,371,033 $ 1,337,060
Commercial 1,527,880 1,591,363 1,493,353 1,486,586 1,449,108
Industrial 1,143,001 1,170,881 1,110,311 1,118,633 1,141,766
Other (30,892) 49,274 47,848 47,060 44,255
- -------------------------------------------------------------------------------------------------------------------------------
Total retail 4,050,088 4,298,217 3,978,299 4,023,312 3,972,189
Sales for resale - non-affiliates 210,104 259,234 282,365 281,580 290,302
Sales for resale - affiliates 76,426 81,606 38,708 35,886 76,906
- -------------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 4,336,618 4,639,057 4,299,372 4,340,778 4,339,397
Other revenues 120,057 99,196 86,345 76,001 65,941
- -------------------------------------------------------------------------------------------------------------------------------
Total $4,456,675 $4,738,253 $4,385,717 $4,416,779 $4,405,338
===============================================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 19,404,709 19,481,486 17,295,022 17,826,451 17,307,399
Commercial 23,715,485 22,861,391 21,134,346 20,823,073 19,844,999
Industrial 27,300,355 27,283,147 26,701,685 26,191,831 25,286,340
Other 551,451 543,462 538,163 536,057 493,720
- -------------------------------------------------------------------------------------------------------------------------------
Total retail 70,972,000 70,169,486 65,669,216 65,377,412 62,932,458
Sales for resale - non-affiliates 5,060,931 6,438,891 6,795,300 7,868,342 6,591,841
Sales for resale - affiliates 1,795,243 2,038,400 1,706,699 1,180,207 2,738,947
- -------------------------------------------------------------------------------------------------------------------------------
Total 77,828,174 78,646,777 74,171,215 74,425,961 72,263,246
===============================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 7.27 7.63 7.67 7.69 7.73
Commercial 6.44 6.96 7.07 7.14 7.30
Industrial 4.19 4.29 4.16 4.27 4.52
Total retail 5.71 6.13 6.06 6.15 6.31
Sales for resale 4.18 4.02 3.78 3.51 3.94
Total sales 5.57 5.90 5.80 5.83 6.00
Residential Average Annual
Kilowatt-Hour Use Per Customer 12,006 12,314 11,171 11,763 11,654
Residential Average Annual
Revenue Per Customer $872.47 $939.73 $857.01 $904.70 $900.28
Plant Nameplate Capacity
Ratings (year-end) (megawatts) 14,474 14,437 14,437 14,367 14,344
Maximum Peak-Hour Demand (megawatts):
Winter 11,568 11,959 10,407 10,410 9,819
Summer 14,575 13,923 13,153 12,914 12,828
Annual Load Factor (percent) 58.9 58.7 57.4 62.2 59.6
Plant Availability (percent):
Fossil-steam 84.3 86.0 85.8 85.2 85.8
Nuclear 89.3 91.6 88.8 89.3 91.8
- -------------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 63.0 62.3 64.3 60.4 63.0
Nuclear 18.0 18.3 18.8 18.2 19.3
Hydro 0.9 2.2 2.2 2.2 2.5
Oil and gas 1.6 2.2 0.6 0.5 0.6
Purchased power -
From non-affiliates 6.6 6.5 2.7 5.6 7.7
From affiliates 9.9 8.5 11.4 13.1 6.9
- -------------------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0 100.0 100.0
===============================================================================================================================
II-112
GULF POWER COMPANY
FIANANCIAL SECTION
II-113
MANAGEMENT'S REPORT
Gulf Power Company 1999 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
Travis J. Bowden
President
and Chief Executive Officer
/s/Arlan E. Scarbrough
Arlan E. Scarbrough
Chief Financial Officer
February 16, 2000
II-114
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, 1999 and 1998, and the related statements
of income, common stockholder's equity, and cash flows for each of the three
years in the period ended December 31, 1999. 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 auditing standards generally
accepted in the United States. 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 11-124 through II-139)
referred to above present fairly, in all material respects, the financial
position of Gulf Power Company as of December 31, 1999 and 1998, and the results
of its operations and its cash flows for each of the three years in the period
ended December 31, 1999, in conformity with accounting principles generally
accepted in the United States.
/s/Arthur Andersen LLP
Atlanta, Georgia
February 16, 2000
II-115
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Gulf Power Company 1999 Annual Report
RESULTS OF OPERATIONS
Earnings
Gulf Power Company's 1999 net income after dividends on preferred stock was
$53.7 million, a decrease of $2.8 million from the previous year. In 1998,
earnings were $56.5 million, down $1.1 million when compared to 1997. The
decrease in earnings in 1999, as well as 1998, was primarily a result of higher
expenses than in the prior year.
Revenues
Operating revenues increased in 1999 and 1998 when compared to 1998 and 1997,
respectively. The following table summarizes the factors impacting operating
revenues for the past three years:
Increase (Decrease)
From Prior Year
---------------------------------------
1999 1998 1997
---------------------------------------
(in thousands)
Retail --
Growth and
price change $10,348 $15,021 $ 4,005
Weather (7,879) 6,656 (5,277)
Regulatory cost
recovery and other 1,173 (34,179) (7,837)
- --------------------------------------------------------------------
Total retail 3,642 (12,502) (9,109)
- --------------------------------------------------------------------
Sales for resale--
Non-affiliates 461 (1,804) 496
Affiliates 23,468 25,882 (1,002)
- --------------------------------------------------------------------
Total sales for resale 23,929 24,078 (506)
Other operating
revenues (3,990) 13,086 1,106
- --------------------------------------------------------------------
Total operating
revenues $23,581 $24,662 $(8,509)
====================================================================
Percent change 3.6% 3.9% (1.3)%
- --------------------------------------------------------------------
Retail revenues of $512.8 million in 1999 increased $3.6 million, or 0.7
percent, from the prior year due primarily to an increase in the number of
retail customers served by the Company. Retail revenues for 1998 decreased $12.5
million, or 2.4 percent, when compared to 1997 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 Committments" for further
information.
The 1999 increase in regulatory cost recovery and other retail revenues over
1998 is primarily attributable to the recovery of increased purchased power
capacity costs. The 1998 decrease in regulatory cost recovery and other retail
revenues over 1997 is primarily attributable to 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 $128.5 million in 1999, an increase of $24 million, or
23 percent, over 1998 primarily 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:
1999 1998 1997
----------------------------------------
(in thousands)
Capacity $19,792 $22,503 $24,899
Energy 20,251 14,556 18,160
- -------------------------------------------------------------
Total $40,043 $37,059 $43,059
=============================================================
Declining capacity revenues are due primarily to the decline in net plant
investment related to these sales. In addition, the decline in 1999 reflects a
reduction in the authorized rate of return on the equity component of the
investment.
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.
II-116
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Gulf Power Company 1999 Annual Report
Other operating revenues decreased in 1999 and 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.
Energy Sales
Kilowatt-hour sales for 1999 and the percent changes by year were as follows:
KWH Percent Change
------------- -------------------------------
1999 1999 1998 1997
------------- -------------------------------
(millions)
Residential 4,471 0.8% 7.7% (1.0)%
Commercial 3,223 3.6 7.4 3.2
Industrial 1,846 0.7 (3.7) 5.3
Other 19 0.0 4.7 1.6
-------------
Total retail 9,559 1.7 5.2 1.6
Sales for resale
Non-affiliates 1,562 16.4 (12.4) (0.2)
Affiliates 2,512 42.9 107.3 19.5
-------------
Total 13,633 9.0 10.5 2.5
==================================================================
In 1999, total retail energy sales increased due to increases from 1998 in
the number of residential, commercial and industrial customers. Total energy
sales increased in 1998 when compared to 1997 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. 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).
An increase in energy sales for resale to non-affiliates of 16.4 percent in
1999 when compared 1998 and a decrease of 12.4 percent in 1998 when compared to
1997 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 1999 increased $26.8 million, or 5.1 percent, over
the amount recorded in 1998 due primarily to higher fuel and purchased power
expenses, offset by lower other operation expenses. In 1998, total operating
expenses increased $26.5 million, or 5.3 percent, from 1997. The increase was
due primarily to higher fuel, purchased power, and maintenance expenses offset
by lower other operation expenses.
Fuel expenses in 1999, when compared to 1998, increased $11.5 million, or 5.9
percent. In 1998, fuel expenses increased $16.6 million, or 9.2 percent, when
compared to 1997. The increases were the result of increased generation
resulting from a higher demand for energy, while average fuel costs decreased as
noted below.
Purchased power expenses increased in 1999 by $13.2 million, or 30.2 percent,
over 1998 and purchased power expenses for 1998 increased over 1997 by $6.9
million, or 18.8 percent, due to a higher demand for energy in both years.
The amount and sources of generation and the average cost of fuel per net
kilowatt-hour generated were as follows:
1999 1998 1997
-------------------------------
Total generation
(millions of kilowatt-hours) 13,095 11,986 10,435
Sources of generation
(percent)
Coal 97.4 98.0 99.6
Oil and gas 2.6 2.0 0.4
Average cost of fuel per net
kilowatt-hour generated
(cents)-- 1.60 1.69 1.99
- ---------------------------------------------------------------------
Other operation expenses decreased $4.3 million, or 3.6 percent, in 1999 from
the 1998 level and $7.3 million, or 5.7 percent, in 1998 from the 1997 level due
to a decrease in the amortization costs of prior year payments related to
renegotiations of coal supply contracts. The 1998 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.
II-117
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 1999 Annual Report
Depreciation and amortization expense increased $5.5 million, or 9.2 percent,
in 1999 when compared to 1998 due primarily to a reduction in the amortization
of gains from the 1998 sale of emission allowances.
Maintenance expenses in 1998 increased by $9.3 million, or 19.4 percent, over
1997 due primarily to scheduled maintenance at Plant Crist and Plant Smith and
increased transmission and distribution maintenance.
Interest on long-term debt in 1999 increased $1.7 million, or 8.4 percent,
when compared to 1998 due primarily to two first mortgage bonds maturing in 1998
and being replaced by senior notes at a slightly higher interest rate, and the
issuance of $50 million of senior notes in August 1999. In 1998, interest on
long-term debt decreased $2.0 million, or 9.1 percent, from 1997 mostly due 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 the replacement in 1998 of the two
maturing first mortgage bonds with senior notes at a slightly higher interest
rate.
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 long economic lives. 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 early 1999, the FPSC
Staff and the Company became involved in serious discussions primarily related
to reducing the Company's authorized rate of return. On October 1, 1999 the
Office of Public Counsel, the Coalition for Equitable Rates, the Florida
Industrial Power Users Group, and the Company jointly filed a petition to
resolve the issues. The stipulation included a reduction to retail base rates of
$10 million annually and provides for revenues to be shared within set ranges
for 1999 through 2002. Customers would receive two-thirds of any revenue within
the ranges and the Company would retain one-third. For calendar year 2000, the
Company's retail base rate revenues in excess of $352 million up to $368 million
will be shared between the Company and its retail customers on the
one-third/two-thirds basis. Retail base rate revenues above $368 million for
calendar year 2000 will be refunded to the Company's customers. These set ranges
increase gradually until the expiration of the plan. The Sharing Plan will be in
place until the earlier of the in-service date of Smith Unit 3 or December 31,
2002. The parties could not agree on the appropriate Return on Equity (ROE).
Consequently, the Company filed a request to prospectively reduce its authorized
ROE range from 11 to 13 percent to 10.5 to 12.5 percent in order to help ensure
that the FPSC would approve the stipulation. Both the stipulation and the ROE
request were approved by the Commission on October 5, 1999, with an effective
date of November 4, 1999.
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
II-118
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 1999 Annual Report
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. 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 these
initiatives materialize, the structure of the utility industry continues to
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 financial
condition and results of operation. 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, if the Company does not remain a low-cost producer and provide
quality service, the Company's 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 pilot program ends in September of 2000 and the company is
currently reviewing its options.
Every five years the FPSC establishes numeric demand side management goals.
The Company proposed numeric goals for the ten-year period from 2000 to 2009.
The proposed goals consisted of the total, cost-effective winter and summer peak
demand (kilowatts) and annual energy (kilowatt-hour) savings reasonably
achievable from demand side management for the residential and
commercial/industrial classes. The Company submitted its 2000 Demand Side
Management Plan to the FPSC on December 29, 1999. The plan describes the
Company's proposed programs it will employ to reach the numeric goals. The plan
relies heavily on innovative pricing and energy efficient construction. The FPSC
is expected to issue its final order on the Company's 2000 Demand Side
Management Plan in mid-April 2000.
On December 20, 1999, the Federal Energy Regulatory Commission (FERC) issued
its final rule on Regional Transmission Organizations (RTOs). The order
encourages utilities owning transmission systems to form RTOs on a voluntary
basis. To facilitate the development of RTOs, the FERC will convene regional
conferences for utilities, customers, and other members of the public to discuss
the formation of RTOs. In addition to participating in the regional conferences,
utilities owning transmission systems, including Southern Company, are required
to make a filing by October 15, 2000. The filing must contain either a proposal
for RTO participation or a description of the efforts made to participate in an
RTO, the reasons for non-participation, any obstacles to participation, and any
II-119
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 1999 Annual Report
plans for further work toward participation. The RTOs that are proposed in the
filings should be operational by December 15, 2001. Southern Company is
evaluating this issue and formulating its response. The outcome of this matter
cannot now be determined.
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.
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, 1999, 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, 1999, 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 January 1, 2001. 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.
Year 2000 Challenge
The work undertaken by the Company to ensure that all critical computer systems
and other date sensitive devices would function correctly in the Year 2000 was
successful. There were no material incidents reported and no disruption of
electric service within the service area of the Company. There were no reports
of significant events regarding third parties that impacted revenues or
expenses.
The Company's original projected total costs for Year 2000 readiness were
approximately $5 million. Final projected costs were also $5 million with no
material costs remaining to be spent in 2000. From its inception through
December 31, 1999, the Year 2000 program costs, recognized primarily as expense,
amounted to $5 million, of which $2 million was recorded in 1999.
FINANCIAL CONDITION
Overview
The Company's financial condition continues to be very solid. During 1999, gross
property additions were $69.8 million. Funds for the property additions were
provided by operating activities. See the Statements of Cash Flows for further
details.
Financing Activities
In 1999, the Company sold $50 million of senior notes and long-term bank notes
totaling $27 million were retired. The remaining proceeds from this issuance
were used to reduce short-term borrowing requirements. See the Statements of
Cash Flows for further details.
Composite financing rates for the years 1997 through 1999 as of year end were
as follows:
II-120
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 1999 Annual Report
1999 1998 1997
-----------------------------
Composite interest rate on
long-term debt 6.0% 6.1% 5.9%
Composite rate on
trust preferred securities 7.3% 7.3% 7.6%
Composite preferred stock
dividend rate 5.1% 5.1% 6.1%
- -----------------------------------------------------------------
The composite interest rate on long-term debt decreased in 1999 primarily due
to lower interest rates on variable rate pollution control bonds.
Capital Requirements for Construction
The Company's gross property additions, including those amounts related to
environmental compliance, are budgeted at $428 million for the three years
beginning in 2000 ($106 million in 2000, $232 million in 2001, and $90 million
in 2002). These amounts include $198.8 million for the years 2000 through 2002
for the estimated cost of a 574 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. The remaining property additions budget is
primarily for maintaining and upgrading transmission and distribution facilities
and generating plants. 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.
Other Capital Requirements
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.
For Phase II sulfur dioxide compliance, Southern Company currently uses
emission allowances and increased fuel switching. Also, equipment to control
nitrogen oxide emissions was installed on additional system fossil-fired units
as required to meet Phase II limits and ozone non-attainment requirements.
Compliance for Phase II and initial ozone non-attainment requirements increased
total estimated construction expenditures by approximately $105 million. 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 reduction rule to the states for
implementation. The final rule affects 22 states, including Alabama and Georgia.
II-121
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 1999 Annual Report
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's July 1997 standards and the September 1998 rule are being
challenged in the courts by several states and industry groups. Implementation
of the final state rules for these three initiatives could require substantial
further reductions in nitrogen oxide and sulfur dioxide emissions from
fossil-fired generating facilities and other industries in these states.
Additional compliance costs and capital expenditures resulting from the
implementation of these rules and standards 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
any new standards will depend on the development and implementation of
applicable regulations.
On November 3, 1999, the EPA brought a civil action in the U.S. District
Court against Alabama Power, Georgia Power, and the system service company. The
complaint alleges violations of the prevention of significant deterioration and
new source review provisions of the Clean Air Act with respect to five
coal-fired generating facilities in Alabama and Georgia. The civil action
requests penalties and injunctive relief, including an order requiring the
installation of the best available control technology at the affected units. The
EPA concurrently issued to the integrated Southeast utilities a notice of
violation related to 10 generating facilities, including the five facilities
mentioned previously and the Company's Plants Crist and Scherer. 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. In
early 2000, the EPA filed a motion to amend its complaint to add the violations
alleged in its notice of violation, and to add Gulf Power, Mississippi Power,
and Savannah Electric as defendants. The complaint and notice of violation are
similar to those brought against and issued to several other electric utilities.
These complaints and notices of violation allege that the utilities had failed
to secure necessary permits or install additional pollution equipment when
performing maintenance and construction at coal burning plants constructed or
under construction prior to 1978. Southern Company believes that its integrated
utilities complied with applicable laws and the EPA's regulations and
interpretations in effect at the time the work in question took place. The
Clean Air Act authorizes civil penalties of up to $27,500 per day per violation
at each generating unit. Prior to January 30, 1997, the penalty was $25,000 per
day. An adverse outcome of this matter could require substantial capital
expenditures that cannot be determined at this time and possibly require payment
of substantial penalties. This could affect future results of operations, cash
flows, and possibly financial condition if such costs are not recovered through
regulated rates.
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.
11-122
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 1999 Annual Report
Sources of Capital
At December 31, 1999, the Company had approximately $15.8 million of cash and
cash equivalents and $41.5 million of unused committed lines of credit with
banks to meet its short-term cash needs. Refer to the Statements of Cash Flows
for 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
The Company's 1999 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; 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.
11-123
STATEMENTS OF INCOME
For the Years Ended December 31, 1999, 1998, and 1997
Gulf Power Company 1999 Annual Report
- -----------------------------------------------------------------------------------------------------------
1999 1998 1997
- -----------------------------------------------------------------------------------------------------------
(in thousands)
Operating Revenues:
Retail sales $512,760 $509,118 $521,619
Sales for resale --
Non-affiliates 62,354 61,893 63,697
Affiliates 66,110 42,642 16,760
Other revenues 32,875 36,865 23,780
- -----------------------------------------------------------------------------------------------------------
Total operating revenues 674,099 650,518 625,856
- -----------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
Fuel 209,031 197,462 180,843
Purchased power --
Non-affiliates 46,332 29,369 11,938
Affiliates 10,703 14,445 24,955
Other 114,670 119,011 126,266
Maintenance 57,830 57,286 47,988
Depreciation and amortization 64,589 59,129 57,874
Taxes other than income taxes 51,782 51,462 51,775
- -----------------------------------------------------------------------------------------------------------
Total operating expenses 554,937 528,164 501,639
- -----------------------------------------------------------------------------------------------------------
Operating Income 119,162 122,354 124,217
Other Income (Expense):
Interest income 1,771 931 1,203
Other, net (1,357) (2,339) (992)
- -----------------------------------------------------------------------------------------------------------
Earnings Before Interest and Income Taxes 119,576 120,946 124,428
- -----------------------------------------------------------------------------------------------------------
Interest Charges and Other:
Interest on long-term debt 21,375 19,718 21,699
Interest on notes payable 2,371 1,190 891
Amortization of debt discount, premium and expense, net 1,989 2,100 2,281
Other interest charges 1,126 2,548 2,076
Distributions on preferred securities of subsidiary 6,200 6,034 2,804
- -----------------------------------------------------------------------------------------------------------
Total interest charges and other, net 33,061 31,590 29,751
- -----------------------------------------------------------------------------------------------------------
Earnings Before Income Taxes 86,515 89,356 94,677
Income taxes (Note 8) 32,631 32,199 33,450
- -----------------------------------------------------------------------------------------------------------
Net Income 53,884 57,157 61,227
Dividends on Preferred Stock 217 636 3,617
- -----------------------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred Stock $ 53,667 $ 56,521 $ 57,610
===========================================================================================================
The accompanying notes are an integral part of these statements.
II-124
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1999, 1998, and 1997
Gulf Power Company 1999 Annual Report
- ------------------------------------------------------------------------------------------------------------------------------------
1999 1998 1997
- --------------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Activities:
Net income $ 53,884 $ 57,157 $ 61,227
Adjustments to reconcile net income
to net cash provided from operating activities --
Depreciation and amortization 68,721 69,633 72,860
Deferred income taxes and investment tax credits, net (6,609) (4,684) (7,047)
Other, net 3,735 3,463 4,831
Changes in certain current assets and liabilities --
Receivables, net (10,484) 11,308 (692)
Fossil fuel stock (5,656) (4,917) 9,056
Materials and supplies (2,063) 609 1,618
Accounts payable (2,023) 823 1,398
Other 7,030 (18,471) 22,296
- --------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities 106,535 114,921 165,547
- --------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (69,798) (69,731) (54,289)
Other (8,856) 5,990 509
- --------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities (78,654) (63,741) (53,780)
- --------------------------------------------------------------------------------------------------------------------------
Financing Activities:
Increase (decrease) in notes payable, net 23,500 (15,500) 22,000
Proceeds --
Other long-term debt 50,000 50,000 60,930
Preferred securities - 45,000 40,000
Capital contributions from parent company 2,294 522 -
Retirements --
First mortgage bonds - (45,000) (25,000)
Other long-term debt (27,074) (8,326) (56,902)
Preferred stock - (9,455) (75,911)
Payment of preferred stock dividends (271) (792) (5,370)
Payment of common stock dividends (61,300) (67,200) (64,600)
Other (246) (4,167) (3,014)
- --------------------------------------------------------------------------------------------------------------------------
Net cash used for financing activities (13,097) (54,918) (107,867)
- --------------------------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents 14,784 (3,738) 3,900
Cash and Cash Equivalents at Beginning of Period 969 4,707 807
- --------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ 15,753 $ 969 $ 4,707
==========================================================================================================================
Supplemental Cash Flow Information:
Cash paid during the period for --
Interest (net of amount capitalized) $27,670 $28,044 $26,558
Income taxes (net of refunds) 29,462 38,782 36,010
- --------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
II-125
BALANCE SHEETS
At December 31, 1999 and 1998
Gulf Power Company 1999 Annual Report
- ---------------------------------------------------------------------------------------------------------------------
Assets 1999 1998
- ---------------------------------------------------------------------------------------------------------------------
(in thousands)
Current Assets:
Cash and cash equivalents $ 15,753 $ 969
Receivables --
Customer accounts receivable 55,108 49,067
Other accounts and notes receivable 4,325 3,514
Affiliated companies 7,104 3,442
Accumulated provision for uncollectible accounts (1,026) (996)
Fossil fuel stock, at average cost 29,869 24,213
Materials and supplies, at average cost (Note 1) 30,088 28,025
Regulatory clauses under recovery (Note 1) 11,611 9,737
Other 5,354 9,725
- ---------------------------------------------------------------------------------------------------------------------
Total current assets 158,186 127,696
- ---------------------------------------------------------------------------------------------------------------------
Property, Plant, and Equipment:
In service (Notes 1 and 6) 1,853,664 1,809,901
Less accumulated provision for depreciation 821,970 784,111
- ---------------------------------------------------------------------------------------------------------------------
1,031,694 1,025,790
Construction work in progress 34,164 34,863
- ---------------------------------------------------------------------------------------------------------------------
Total property, plant, and equipment 1,065,858 1,060,653
- ---------------------------------------------------------------------------------------------------------------------
Other Property and Investments 1,481 588
- ---------------------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets:
Deferred charges related to income taxes (Note 8) 25,264 25,308
Prepaid pension costs (Note 2) 17,734 13,770
Debt expense, being amortized 2,526 2,565
Premium on reacquired debt, being amortized 17,360 18,883
Other 20,086 18,438
- ---------------------------------------------------------------------------------------------------------------------
Total deferred charges and other assets 82,970 78,964
- ---------------------------------------------------------------------------------------------------------------------
Total Assets $1,308,495 $1,267,901
=====================================================================================================================
The accompanying notes are an integral part of these balance sheets.
II-126
BALANCE SHEETS
At December 31, 1999 and 1998
Gulf Power Company 1999 Annual Report
- ----------------------------------------------------------------------------------------------------------------------
Liabilities and Stockholder's Equity 1999 1998
- ----------------------------------------------------------------------------------------------------------------------
(in thousands)
Current Liabilities:
Securities due within one year (Note 10) $ - $ 27,000
Notes payable 55,000 31,500
Accounts payable --
Affiliated 14,878 19,756
Other 22,581 23,697
Customer deposits 12,778 12,560
Taxes accrued --
Income taxes 4,889 -
Other 7,707 7,432
Interest accrued 9,255 5,184
Vacation pay accrued 4,199 4,035
Other 4,961 10,051
- ----------------------------------------------------------------------------------------------------------------------
Total current liabilities 136,248 141,215
- ----------------------------------------------------------------------------------------------------------------------
Long-term debt (See accompanying statements) 367,449 317,341
- ----------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes (Note 8) 162,776 166,118
Deferred credits related to income taxes (Note 8) 49,693 52,465
Accumulated deferred investment tax credits 27,712 29,632
Employee benefits provisions 31,735 28,594
Other 21,333 15,648
- ----------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 293,249 292,457
- ----------------------------------------------------------------------------------------------------------------------
Company obligated mandatorily redeemable preferred
securities of subsidiary trusts holding company junior
subordinated notes (See accompanying statements) 85,000 85,000
- ----------------------------------------------------------------------------------------------------------------------
Preferred stock (See accompanying statements) 4,236 4,236
- ----------------------------------------------------------------------------------------------------------------------
Common stockholder's equity (See accompanying statements) 422,313 427,652
- ----------------------------------------------------------------------------------------------------------------------
Total Liabilities and Stockholder's Equity $1,308,495 $1,267,901
======================================================================================================================
The accompanying notes are an integral part of these balance sheets.
II-127
STATEMENTS OF CAPITALIZATION
At December 31, 1999 and 1998
Gulf Power Company 1999 Annual Report
- ------------------------------------------------------------------------------------------------------------------------------
1999 1998 1999 1998
- ------------------------------------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
Long-Term Debt:
First mortgage bonds --
Maturity Interest Rates
--------- -------------
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 85,000
- ------------------------------------------------------------------------------------------------------------------------------
Long-term notes payable --
7.05% due August 15, 2004 50,000 -
7.50% due June 30, 2037 20,000 20,000
6.70% due June 30, 2038 49,926 50,000
Adjustable rate (5.72% at 1/1/99)
due November 20, 1999 - 27,000
- ------------------------------------------------------------------------------------------------------------------------------
Total long-term notes payable 119,926 97,000
- ------------------------------------------------------------------------------------------------------------------------------
Other long-term debt --
Pollution control revenue bonds --
Collateralized with first mortgage bonds:
5.25% to 6.30% due 2006-2026 108,700 108,700
Variable rate (3.70% at 1/1/00)
due 2024 20,000 20,000
Collateralized with other property:
Variable rate (3.75% at 1/1/00)
due 2022 40,930 40,930
- ------------------------------------------------------------------------------------------------------------------------------
Total other long-term debt 169,630 169,630
- ------------------------------------------------------------------------------------------------------------------------------
Unamortized debt premium (discount), net (7,107) (7,289)
- ------------------------------------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
requirement -- $22.5 million) 367,449 344,341
Less amount due within one year (Note 10) - 27,000
- ------------------------------------------------------------------------------------------------------------------------------
Long-term debt excluding amount due within one year 367,449 317,341 41.8% 38.0%
- ------------------------------------------------------------------------------------------------------------------------------
Company Obligated Mandatorily
Redeemable Preferred Securities: (Note 9)
$25 liquidation value --
7.00% 45,000 45,000
7.625% 40,000 40,000
- ------------------------------------------------------------------------------------------------------------------------------
Total (annual distribution requirement -- $6.2 million) 85,000 85,000 9.7 10.2
- ------------------------------------------------------------------------------------------------------------------------------
Cumulative Preferred Stock:
$100 par value
4.64% to 5.44% 4,236 4,236
- ------------------------------------------------------------------------------------------------------------------------------
Total (annual dividend requirement -- $0.2 million) 4,236 4,236
Less amount due within one year - -
- ------------------------------------------------------------------------------------------------------------------------------
Total excluding amount due within one year 4,236 4,236 0.5 0.5
- ------------------------------------------------------------------------------------------------------------------------------
Common Stockholder's Equity:
Common stock, without par value --
Authorized and Outstanding -
992,717 shares in 1999 and 1998 38,060 38,060
Paid-in capital 221,254 218,960
Premium on preferred stock 12 12
Retained earnings (Note 11) 162,987 170,620
- ------------------------------------------------------------------------------------------------------------------------------
Total common stockholder's equity 422,313 427,652 48.0 51.3
- ------------------------------------------------------------------------------------------------------------------------------
Total Capitalization $878,998 $834,229 100.0% 100.0%
==============================================================================================================================
The accompanying notes are an integral part of these statements.
II-128
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
For the Years Ended December 31, 1999, 1998, and 1997
Gulf Power Company 1999 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------
Premium on
Common Paid-In Preferred Retained
Stock Capital Stock Earnings Total
- -----------------------------------------------------------------------------------------------------------------------------
(in thousands)
Balance at January 1, 1997 $38,060 $218,437 $81 $179,180 $435,758
Net income after dividends on preferred stock - - - 57,610 57,610
Cash dividends on common stock - - - (64,600) (64,600)
Other - 1 (69) 18 (50)
- -----------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1997 38,060 218,438 12 172,208 428,718
Net income after dividends on preferred stock - - - 56,521 56,521
Capital contributions from parent company - 522 - - 522
Cash dividends on common stock - - - (57,200) (57,200)
Other - - - (909) (909)
- -----------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1998 38,060 218,960 12 170,620 427,652
Net income after dividends on preferred stock - - - 53,667 53,667
Capital contributions from parent company - 2,294 - - 2,294
Cash dividends on common stock - - - (61,300) (61,300)
- -----------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1999 $38,060 $221,254 $12 $162,987 $422,313
=============================================================================================================================
The accompanying notes are an integral part of these statements.
II-129
NOTES TO FINANCIAL STATEMENTS
Gulf Power Company 1999 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 integrated Southeast utilities, 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 integrated Southeast utilities -- Alabama Power, Georgia
Power, Gulf Power, Mississippi Power, and Savannah Electric -- provide electric
service in four states. Gulf Power Company provides electric service to the
northwest panhandle of Florida. Contracts among the integrated Southeast
utilities -- related to 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. Southern Nuclear provides services to Southern Company's nuclear
power plants. Southern Energy acquires, develops, builds, owns, and operates
power production and delivery facilities and provides a broad range of
energy-related services to utilities and industrial companies in selected
countries around the world. Southern Energy businesses include independent power
projects, integrated utilities, a distribution company, and energy trading and
marketing businesses outside the southeastern United States.
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 and
the FERC. 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.
Related-Party Transactions
The Company has an agreement with Southern Company Services, Inc. (a wholly
owned subsidiary of Southern Company) under which the following services are
rendered to the company at cost: general and design engineering, purchasing,
accounting and statistical, finance and treasury, tax, information resources,
marketing, auditing, insurance and pension, human resources, systems and
procedures, and other services with respect to business and operations and power
pool operations. Costs for these services amounted to $43 million, $40 million,
and $36 million during 1999, 1998, and 1997, respectively.
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:
II-130
NOTES TO FINANCIAL STATEMENTS
Gulf Power Company 1999 Annual Report
1999 1998
--------------------------
(in thousands)
Deferred income tax debits $25,264 $ 25,308
Deferred loss on reacquired
debt 17,360 18,883
Environmental remediation 5,745 7,076
Vacation pay 4,199 4,035
Regulatory clauses under (over)
recovery, net 8,486 3,700
Accumulated provision for
property damage (5,528) (1,605)
Deferred income tax credits (49,693) (52,465)
Other, net (1,255) (480)
- ------------------------------------------------------------------
Total $ 4,578 $ 4,452
==================================================================
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 related 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.
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.
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 retail 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 retail 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 plant in service is provided primarily by
using composite straight-line rates, which approximated 3.8 percent in 1999 and
1998 and 3.6 percent in 1997. 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.
Property, Plant, and Equipment
Property, plant, and equipment 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.
II-131
NOTES (continued)
Gulf Power Company 1999 Annual Report
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, 1999 $367,449 $349,791
At December 31, 1998 $344,341 $357,100
Capital trust preferred
securities:
At December 31, 1999 $85,000 $69,092
At December 31, 1998 $85,000 $89,400
- --------------------------------------------------------------
The fair values for long-term debt and preferred 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.
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 $1.8 million and $1.3 million
at December 31, 1999 and 1998, respectively, is included in other 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, 1999 and 1998, the accumulated
provision for property damage was $5.5 million and $1.6 million, respectively.
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. The Company
accrued $5.5 million in 1999 and $6.5 million in 1998 to the accumulated
provision for property damage. The Company charged $1.6 million to the provision
account in 1999. 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 required by the Company's regulatory commissions. The
measurement date for plan assets and obligations 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
---------------------------
1999 1998
- ---------------------------------------------------------------
(in thousands)
Balance at beginning of year $143,012 $130,794
Service cost 4,490 4,107
Interest cost 9,440 9,572
Benefits paid (6,862) (6,663)
Actuarial loss (gain) and
employee transfers (8,113) 5,202
- ---------------------------------------------------------------
Balance at end of year $141,967 $143,012
===============================================================
II-132
NOTES (continued)
Gulf Power Company 1999 Annual Report
Plan Assets
---------------------------
1999 1998
- ---------------------------------------------------------------
(in thousands)
Balance at beginning of year $212,934 $222,196
Actual return on plan assets 35,971 1,310
Benefits paid (6,862) (6,663)
Employee transfers (558) (3,909)
- ---------------------------------------------------------------
Balance at end of year $241,485 $212,934
===============================================================
The accrued pension costs recognized in the Balance Sheets were as follows:
1999 1998
- ---------------------------------------------------------------
(in thousands)
Funded status $99,518 $ 69,922
Unrecognized transition
obligation (4,323) (5,043)
Unrecognized prior
service cost 4,495 4,869
Unrecognized net gain (81,956) (55,978)
- ---------------------------------------------------------------
Prepaid asset recognized
in the Balance Sheets $17,734 $13,770
===============================================================
Components of the pension plan's net periodic cost were as follows:
1999 1998 1997
- -----------------------------------------------------------------
Service cost $4,490 $ 4,107 $ 3,897
Interest cost 9,440 9,572 9,301
Expected return on
plan assets (15,968) (14,827) (13,675)
Recognized net gain (1,579) (1,891) (1,656)
Net amortization (347) (347) (347)
- -----------------------------------------------------------------
Net pension income $(3,964) $(3,386) $ (2,480)
=================================================================
Postretirement Benefits
Changes during the year in the accumulated benefit obligations and in the fair
value of plan assets were as follows:
Accumulated
Benefit Obligations
---------------------------
1999 1998
- ---------------------------------------------------------------
(in thousands)
Balance at beginning of year $49,303 $39,669
Service cost 1,087 946
Interest cost 3,261 3,123
Benefits paid (1,177) (1,068)
Actuarial (loss) gain and
employee transfers (4,464) 3,614
Amendments - 3,019
- ---------------------------------------------------------------
Balance at end of year $48,010 $49,303
===============================================================
Plan Assets
---------------------------
1999 1998
- ---------------------------------------------------------------
(in thousands)
Balance at beginning of year $9,603 $9,455
Actual return on plan assets 1,525 54
Employer contributions 1,245 1,162
Benefits paid (1,177) (1,068)
- ---------------------------------------------------------------
Balance at end of year $11,196 $9,603
===============================================================
The accrued postretirement costs recognized in the Balance Sheets were as
follows:
1999 1998
- ---------------------------------------------------------------
(in thousands)
Funded status $(36,814) $(39,700)
Unrecognized transition
obligation 4,723 5,079
Unrecognized prior
service cost 2,741 2,900
Unrecognized net loss 2,620 8,187
Fourth quarter contributions 300 -
- ---------------------------------------------------------------
Accrued liability recognized
in the Balance Sheets $(26,430) $(23,534)
===============================================================
II-133
NOTES (continued)
Gulf Power Company 1999 Annual Report
Components of the postretirement plan's net periodic cost were as follows:
1999 1998 1997
- ---------------------------------------------------------------
Service cost $1,087 $ 946 $ 896
Interest cost 3,261 3,123 2,845
Expected return on
plan assets (794) (717) (641)
Transition obligation 356 356 356
Prior service cost 159 119 -
Recognized net loss 264 128 184
- ---------------------------------------------------------------
Net postretirement cost $4,333 $3,955 $3,640
===============================================================
The weighted average rates assumed in the actuarial calculations for both the
pension plan and postretirement benefits were:
1999 1998
- --------------------------------------------------------
Discount 7.50% 6.75%
Annual salary increase 5.00% 4.25%
Long-term return on plan
assets 8.50% 8.50%
- --------------------------------------------------------
An additional assumption used in measuring the accumulated postretirement
benefit obligations was a weighted average medical care cost trend rate of 7.74
percent for 1999, decreasing gradually to 5.5 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,
1999 as follows (in thousands):
1 Percent 1 Percent
Increase Decrease
- ---------------------------------------------------------------
Benefit obligation $3,627 $(3,086)
Service and interest costs $320 $(269)
===============================================================
Work Force Reduction Programs
The Company recorded costs related to work force reduction programs of $0.2
million in 1999, $2.8 million in 1998, and $1.4 million in 1997. The Company has
also incurred its pro rata share for the costs of affiliated companies'
programs. The costs related to these programs were $0.6 million for 1999, $0.2
million for 1998, and $1.3 million for 1997. The Company has expensed all costs
related to these work force reduction programs.
3. CONTINGENCIES AND REGULATORY
MATTERS
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 is 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 1999 and 1998, the Company recorded ECRC revenues of
$11.6 million and $8.0 million, respectively.
At December 31, 1999, the Company's liability for the estimated costs of
environmental remediation projects for known sites was $5.7 million. These
estimated costs are expected to be expended from 2000 through 2006. These
projects have been approved by the FPSC for recovery through the ECRC discussed
above. Therefore, the Company recorded $1.2 million in current assets and
current liabilities and $4.5 million in deferred assets and deferred liabilities
representing the future recoverability of these costs.
Environmental Litigation
On November 3, 1999, the Environmental Protection Agency (EPA) brought a civil
action in the U.S. District Court against Alabama Power, Georgia Power, and the
system service company. The complaint alleges violations of the prevention of
significant deterioration and new source review provisions of the Clean Air Act
II-134
NOTES (continued)
Gulf Power Company 1999 Annual Report
with respect to five coal-fired generating facilities in Alabama and Georgia.
The civil action requests penalties and injunctive relief, including an order
requiring the installation of the best available control technology at the
affected units. The Clean Air Act authorizes civil penalties of up to $27,500
per day, per violation at each generating unit. Prior to January 30, 1997, the
penalty was $25,000 per day.
The EPA concurrently issued to the integrated Southeast utilities a notice of
violation related to 10 generating facilities, including the five facilities
mentioned previously and the Company's Plants Crist and Scherer. See Note 6
under "Joint Ownership Agreements" related to the Company's ownership interest
in Georgia Power's Plant Scherer Unit No. 3. In early 2000, the EPA filed a
motion to amend its complaint to add the violations alleged in its notice of
violation, and to add Gulf Power, Mississippi Power, and Savannah Electric as
defendants. The complaint and notice of violation are similar to those brought
against and issued to several other electric utilities. These complaints and
notices of violation allege that the utilities had failed to secure necessary
permits or install additional pollution equipment when performing maintenance
and construction at coal burning plants constructed or under construction prior
to 1978. Southern Company believes that its integrated utilities complied with
applicable laws and the EPA's regulations and interpretations in effect at the
time the work in question took place.
An adverse outcome of this matter could require substantial capital
expenditures that cannot be determined at this time and possibly require payment
of substantial penalties. This could affect future results of operations, cash
flows, and possibly financial condition if such costs are not recovered through
regulated rates.
4. CONSTRUCTION PROGRAM
The Company is engaged in a continuous construction program, the cost of which
is currently estimated to total $106 million in 2000, $232 million in 2001, and
$90 million in 2002. 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, 1999, significant purchase commitments were outstanding in
connection with the construction program. The Company has budgeted $198.8
million for the years 2000 through 2002 for the estimated cost of a 574 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. 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 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, 1999, the Company had $41.5 million of lines of credit with
banks subject to renewal June 1 of each year, all of which 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 seven major money center banks that total $130 million, of which $50
million was committed at December 31, 1999.
11-135
NOTES (continued)
Gulf Power Company 1999 Annual Report
Assets Subject to Lien
The Company's mortgage, which secures the first mortgage bonds issued by the
Company, constitutes a direct first lien on substantially all of the Company's
fixed property and franchises.
Fuel Commitments
To supply a portion of the fuel requirements of its generating plants, the
Company has entered into long-term commitments for the procurement of fuel. In
most cases, these contracts contain provisions for price escalations, minimum
purchase levels, and other financial commitments. Total estimated long-term
obligations at December 31, 1999 were as follows:
Year Fuel
--------- ----------------
(in millions)
2000 $89
2001 70
2002 86
2003 90
2004 91
2005 - 2026 508
----------------------------------------------------------
Total commitments $934
==========================================================
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 1999 and $2.8 million in 1998.
The annual amounts for 2000 through 2004 are expected to be $2.1 million, $1.7
million, $1.7 million, $1.7 million, and $1.8 million, respectively, and after
2004 are expected to total $14.4 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-136
NOTES (continued)
Gulf Power Company 1999 Annual Report
At December 31, 1999, 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 $185,714(1) $231,041
Accumulated Depreciation $66,193 $113,687
Construction Work in Progress $276 $2,621
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 $19.8 million in 1999, $22.5 million in
1998, and $24.9 million in 1997. Declining capacity revenues are due primarily
to the decline in net plant investment related to these sales. In addition, the
decline in 1999 reflects a reduction in the authorized rate of return on the
equity component of the investment.
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 1999. Sales will decrease to 209 megawatts per year
in 2000 and remain at that level -- unless reduced by FP&L, FPC, and JEA for the
periods after 2000 with a minimum of three years notice -- until the expiration
of the contracts in 2010.
Capacity and energy sales to FP&L, the Company's largest single customer,
provided revenues of $24.3 million in 1999, $22.3 million in 1998, and $25.4
million in 1997, or 3.6 percent, 3.4 percent, and 4.1 percent of operating
revenues, respectively.
8. INCOME TAXES
At December 31, 1999, 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 allowance for funds used during construction. At December 31, 1999,
the tax-related regulatory liabilities to be credited to customers were $49.7
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:
1999 1998 1997
------------------------------------
(in thousands)
Total provision for income taxes:
Federal--
Current $33,973 $31,746 $34,522
Deferred --current year 16,776 18,485 19,297
--reversal of
prior years (22,883) (22,952) (25,778)
- --------------------------------------------------------------------
27,866 27,279 28,041
- --------------------------------------------------------------------
State--
Current 5,267 5,137 5,975
Deferred --current year 2,474 2,745 2,868
--reversal of
prior years (2,976) (2,962) (3,434)
- --------------------------------------------------------------------
4,765 4,920 5,409
- --------------------------------------------------------------------
Total $32,631 $32,199 $33,450
====================================================================
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:
11-137
NOTES (continued)
Gulf Power Company 1999 Annual Report
1999 1998
--------------------------
(in thousands)
Deferred tax liabilities:
Accelerated depreciation $168,662 $155,833
Property basis differences 6,000 20,330
Other 18,272 17,645
- ---------------------------------------------------------------------
Total 192,934 193,808
- ---------------------------------------------------------------------
Deferred tax assets:
Federal effect of state deferred taxes 9,293 9,509
Postretirement benefits 8,456 7,644
Other 12,526 10,702
- ---------------------------------------------------------------------
Total 30,275 27,855
- ---------------------------------------------------------------------
Net deferred tax liabilities 162,659 165,953
Less current portion, net (117) (165)
- ---------------------------------------------------------------------
Accumulated deferred income
taxes in the Balance Sheets $162,776 $166,118
=====================================================================
Deferred investment tax credits are amortized over the lives 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 1999, $1.9 million in 1998, and $2.2
million in 1997. At December 31, 1999, 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:
1999 1998 1997
----------------------------
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) (2) (1)
Other, net - (2) (4)
- ----------------------------------------------------------------
Effective income tax rate 38% 36% 35%
================================================================
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.
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:
1999 1998
----------------------
(in thousands)
Bond improvement fund requirement $850 $ 850
Less portion to be satisfied by
certifying property additions 850 850
- -----------------------------------------------------------------
Cash requirement - -
Maturities of first mortgage bonds - -
Current portion of other long-term
debt - 27,000
- -----------------------------------------------------------------
Total $ - $27,000
=================================================================
The first mortgage bond improvement fund requirement amounts to 1 percent of
each outstanding series of bonds authenticated under the indenture prior to
January 1 of each year, other than those issued to collateralize pollution
control revenue bond obligations. The requirement may be satisfied by depositing
11-138
NOTES (continued)
Gulf Power Company 1999 Annual Report
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, 1999, 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 1999 and 1998 are as follows:
Net Income
After Dividends
Operating Operating on Preferred
Quarter Ended Revenues Income Stock
- --------------------------------------------------------------------
(in thousands)
March 1999 $134,506 $15,665 $ 4,799
June 1999 166,815 29,253 13,226
September 1999 218,264 54,429 28,582
December 1999 154,514 19,815 7,060
March 1998 $140,950 $19,387 $ 6,853
June 1998 177,130 33,232 13,364
September 1998 199,377 49,837 26,989
December 1998 133,061 19,898 9,315
- --------------------------------------------------------------------
The Company's business is influenced by seasonal weather conditions and the
timing of rate changes, among other factors.
II-139
ELECTED FINANCIAL AND OPERATING DATA 1995-1999
Gulf Power Company 1999 Annual Report
- -------------------------------------------------------------------------------------------------------------------------------
1999 1998 1997 1996 1995
- -------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands) 674,099 $650,518 $625,856 $634,365 $619,077
Net Income after Dividends
on Preferred Stock (in thousands) $53,667 $56,521 $57,610 $57,845 $57,154
Cash Dividends
on Common Stock (in thousands) $61,300 $57,200 $64,600 $58,300 $46,400
Return on Average Common Equity (percent) 12.63 13.20 13.33 13.27 13.27
Total Assets (in thousands) 308,495 $1,267,901 $1,265,612 $1,308,366 $1,341,859
Gross Property Additions (in thousands) $69,798 $69,731 $54,289 $61,386 $63,113
- -------------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity 422,313 $427,652 $428,718 $435,758 $436,242
Preferred stock 4,236 4,236 13,691 65,102 89,602
Company obligated mandatorily
redeemable preferred securities 85,000 85,000 40,000 - -
Long-term debt 367,449 317,341 296,993 331,880 323,376
- -------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 878,998 $834,229 $779,402 $832,740 $849,220
===============================================================================================================================
Capitalization Ratios (percent):
Common stock equity 48.0 51.3 55.0 52.3 51.4
Preferred stock 0.5 0.5 1.8 7.8 10.5
Company obligated mandatorily
redeemable preferred securities 9.7 10.2 5.1 - -
Long-term debt 41.8 38.0 38.1 39.9 38.1
- -------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0 100.0 100.0 100.0
===============================================================================================================================
Security Ratings:
First Mortgage Bonds -
Moody's A1 A1 A1 A1 A1
Standard and Poor's AA- AA- AA- A+ A+
Duff & Phelps AA- AA- AA- AA- A+
Preferred Stock -
Moody's a2 a2 a2 a2 a2
Standard and Poor's A- A A A A
Duff & Phelps A A+ 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 315,240 307,077 300,257 291,196 283,421
Commercial 47,728 46,370 44,589 43,196 41,281
Industrial 267 257 267 278 278
Other 319 268 264 162 134
- -------------------------------------------------------------------------------------------------------------------------------
Total 363,554 353,972 345,377 334,832 325,114
===============================================================================================================================
Employees (year-end): 1,339 1,328 1,328 1,384 1,501
- -------------------------------------------------------------------------------------------------------------------------------
II-140
SELECTED FINANCIAL AND OPERATING DATA 1995-1999 (continued)
Gulf Power Company 1999 Annual Report
- ------------------------------------------------------------------------------------------------------------------------------
1999 1998 1997 1996 1995
- ------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $ 277,311 $276,208 $ 277,609 $ 285,498 $ 276,155
Commercial 165,871 160,960 164,435 164,181 159,260
Industrial 67,404 69,850 77,492 78,994 81,606
Other 2,174 2,100 2,083 2,056 1,993
- ------------------------------------------------------------------------------------------------------------------------------
Total retail 512,760 509,118 521,619 530,729 519,014
Sales for resale - non-affiliates 62,354 61,893 63,697 63,201 60,413
Sales for resale - affiliates 66,110 42,642 16,760 17,762 18,619
- ------------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 641,224 613,653 602,076 611,692 598,046
Other revenues 32,875 36,865 23,780 22,673 21,031
- ------------------------------------------------------------------------------------------------------------------------------
Total $674,099 $650,518 $625,856 $634,365 $619,077
==============================================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 4,471,118 4,437,558 4,119,492 4,159,924 4,014,142
Commercial 3,222,532 3,111,933 2,897,887 2,808,634 2,708,243
Industrial 1,846,237 1,833,575 1,903,050 1,808,086 1,794,754
Other 19,296 18,952 18,101 17,815 17,345
- ------------------------------------------------------------------------------------------------------------------------------
Total retail 9,559,183 9,402,018 8,938,530 8,794,459 8,534,484
Sales for resale - non-affiliates 1,561,972 1,341,990 1,531,179 1,534,097 1,396,474
Sales for resale - affiliates 2,511,983 1,758,150 848,135 709,647 759,341
- ------------------------------------------------------------------------------------------------------------------------------
Total 13,633,138 12,502,158 11,317,844 11,038,203 10,690,299
==============================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 6.20 6.22 6.74 6.86 6.88
Commercial 5.15 5.17 5.67 5.85 5.88
Industrial 3.65 3.81 4.07 4.37 4.55
Total retail 5.36 5.41 5.84 6.03 6.08
Sales for resale 3.15 3.37 3.38 3.61 3.67
Total sales 4.70 4.91 5.32 5.54 5.59
Residential Average Annual
Kilowatt-Hour Use Per Customer 14,318 14,577 13,894 14,457 14,148
Residential Average Annual
Revenue Per Customer $888.01 $907.35 $936.30 $992.17 $973.35
Plant Nameplate Capacity
Ratings (year-end) (megawatts) 2,188 2,188 2,174 2,174 2,174
Maximum Peak-Hour Demand (megawatts):
Winter 2,085 2,040 1,844 2,136 1,732
Summer 2,161 2,146 2,032 1,961 2,040
Annual Load Factor (percent) 55.2 55.3 55.5 51.4 53.0
Plant Availability Fossil-Steam (percent): 87.2 87.6 91.0 91.8 84.0
- ------------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 89.8 89.2 87.1 87.8 86.8
Oil and gas 2.5 2.0 0.4 0.5 0.4
Purchased power -
From non-affiliates 5.9 5.5 3.5 2.7 4.0
From affiliates 1.8 3.3 9.0 9.0 8.8
- ------------------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0 100.0 100.0
==============================================================================================================================
II-141
MISSISSIPPI POWER COMPANY
FINANCIAL SECTION
II-142
MANAGEMENT'S REPORT
Mississippi Power Company 1999 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 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 16, 2000
II-143
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, 1999 and 1998, and the
related statements of income, common stockholder's equity, and cash flows for
each of the three years in the period ended December 31, 1999. 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 auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements (pages II-152 through II-168)
referred to above present fairly, in all material respects, the financial
position of Mississippi Power Company as of December 31, 1999 and 1998, and the
results of its operations and its cash flows for each of the three years in the
period ended December 31, 1999, in conformity with accounting principles
generally accepted in the United States.
/s/ Arthur Andersen LLP
Atlanta, Georgia
February 16, 2000
II-144
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Mississippi Power Company 1999 Annual Report
RESULTS OF OPERATIONS
Earnings
Mississippi Power Company's 1999 net income after dividends on preferred stock
of $54.8 million remained relatively flat when compared to 1998. In 1998,
earnings were $55.1 million, up $1.1 million from the prior year. This change is
primarily attributable to higher retail and wholesale revenues.
Revenues
The following table summarizes the factors impacting operating revenues for the
past three years:
Increase (Decrease)
From Prior Year
----------------------------------
1999 1998 1997
----------------------------------
(in thousands)
Retail --
Change in base
rates (PEP and
ECO Plan) $ 792 $ 335 $ 3,177
Sales growth 7,876 4,787 109
Weather (1,404) 7,091 (1,118)
Fuel cost
recovery
and other 19,603 13,112 948
--------------------------------------------------------------
Total retail 26,867 25,325 3,116
--------------------------------------------------------------
Sales for resale --
Non-affiliates 9,778 16,084 5,464
Affiliates 1,161 8,142 (11,606)
--------------------------------------------------------------
Total sales for
resale 10,939 24,226 (6,142)
Other operating
revenues 67 1,992 2,585
--------------------------------------------------------------
Total operating
revenues $37,873 $51,543 $ (441)
==============================================================
Percent change 6.4% 9.5% (0.1)%
--------------------------------------------------------------
Retail revenues of $469 million in 1999 increased 6.1 percent from 1998.
This increase resulted primarily from continued growth in the service area and a
true-up of the unbilled revenue estimate. Retail revenues for 1998 reflected a
6.1 percent increase over the prior year due to the continued growth in the
service area and the positive impact of weather on energy sales.
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 10.2 percent in 1999 and
9.8 percent in 1998, with the related revenues rising 12.1 percent and 11.3
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 1999 and 1998 primarily due to power
marketing activities. These increases were 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.
Below is a breakdown of kilowatt-hour sales for 1999 and the percent change
for the last three years:
1999 Percent Change
----------- ------------------------------
KWH 1999 1998 1997
(in
millions)
Residential 2,248 - 10.3% (2.0)%
Commercial 2,848 8.5 9.0 4.0
Industrial 4,407 18.2 (6.4) 0.6
Other 40 0.8 - 2.6
Total retail 9,543 10.4 2.0 0.9
Sales for
Resale --
Non-affiliates 3,256 3.1 9.1 6.2
Affiliates 540 (2.2) 15.2 (31.0)
----------
Total 13,339 8.0 4.3 0.2
==================================================================
II-145
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 1999 Annual Report
Total retail sales increased 10.4 percent from 1998 primarily because of
continued growth in the service area, industrial customers' recovery from last
year's hurricane and a true-up of the unbilled revenue estimate. The unbilled
revenue true-up amounted to approximately 3.5 percent of the total increase.
Residential sales decreased slightly in 1999 due to the mild weather in the
spring and winter periods, while commercial and industrial sales increased by
8.5 percent and 18.2 percent, respectively. Increased tourism and strong growth
impacted commercial sales, while industrial sales were impacted by increased
production by several larger industrial customers. Residential and commercial
sales increased in 1998 by 10.3 percent and 9.0 percent, respectively, due to
sales growth and higher than normal temperatures in the summer months. Sales to
industrial customers decreased by 6.4 percent primarily due to a large
industrial customer being shut down because of damages incurred from Hurricane
Georges.
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 $513 million in 1999 reflecting an increase of $33
million or 6.9 percent over the prior year. The increase was due primarily to
higher fuel costs. In 1998, total operating expenses increased by 10.6 percent
over the prior year due primarily to higher fuel expenses, higher maintenance
and higher other operation costs.
Fuel costs are the single largest expense for the Company. Fuel expenses in
1999 increased 10.3 percent due to an increase in generation resulting from a
higher demand for energy. In 1999, expenses related to purchased power from
non-affiliates increased 18.3 percent, while expenses related to purchased power
from affiliates decreased 14.0 percent which, in total, resulted in a slight
increase when compared to 1998. 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.
In 1998, fuel costs increased because of a 3.1 percent increase in
generation and a higher average cost of fuel. The increased generation was due
to higher demand for energy across the Southern electric system. Expenses
related to purchased power from non-affiliates increased, and expenses related
to purchased power from affiliates decreased. Further, the higher demand for
energy resulted in higher purchased power costs from non-affiliates.
The amount and sources of generation and the average cost of fuel per net
kilowatt-hour generated were as follows:
1999 1998 1997
-------------------------
Total generation
(millions of kilowatt
hours) 11,599 10,610 10,289
Sources of generation
(percent) --
Coal 81 80 85
Gas 19 20 15
Average cost of fuel per net
kilowatt-hour generated
(cents) -- 1.65 1.62 1.54
- --------------------------------------------------------------
Other operation expenses increased 13.9 percent in 1999 primarily due to the
amortization of costs associated with the workforce reduction plan and higher
distribution expenses. In 1998, other operation expense increased 7.5 percent
due to continuing expenses related to a new customer service system,
modification of certain information systems for year 2000 readiness, and costs
related to workforce reduction programs. Maintenance expenses decreased 6.6
percent in 1999 due to reduced scheduled maintenance. In 1999, depreciation and
amortization expenses increased 3.7 percent primarily due to growth in plant
investment. Comparisons of taxes other than income taxes for 1999 and 1998 show
increases of 4.2 percent and 4.4 percent, respectively, due to higher municipal
franchise taxes resulting from higher retail revenues. Interest expense
increased due to additional interest related to notes payable and interest
accrued on tax audit issues.
II-146
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 1999 Annual Report
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 utility plant with long economic
lives. Conventional accounting for historical costs does not recognize this
economic loss or 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 weather to energy sales growth to a less regulated
and 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 is also maximizing the utility of invested capital and
minimizing the need for additional capital by refinancing, managing the size of
its fuel stockpile, raising generating plant availability and efficiency, and
aggressively controlling the construction budget.
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 Mississippi Public Service Commission (MPSC)
under cost-based regulatory principles. The Federal Energy Regulatory Commission
(FERC) regulates the Company's wholesale rate schedules, power sales contracts
and transmission facilities.
Operating revenues will be affected by any changes in rates under the
Performance Evaluation Plan (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 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. Compliance costs related to the Clean Air Act could affect
earnings if such costs cannot be recovered. The Company's 1999 ECO Plan was
approved, as filed, in 1999 and resulted in a slight decrease in customer
prices. The Company filed its 2000 ECO Plan in January, 2000 and, if approved as
filed, will result in a slight decrease in customer prices. Refer to Note 3 to
the financial statements under "Litigation and Regulatory Matters" for
additional information. The Clean Air Act and other important environmental
items are discussed later under "Environmental Matters".
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. Currently, the Company is
negotiating with certain of its wholesale customers a change in rates and has
committed to them that any agreement reached would be effective January 1, 2000.
At this time, no agreement has been reached and the ultimate amount of any rate
change cannot now be determined.
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, wholesale transmission access and numerous potential
new energy suppliers, including power marketers and brokers, are driving down
electricity sales for resale rates. 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
II-147
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 1999 Annual Report
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. While 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. 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 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 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.
On December 20, 1999, the FERC issued its final ruling on Regional
Transmission Organizations (RTOs). The order encourages utilities owning
transmission systems to form RTOs on a voluntary basis. To facilitate the
development of RTOs, the FERC will convene regional conferences for utilities,
customers, and other members of the public to discuss the formation of RTOs. In
addition to participating in the regional conferences, utilities owning
transmission systems, including the Company, are required to make a filing by
October 15, 2000. The filing must contain either a proposal for RTO
participation or a description of the efforts made to participate in an RTO, the
reasons for non-participation, any obstacles to participation, and any plans for
further work toward participation. The RTOs that are proposed in the filings
should be operational by December 15, 2001. The Company is evaluating the issue
and formulating its response. The outcome of this matter cannot now be
determined.
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, 1999, 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, 1999, a near-term 100 basis point change in interest rates would not
materially affect the financial statements.
New Accounting Standard
The FASB has issued Statement No. 133, Accounting for Derivative Instruments and
Hedging Activities, which must be adopted by January 1, 2001. 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.
Year 2000
Year 2000 Challenge
The work undertaken by the Company to prepare critical computer systems and
other date sensitive devices to function correctly in the Year 2000 was
successful. There were no material incidents reported and no disruption of
electric service within the service area of the Company. There were no reports
of significant events regarding third parties that impacted revenues or
expenses.
For the Company, original projected total costs for Year 2000 readiness were
approximately $5 million. These costs include labor necessary to identify, test,
and renovate affected devices and systems, and costs for reporting requirements
to state and federal agencies. From its inception through December 31, 1999, the
II-148
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 1999 Annual Report
Year 2000 program costs, recognized primarily as expense, amounted to
approximately $5 million.
FINANCIAL CONDITION
Overview
The principal change in Mississippi Power's financial condition during 1999 was
the addition of approximately $76 million to utility plant. Funding for these
additions and other capital requirements were derived primarily from operations.
The Statements of Cash Flows provide additional details.
Financing Activity
In 1999, the Company sold $9.4 million of pollution control bonds. Additionally,
the Company retired and reissued unsecured debt of $50 million. See the
Statements of Cash Flows for further details.
Composite financing rates have remained relatively flat for the years 1997
through 1999. As of year-end for each year respectively, the composite rates
were as follows:
1999 1998 1997
----------------------------
Composite interest rate on
long-term debt 6.19% 6.14% 6.16%
Composite preferred stock
dividend rate 6.33% 6.33% 6.33%
Composite interest rate on
preferred securities 7.75% 7.75% 7.75%
------------------------------------------------------------
In 1999, the Company signed an Agreement for Lease and a Lease Agreement
with Escatawpa Funding ("Escatawpa"), a limited partnership, that calls for the
Company to design and construct, as agent for Escatawpa, a 1,064 megawatt
natural gas combined cycle facility. It is anticipated that the total project
will cost approximately $406 million, and upon project completion in mid 2001,
the Company intends to lease the facility for an initial term of approximately
10 years. It is anticipated that the annual lease payments will approximate $32
million during the initial term.
Capital Structure
At year-end 1999, the Company's ratio of common equity to total capitalization,
excluding long-term debt due within one year, decreased from 52.1 percent in
1998, to 50.2 percent.
Capital Requirements for Construction
The Company's projected construction expenditures for the next three years total
$199 million ($84 million in 2000, $54 million in 2001, and $61 million in
2002). The major emphasis within the construction program will be on the upgrade
of existing facilities.
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, 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 2002 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
On November 3, 1999, the Environmental Protection Agency (EPA), brought a civil
action in the U.S. District Court against Alabama Power Company, Georgia Power
Company and the system service company. The complaint alleges violations of the
prevention of significant deterioration and new source review provisions of the
Clean Air Act with respect to five coal-fired generating facilities in Alabama
and Georgia. The civil action requests penalties and injunctive relief,
including an order requiring the installation of the best available control
technology at the affected units. The EPA concurrently issued to the integrated
Southeast utilities a notice of violation related to 10 generating facilities,
which includes the five facilities mentioned previously, and the Company's
plants Watson and Greene County. In early 2000, the EPA filed a motion to amend
its complaint to add the violations alleged in its notice of violation, and to
add Gulf Power, Mississippi Power, and Savannah Electric as defendants.
II-149
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 1999 Annual Report
The complaint and notice of violation are similar to those brought against and
issued to several other electric utilities. These complaints and notices of
violation allege that the utilities had failed to secure necessary permits or
install additional pollution equipment when performing maintenance and
construction at coal burning plants constructed or under construction prior to
1978. Southern Company believes that its integrated utilities complied with
applicable laws and the EPA's regulations and interpretations in effect at the
time the work in question took place. The Clean Air Act authorizes civil
penalties of up to $27,500 per day per violation at each generating unit. Prior
to January 30, 1997, the penalty was $25,000 per day. An adverse outcome of this
matter could require substantial capital expenditures that cannot be determined
at this time and possibly require payment of substantial penalties. This could
affect future results of operations, cash flows, and possibly the Company's
financial condition unless such costs can be recovered through regulated rates.
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 other subsidiaries of Southern Company. Specific
reductions in sulfur dioxide and nitrogen oxide emissions from fossil-fired
generating plants were 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 started in 2000, and all fossil-fired generating plants are now
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 currently uses
emission allowances and increased fuel switching. Also, equipment to control
nitrogen oxide emissions was installed on additional system fossil-fired units
as necessary to meet Phase II limits and ozone non-attainment requirements.
Compliance for Phase II and initial ozone non-attainment requirements increased
total estimated construction expenditures by approximately $105 million. 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
provisions. However, there can be no assurance that all Clean Air Act costs will
be recovered.
In July 1997, the EPA revised the national ambient air quality standards for
ozone and particulate matter. This revision made the standards significantly
more stringent. In September 1998, the EPA issued the final regional nitrogen
oxide rules to the states for implementation. 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.
Mississippi is one of those new 15 states. The EPA's July 1997 standards and the
September 1998 rule 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 any new standards will
depend on the development and implementation of applicable regulations.
II-150
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 1999 Annual Report
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 was substantially remediated in 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 or other environmental concerns. The likelihood
or outcome of such potential lawsuits cannot be determined at this time.
Sources of Capital
To meet short-term cash needs and contingencies, the Company had at December 31,
1999 approximately $173 thousand of cash and cash equivalents and approximately
$104.3 million of unused committed credit agreements. The Company had $57.5
million of short term notes payable outstanding at year end 1999.
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 1998 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 high
enough to permit, at present interest rate levels, any foreseeable security
sales. The amount of securities which the Company will be permitted to issue in
the future will depend upon market conditions and other factors prevailing at
that time.
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-151
STATEMENTS OF INCOME
For the Years Ended December 31, 1999, 1998, and 1997
Mississippi Power Company 1999 Annual Report
- ----------------------------------------------------------------------------------------------------------------------
1999 1998 1997
- ----------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Revenues:
Retail sales $469,434 $442,567 $417,242
Sales for resale --
Non-affiliates 131,004 121,225 105,141
Affiliates 19,446 18,285 10,143
Other revenues 13,120 13,054 11,062
- ----------------------------------------------------------------------------------------------------------------------
Total operating revenues 633,004 595,131 543,588
- ----------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
Fuel 172,686 156,539 142,059
Purchased power --
Non-affiliates 40,080 33,872 14,536
Affiliates 31,007 36,037 37,794
Other 125,291 109,993 102,365
Maintenance 47,085 50,404 47,302
Depreciation and amortization 49,206 47,450 45,574
Taxes other than income taxes 47,893 45,965 44,034
- ----------------------------------------------------------------------------------------------------------------------
Total operating expenses 513,248 480,260 433,664
- ----------------------------------------------------------------------------------------------------------------------
Operating Income 119,756 114,871 109,924
Other Income:
Interest income 273 947 857
Other, net 1,675 2,498 2,368
- ----------------------------------------------------------------------------------------------------------------------
Earnings Before Interest and Income Taxes 121,704 118,316 113,149
- ----------------------------------------------------------------------------------------------------------------------
Interest Charges and Other:
Interest on long-term debt 20,455 20,567 19,856
Interest on notes payable 2,750 943 96
Amortization of debt discount, premium and expense, net 1,432 1,446 1,577
Other interest charges 3,332 790 574
Distributions on preferred securities of subsidiary 2,796 2,796 2,369
- ----------------------------------------------------------------------------------------------------------------------
Total interest charges and other, net 30,765 26,542 24,472
- ----------------------------------------------------------------------------------------------------------------------
Earnings Before Income Taxes 90,939 91,774 88,677
Income taxes 34,117 34,664 31,380
- ----------------------------------------------------------------------------------------------------------------------
Net Income 56,822 57,110 57,297
Dividends on Preferred Stock 2,013 2,005 3,287
- ----------------------------------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred Stock $ 54,809 $ 55,105 $ 54,010
======================================================================================================================
The accompanying notes are an integral part of these statements.
II-152
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1999, 1998, and 1997
Mississippi Power Company 1999 Annual Report
- -------------------------------------------------------------------------------------------------------------------------------
1999 1998 1997
- -------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Activities:
Net income $ 56,822 $ 57,110 $ 57,297
Adjustments to reconcile net income
to net cash provided from operating activities --
Depreciation and amortization 53,427 51,517 49,661
Deferred income taxes and investment tax credits, net (4,143) 11,620 (1,809)
Other, net 5,531 (12,175) 3,206
Changes in certain current assets and liabilities --
Receivables, net (39,304) (5,486) (8,583)
Fossil fuel stock (9,379) (5,767) 1,517
Materials and supplies (1,903) 717 1,631
Accounts payable 1,391 (389) 8,357
Other 14,206 (4,061) 3,980
- -------------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities 76,648 93,086 115,257
- -------------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (75,888) (68,231) (55,375)
Other 1,009 (324) (489)
- -------------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities (74,879) (68,555) (55,864)
- -------------------------------------------------------------------------------------------------------------------------------
Financing Activities:
Increase (decrease) in notes payable, net 44,500 13,000 -
Proceeds --
Other long-term debt 59,400 103,520 -
Preferred securities - - 35,000
Preferred stock - - -
Capital contributions from parent company 2,028 85 -
Retirements --
First mortgage bonds - (75,000) -
Other long-term debt (50,456) (13,020) (10)
Preferred stock - (87) (42,518)
Payment of preferred stock dividends (2,013) (2,005) (3,287)
Payment of common stock dividends (56,100) (51,700) (49,400)
Other (282) (2,429) (1,804)
- -------------------------------------------------------------------------------------------------------------------------------
Net cash used for financing activities (2,923) (27,636) (62,019)
- -------------------------------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents (1,154) (3,105) (2,626)
Cash and Cash Equivalents at Beginning of Period 1,327 4,432 7,058
- -------------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ 173 $ 1,327 $ 4,432
===============================================================================================================================
Supplemental Cash Flow Information:
Cash paid during the period for --
Interest (net of amount capitalized) $25,486 $26,133 $22,297
Income taxes (net of refunds) 39,729 26,847 33,450
- -------------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
II-153
BALANCE SHEETS
At December 31, 1999 and 1998
Mississippi Power Company 1999 Annual Report
- ---------------------------------------------------------------------------------------------------------------------
Assets 1999 1998
- ---------------------------------------------------------------------------------------------------------------------
(in thousands)
Current Assets:
Cash and cash equivalents $ 173 $ 1,327
Receivables --
Customer accounts receivable 61,274 37,871
Other accounts and notes receivable 23,490 12,495
Affiliated companies 16,097 10,946
Accumulated provision for uncollectible accounts (697) (621)
Fossil fuel stock, at average cost 25,797 16,418
Materials and supplies, at average cost 20,638 18,735
Other 10,013 10,616
- ---------------------------------------------------------------------------------------------------------------------
Total current assets 156,785 107,787
- ---------------------------------------------------------------------------------------------------------------------
Property, Plant, and Equipment:
In service 1,601,399 1,553,112
Less accumulated provision for depreciation 626,841 583,957
- ---------------------------------------------------------------------------------------------------------------------
974,558 969,155
Construction work in progress 68,721 51,517
- ---------------------------------------------------------------------------------------------------------------------
Total property, plant, and equipment 1,043,279 1,020,672
- ---------------------------------------------------------------------------------------------------------------------
Other Property and Investments 1,389 979
- ---------------------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets:
Deferred charges related to income taxes 21,557 22,697
Prepaid pension costs 2,488 -
Debt expense, being amortized 4,355 4,409
Premium on reacquired debt, being amortized 8,154 9,304
Workforce reduction plan - 12,748
Other 13,129 11,009
- ---------------------------------------------------------------------------------------------------------------------
Total deferred charges and other assets 49,683 60,167
- ---------------------------------------------------------------------------------------------------------------------
Total Assets $1,251,136 $1,189,605
=====================================================================================================================
The accompanying notes are an integral part of these balance sheets.
II-154
BALANCE SHEETS
At December 31, 1999 and 1998
Mississippi Power Company 1999 Annual Report
- --------------------------------------------------------------------------------------------------------------------
Liabilities and Stockholder's Equity 1999 1998
- --------------------------------------------------------------------------------------------------------------------
(in thousands)
Current Liabilities:
Securities due within one year $ 30,020 $ 50,020
Notes payable 57,500 13,000
Accounts payable --
Affiliated 17,002 8,788
Other 43,105 47,113
Customer deposits 3,749 3,272
Taxes accrued --
Income taxes 6,865 1,124
Other 35,534 31,379
Interest accrued 6,733 2,955
Vacation pay accrued 5,218 4,717
Other 7,497 11,448
- --------------------------------------------------------------------------------------------------------------------
Total current liabilities 213,223 173,816
- --------------------------------------------------------------------------------------------------------------------
Long-term debt (See accompanying statements) 321,802 292,744
- --------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 139,564 143,852
Deferred credits related to income taxes 34,765 37,277
Accumulated deferred investment tax credits 24,695 25,913
Employee benefits provisions 34,268 34,148
Workforce reduction plan 11,272 13,051
Other 12,770 10,764
- --------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 257,334 265,005
- --------------------------------------------------------------------------------------------------------------------
Company obligated mandatorily redeemable preferred
securities of subsidiary trust holding company junior
subordinated notes (See accompanying statements) 35,000 35,000
- --------------------------------------------------------------------------------------------------------------------
Preferred stock (See accompanying statements) 31,809 31,809
- --------------------------------------------------------------------------------------------------------------------
Common stockholder's equity (See accompanying statements) 391,968 391,231
- --------------------------------------------------------------------------------------------------------------------
Total Liabilities and Stockholder's Equity $1,251,136 $1,189,605
====================================================================================================================
The accompanying notes are an integral part of these balance sheets.
II-155
STATEMENTS OF CAPITALIZATION
At December 31, 1999 and 1998
Mississippi Power Company 1999 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------
1999 1998 1999 1998
- -----------------------------------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
Long-Term Debt:
First mortgage bonds --
Maturity Interest Rates
-------- --------------
June 1, 2023 7.45% $ 35,000 $ 35,000
March 1, 2004 6.60% 35,000 35,000
December 1, 2025 6.875% 30,000 30,000
- -----------------------------------------------------------------------------------------------------------------------------
Total first mortgage bonds 100,000 100,000
- -----------------------------------------------------------------------------------------------------------------------------
Long-term notes payable --
6.05% due May 1, 2003 35,000 35,000
6.75% due June 30, 2038 54,564 55,000
Adjustable rates (6.61% to 6.78% at 1/1/00)
due 1999-2002 80,000 80,000
- -----------------------------------------------------------------------------------------------------------------------------
Total long-term notes payable 169,564 170,000
- -----------------------------------------------------------------------------------------------------------------------------
Other long-term debt --
Pollution control revenue bonds --
Collateralized:
5.65% to 5.80% due 2007-2023 26,785 26,805
Variable rates (3.90% at 1/1/00)
due 2020-2025 10,600 33,900
Non-collateralized:
Variable rates (3.90% to 4.00% at 1/1/00)
due 2020-2028 46,220 13,520
- -----------------------------------------------------------------------------------------------------------------------------
Total other long-term debt 83,605 74,225
- -----------------------------------------------------------------------------------------------------------------------------
Unamortized debt premium (discount), net (1,347) (1,461)
- -----------------------------------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
requirement -- $21.9 million) 351,822 342,764
Less amount due within one year 30,020 50,020
- -----------------------------------------------------------------------------------------------------------------------------
Long-term debt excluding amount due within one year $321,802 $292,744 41.2% 39.0%
- -----------------------------------------------------------------------------------------------------------------------------
II-156
STATEMENTS OF CAPITALIZATION (continued)
At December 31, 1999 and 1998
Mississippi Power Company 1999 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------
1999 1998 1999 1998
- -----------------------------------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
Company Obligated Mandatorily
Redeemable Preferred Securities:
$25 liquidation value --
7.75% $ 35,000 $ 35,000
- -----------------------------------------------------------------------------------------------------------------------------
Total (annual distribution requirement -- $2.7 million) 35,000 35,000 4.5 4.7
- -----------------------------------------------------------------------------------------------------------------------------
Cumulative Preferred Stock:
$100 par value
4.40% to 7.00% 31,809 31,809
- -----------------------------------------------------------------------------------------------------------------------------
Total (annual dividend requirement -- $2.0 million) 31,809 31,809
Less amount due within one year - -
- -----------------------------------------------------------------------------------------------------------------------------
Total excluding amount due within one year 31,809 31,809 4.1 4.2
- -----------------------------------------------------------------------------------------------------------------------------
Common Stockholder's Equity:
Common stock, without par value --
Authorized - 1,130,000 shares
Outstanding - 1,121,000 shares in 1999 and 1998 37,691 37,691
Paid-in capital 181,502 179,474
Premium on preferred stock 326 326
Retained earnings 172,449 173,740
- -----------------------------------------------------------------------------------------------------------------------------
Total common stockholder's equity 391,968 391,231 50.2 52.1
- -----------------------------------------------------------------------------------------------------------------------------
Total Capitalization $780,579 $750,784 100.0% 100.0%
=============================================================================================================================
The accompanying notes are an integral part of these statements.
II-157
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
For the Years Ended December 31, 1999, 1998, and 1997
Mississippi Power Company 1999 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------
Premium on
Common Paid-In Preferred Retained
Stock Capital Stock Earnings Total
- ----------------------------------------------------------------------------------------------------------------------------
(in thousands)
Balance at January 1, 1997 $37,691 $179,389 $372 $166,282 $383,734
Net income after dividends on preferred stock - - - 54,010 54,010
Cash dividends on common stock - - - (49,400) (49,400)
Other - - (45) (475) (520)
- ----------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1997 37,691 179,389 327 170,417 387,824
Net income after dividends on preferred stock - - - 55,105 55,105
Capital contributions from parent company - 85 - - 85
Cash dividends on common stock - - - (51,700) (51,700)
Other - - (1) (82) (83)
- ----------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1998 37,691 179,474 326 173,740 391,231
Net income after dividends on preferred stock - - - 54,809 54,809
Capital contributions from parent company - 2,028 - - 2,028
Cash dividends on common stock - - - (56,100) (56,100)
- ----------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1999 $37,691 $181,502 $326 $172,449 $391,968
============================================================================================================================
The accompanying notes are an integral part of these statements.
II-158
NOTES TO FINANCIAL STATEMENTS
Mississippi Power Company 1999 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 integrated Southeast utilities, Southern
Company Services (SCS), Southern Communications Services (Southern LINC),
Southern Energy, Inc. (Southern Energy), Southern Nuclear Operating Company
(Southern Nuclear), Southern Energy Solutions, and other direct and indirect
subsidiaries. The integrated Southeast utilities -- 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 integrated Southeast utilitis related
to 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 the subsidiary companies. Southern LINC provides digital wireless
communications services to the integrated Southeast utilities 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. Southern Nuclear provides services to Southern Company's nuclear power
plants. Southern Energy acquires, develops, builds, owns, and operates power
production and delivery facilities and provides a broad range of energy-related
servies to utilities and industrial companies in selected countries around the
world. Southern Energy businesses include independent power projects, integrated
utilities, a distribution company, and energy trading and marketing businesses
outside the southeastern United States.
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.
Prior years' data presented in the financial statements have been
reclassified to conform with the current year presentation.
Related-Party Transactions
The Company has an agreement with SCS under which the following services are
rendered to the Company at cost: general and design engineering, purchasing,
accounting and statistical, finance and treasury, tax, information resources,
marketing, auditing, insurance and pension, human resources, systems and
procedures, and other services with respect to business and operations and power
pool operations. Costs for these services amounted to $45.5 million, $43.9
million, and $34.5 million during 1999, 1998, and 1997, respectively.
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 at December 31 relate to:
1999 1998
-------------------------
(in thousands)
Deferred income tax charges $ 21,557 $ 22,697
Vacation pay 5,218 4,717
Workforce reduction plan of
1997 - 12,748
Premium on reacquired debt 8,154 9,304
Deferred environmental costs 323 1,500
Property damage reserve (3,082) (910)
Deferred income tax credits (34,765) (37,277)
Other, net (672) (2,538)
- ----------------------------------------------------------------
Total $ (3,267) $ 10,241
================================================================
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
II-159
NOTES (continued)
Mississippi Power Company 1999 Annual Report
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 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 Mississippi, and to wholesale customers in the Southeast.
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 plant in service is provided primarily by
using composite straight-line rates which approximated 3.3 percent in 1999.
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.
Property, Plant and Equipment
Property, plant, and equipment 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, 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 capitalized.
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, 1999 $353 $334
At December 31, 1998 $343 $348
Capital trust preferred
securities:
At December 31, 1999 $35 $30
At December 31, 1998 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.
II-160
NOTES (continued)
Mississippi Power Company 1999 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 used
or installed.
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
accrues for the cost of such damage by charging expense and crediting an
accumulated provision. The cost of repairing damage resulting from such events
that individually exceed $50 thousand is charged to the accumulated provision.
Effective November 1999, an order from the MPSC increased the maximum Property
Damage Reserve from $18 million to $23 million and allows an annual accrual of
up to $4.6 million. In 1999, the Company provided for such costs by charges to
income of $4.4 million, which is an increase of $2.9 million when compared to
the $1.5 million allowed in both 1998 and 1997. As of December 31, 1999, the
accumulated provision amounted to $3.1 million.
2. RETIREMENT BENEFITS
Mississippi Power has a defined benefit, trusteed, pension plan that covers
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 required by the MPSC. The measurement date for plan
assets and obligations 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
----------------------------
1999 1998
- -----------------------------------------------------------------
(in thousands)
Balance at beginning of year $142,807 $132,131
Service cost 4,415 3,848
Interest cost 9,377 9,613
Benefits paid (8,050) (7,845)
Actuarial (gain) loss and
employee transfers (8,619) 5,060
- -----------------------------------------------------------------
Balance at end of year $139,930 $142,807
=================================================================
Plan Assets
----------------------------
1999 1998
- -----------------------------------------------------------------
(in thousands)
Balance at beginning of year $198,100 $207,457
Actual return on plan assets 33,216 1,252
Benefits paid (8,050) (7,845)
Employee transfers (1,779) (2,764)
- -----------------------------------------------------------------
Balance at end of year $221,487 $198,100
=================================================================
The accrued pension costs recognized in the Balance Sheets were as follows:
1999 1998
- --------------------------------------------------------------------
(in thousands)
Funded status $ 81,557 $ 55,293
Unrecognized transition obligation (3,814) (4,359)
Unrecognized prior service cost 4,991 5,405
Unrecognized net gain (80,246) (56,590)
- --------------------------------------------------------------------
Prepaid asset (liability) recognized
in the Balance Sheets $2,488 $ (251)
====================================================================
II-161
NOTES (continued)
Mississippi Power Company 1999 Annual Report
Components of the plans' net periodic cost were as follows:
1999 1998 1997
- ------------------------------------------------------------------
(in thousands)
Service cost $ 4,415 $ 3,848 $ 4,015
Interest cost 9,377 9,613 9,407
Expected return on
plan assets (14,681) (13,817) (12,805)
Recognized net gain (1,721) (1,956) (1,729)
Net amortization (131) (131) (119)
- ------------------------------------------------------------------
Net pension income $(2,741) $ (2,443) $ (1,231)
==================================================================
Postretirement Benefits
Changes during the year in the accumulated benefit obligations and in the fair
value of plan assets were as follows:
Accumulated
Benefit Obligations
----------------------------
1999 1998
- -----------------------------------------------------------------
(in thousands)
Balance at beginning of year $47,260 $43,417
Service cost 982 806
Interest cost 3,105 3,162
Benefits paid (2,256) (2,302)
Actuarial loss and
employee transfers (3,701) 2,177
- -----------------------------------------------------------------
Balance at end of year $45,390 $47,260
=================================================================
Plan Assets
----------------------------
1999 1998
- -----------------------------------------------------------------
(in thousands)
Balance at beginning of year $12,779 $12,189
Actual return on plan assets 1,818 176
Employer contributions 2,657 2,716
Benefits paid (2,256) (2,302)
- -----------------------------------------------------------------
Balance at end of year $14,998 $12,779
=================================================================
The accrued postretirement costs recognized in the Balance Sheets were as
follows:
1999 1998
- --------------------------------------------------------------------
(in thousands)
Funded status $(30,392) $(34,481)
Unrecognized transition obligation 4,621 4,967
Unrecognized net loss (gain) (3,406) 1,010
Fourth quarter contributions 931 577
- --------------------------------------------------------------------
Accrued liability recognized in the
Balance Sheets $(28,246) $(27,927)
====================================================================
Components of the plans' net periodic cost were as follows:
1999 1998 1997
- ------------------------------------------------------------------
(in thousands)
Service cost $ 981 $ 806 $ 867
Interest cost 3,105 3,162 2,922
Expected return on
plan assets (1,100) (989) (815)
Recognized net (gain) loss - - (7)
Net amortization 346 346 362
- ------------------------------------------------------------------
Net postretirement cost $3,332 $3,325 $3,329
==================================================================
The weighted average rates assumed in the actuarial calculations for both
the pension plans and postretirement benefits were:
1999 1998
---------------------------------------------------------------
Discount 7.50% 6.75%
Annual salary increase 5.00 4.25
Long-term return on plan assets 8.50 8.50
---------------------------------------------------------------
II-162
NOTES (continued)
Mississippi Power Company 1999 Annual Report
An additional assumption used in measuring the accumulated postretirement
benefit obligation was a weighted average medical care cost trend rate of 7.74
percent for 1999, decreasing gradually to 5.50 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,
1999 as follows:
1 Percent 1 Percent
Increase Decrease
- -----------------------------------------------------------------
(in thousands)
Benefit obligation $2,983 $(2,551)
Service and interest costs 258 (219)
- -----------------------------------------------------------------
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 was 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. At December 31, 1999, the
Company has completely amortized the $18.2 million.
3. LITIGATION AND REGULATORY MATTERS
Environmental Litigation
On November 3, 1999, the Environmental Protection Agency (EPA), brought a civil
action in the U.S. District Court against Alabama Power Company, Georgia Power
Company and the system service company. The complaint alleges violations of the
prevention of significant deterioration and new source review provisions of the
Clean Air Act with respect to five coal-fired generating facilities in Alabama
and Georgia. The civil action requests penalties and injunctive relief,
including an order requiring the installation of the best available control
technology at the affected units. The EPA concurrently issued to the integrated
Southeast utilities a notice of violation related to 10 generating facilities,
which includes the five facilities mentioned previously, and the Company's
plants Watson and Greene County. In early 2000, the EPA filed a motion to amend
its complaint to add the violations alleged in its notice of violation, and to
add Gulf Power, Mississippi Power, and Savannah Electric as defendants. The
complaint and notice of violation are similar to those brought against and
issued to several other electric utilities. These complaints and notices of
violation allege that the utilities had failed to secure necessary permits or
install additional pollution equipment when performing maintenance and
construction at coal burning plants constructed or under construction prior to
1978. Southern Company believes that its integrated utilities complied with
applicable laws and the EPA's regulations and interpretations in effect at the
time the work in question took place. The Clean Air Act authorizes civil
penalties of up to $27,500 per day per violation at each generating unit. Prior
to January 30, 1997, the penalty was $25,000 per day. An adverse outcome of this
matter could require substantial capital expenditures that cannot be determined
at this time and possibly require payment of substantial penalties. This could
affect future results of operations, cash flows, and possibly the Company's
financial condition unless such costs can be recovered through regulated rates.
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 Power'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 1999, 1998 or 1997.
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
II-163
NOTES (continued)
Mississippi Power Company 1999 Annual Report
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. In 1998 and 1999,
the Company's ECO filing resulted in a small decrease in customer prices in each
year. The Company filed its 2000 ECO Plan in January, and if approved as filed,
will result in a small decrease in customer prices.
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 has been investigated and substantially remediated. The remedial plan
was approved by the Mississippi Department of Environmental Quality. Remediation
of this site began in 1999 and is scheduled to be completed in early 2000. The
Company expects the total remediation costs to be approximately $2.0 million,
with approximately $1.5 million recovered from other parties and the balance
through the ECO Plan. The Company recovers such costs under the ECO Plan as they
are incurred, as provided for in the Company's 1995 ECO Order. As of December
31, 1999, the balance in the liability and regulatory asset accounts was $0.3
million.
Approval for New Capacity
In January 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 5, Financing
and Commitments). 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 $84 million in 2000, $54 million in 2001,
and $61 million in 2002. 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, and the upgrading of generating plants.
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 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.
In 1999, the Company signed an Agreement for Lease and a Lease Agreement
with Escatawpa Funding ("Escatawpa"), a limited partnership, that calls for the
Company to design and construct, as agent for Escatawpa, a 1,064 megawatt
natural gas combined cycle facility. It is anticipated that the total project
will cost approximately $406 million, and upon project completion in mid 2001,
the Company intends to lease the facility for an initial term of approximately
10 years. It is anticipated that the annual lease payments will approximate $32
million during the initial term.
II-164
NOTES (continued)
Mississippi Power Company 1999 Annual Report
Bank Credit Arrangements
At December 31, 1999, Mississippi Power had total committed credit agreements
with banks for $104.3 million. At year-end 1999, the unused portion of these
committed credit agreements was $104.3 million. These credit agreements expire
at various dates 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 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, 1999, the Company had
$57.5 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 Corp.) 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 1999 use fees collected
under this agreement, net of related expenses, amounted to approximately $3
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
stock, was $2.8 million in 1999, $2.8 million in 1998, and $2.0 million in
1997. The Company's annual lease payments for 2000 through 2004 will average
approximately $1.8 million and after 2004, lease payments total in aggregate
approximately $14.4 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, 1999, were as follows:
Year Fuel
- ----------- ----------
(in millions)
2000 $147
2001 121
2002 124
2003 125
2004 9
2005 - 2026 115
- ---------------------------------------------------
Total commitments $641
- ---------------------------------------------------
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. For the
years ended 1999, 1998 and 1997 Mississippi Power exercised its options to
purchase 250 megawatts, 300 megawatts and 250 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. In
1999, Mississippi Power exercised its option to purchase 400 megawatts of summer
peaking capacity for the year 2000.
II-165
NOTES (continued)
Mississippi Power Company 1999 Annual Report
6. JOINT OWNERSHIP AGREEMENTS
Mississippi Power and Alabama Power own as tenants in common Units 1 and 2 at
Plant Greene County located in Alabama; and Mississippi Power and Gulf Power
own as tenants in common Units 1 and 2 at Plant Daniel located in Mississippi.
At December 31, 1999, 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% $61,050 $29,636
Daniel
Units 1 and 2 1,000 50% $225,761 $103,213
------------------------------------------------------------------
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 utility 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 Company's capacity
revenues under these agreements were not material during the periods reported.
8. INCOME TAXES
At December 31, 1999, the tax-related regulatory assets and liabilities were $22
million and $35 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:
1999 1998 1997
----------------------------------
(in thousands)
Total provision for
income taxes
Federal --
Current $33,379 $20,500 $27,651
Deferred --current year 3,747 7,007 8,171
--reversal of
prior years (7,720) 2,435 (9,236)
-----------------------------------------------------------------
29,406 29,942 26,586
-----------------------------------------------------------------
State --
Current 4,881 2,544 5,537
Deferred --current year 738 1,568 1,756
--reversal of
prior years (908) 610 (2,499)
-----------------------------------------------------------------
4,711 4,722 4,794
-----------------------------------------------------------------
Total 34,117 34,664 31,380
=================================================================
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:
1999 1998
-----------------------------
(in thousands)
Deferred tax liabilities:
Accelerated depreciation $154,698 $153,768
Basis differences 8,967 9,642
Other 23,108 26,038
---------------------------------------------------------------
Total 186,773 189,448
---------------------------------------------------------------
Deferred tax assets:
Other property
basis differences 21,003 22,391
Pension and
other benefits 9,608 9,441
Property insurance 3,419 1,526
Unbilled fuel 4,846 2,080
Other 11,071 14,406
---------------------------------------------------------------
Total 49,947 49,844
---------------------------------------------------------------
Net deferred tax
liabilities 136,826 139,604
Portion included in
current assets, net 2,738 4,248
---------------------------------------------------------------
Accumulated deferred
income taxes in the
Balance Sheets $139,564 $143,852
===============================================================
II-166
NOTES (continued)
Mississippi Power Company 1999 Annual Report
Deferred investment tax credits are amortized over the lives 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 1999, 1998, and 1997. At December 31, 1999, 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:
1999 1998 1997
----------------------------------
Federal statutory rate 35.00% 35.00% 35.00%
State income tax, net of
federal deduction 3.37 3.34 3.51
Non-deductible book
depreciation .77 .47 .47
Other (1.62) (1.04) (3.60)
------------------------------------------------------------------
Effective income tax rate 37.52% 37.77% 35.38%
==================================================================
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.
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 the Company of the Trusts' payment obligations 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:
1999 1998
-------------------
(in thousands)
Bond improvement fund requirement $1,000 $1,000
Less: Portion to be satisfied by
certifying property additions 1,000 1,000
---------------------------------------------------------------
Cash sinking fund requirement - -
Redemptions of first mortgage bonds - -
Current portion of other long-term debt 30,000 50,000
Pollution control bond cash
sinking fund requirements 20 20
---------------------------------------------------------------
Total $30,020 $50,020
===============================================================
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, 1999,
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.
II-167
NOTES (continued)
Mississippi Power Company 1999 Annual Report
12. QUARTERLY FINANCIAL DATA (UNAUDITED)
Summarized quarterly financial data for 1999 and 1998 are as follows:
Net Income
After Dividends
Operating Operating On Preferred
Quarter Ended Revenues Income Stock
- --------------------------------------------------------------------
(in thousands)
March 1999 $122,435 $18,122 $7,193
June 1999 158,590 31,289 14,953
September 1999 201,594 51,609 27,313
December 1999 150,385 18,736 5,350
March 1998 $122,156 $20,299 $8,388
June 1998 156,612 30,126 13,713
September 1998 191,699 50,948 28,309
December 1998 124,664 13,498 4,696
- --------------------------------------------------------------------
Mississippi Power's business is influenced by seasonal weather conditions
and the timing of rate changes.
II-168
SELECTED FINANCIAL AND OPERATING DATA 1995-1999
Mississippi Power Company 1999 Annual Report
- ---------------------------------------------------------------------------------------------------------------------------------
1999 1998 1997 1996 1995
- ---------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands)* $633,004 $595,131 $543,588 $544,029 $516,553
Net Income after Dividends
on Preferred Stock (in thousands) $54,809 $55,105 $54,010 $52,723 $52,531
Cash Dividends
on Common Stock (in thousands) $56,100 $51,700 $49,400 $43,900 $39,400
Return on Average Common Equity (percent) 14.00 14.15 14.00 13.90 14.26
Total Assets (in thousands) $1,251,136 $1,189,605 $1,166,829 $1,142,327 $1,148,953
Gross Property Additions (in thousands) $75,888 $68,231 $55,375 $61,314 $67,570
- ---------------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $391,968 $391,231 $387,824 $383,734 $374,884
Preferred stock 31,809 31,809 31,896 74,414 74,414
Company obligated mandatorily
redeemable preferred securities 35,000 35,000 35,000 - -
Long-term debt 321,802 292,744 291,665 326,379 288,820
- ---------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $780,579 $750,784 $746,385 $784,527 $738,118
=================================================================================================================================
Capitalization Ratios (percent):
Common stock equity 50.2 52.1 52.0 48.9 50.8
Preferred stock 4.1 4.2 4.3 9.5 10.1
Company obligated mandatorily
redeemable preferred securities 4.5 4.7 4.7 - -
Long-term debt 41.2 39.0 39.0 41.6 39.1
- ---------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0 100.0 100.0 100.0
=================================================================================================================================
Security Ratings:
First Mortgage Bonds -
Moody's Aa3 Aa3 Aa3 Aa3 Aa3
Standard and Poor's AA- AA- AA- A+ A+
Duff & Phelps AA- AA- AA- AA- AA-
Preferred Stock -
Moody's a1 a1 a1 a1 a1
Standard and Poor's A- A A A A
Duff & Phelps A+ A+ A+ A+ A+
=================================================================================================================================
Customers (year-end):
Residential 157,592 156,530 156,650 154,630 154,014
Commercial 31,837 31,319 31,667 30,366 29,903
Industrial 546 587 642 639 642
Other 202 200 200 200 194
- ---------------------------------------------------------------------------------------------------------------------------------
Total 190,177 188,636 189,159 185,835 184,753
=================================================================================================================================
Employees (year-end): 1,328 1,230 1,245 1,363 1,421
- ---------------------------------------------------------------------------------------------------------------------------------
* 1999 data includes the true-up of the unbilled revenue estimates.
II-169
SELECTED FINANCIAL AND OPERATING DATA 1995-1999 (continued)
Mississippi Power Company 1999 Annual Report
- --------------------------------------------------------------------------------------------------------------------------------
1999 1998 1997 1996 1995
- --------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands)*:
Residential $ 159,945 $157,642 $ 138,608 $ 137,055 $ 134,286
Commercial 153,936 145,677 134,208 131,734 131,034
Industrial 151,244 135,039 140,233 141,324 140,947
Other 4,309 4,209 4,193 4,013 3,914
- --------------------------------------------------------------------------------------------------------------------------------
Total retail 469,434 442,567 417,242 414,126 410,181
Sales for resale - non-affiliates 131,004 121,225 105,141 99,596 91,820
Sales for resale - affiliates 19,446 18,285 10,143 21,830 7,691
- --------------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 619,884 582,077 532,526 535,552 509,692
Other revenues 13,120 13,054 11,062 8,477 6,861
- --------------------------------------------------------------------------------------------------------------------------------
Total $633,004 $595,131 $543,588 $544,029 $516,553
================================================================================================================================
Kilowatt-Hour Sales (in thousands)*:
Residential 2,248,255 2,248,915 2,039,042 2,079,611 2,040,608
Commercial 2,847,342 2,623,276 2,407,520 2,315,860 2,242,163
Industrial 4,407,445 3,729,166 3,981,875 3,960,243 3,813,456
Other 40,091 39,772 40,508 39,297 38,559
- --------------------------------------------------------------------------------------------------------------------------------
Total retail 9,543,133 8,641,129 8,468,945 8,395,011 8,134,786
Sales for resale - non-affiliates 3,256,175 3,157,837 2,895,182 2,726,993 2,493,519
Sales for resale - affiliates 539,939 552,142 478,884 693,510 243,554
- --------------------------------------------------------------------------------------------------------------------------------
Total 13,339,247 12,351,108 11,843,011 11,815,514 10,871,859
================================================================================================================================
Average Revenue Per Kilowatt-Hour (cents)*:
Residential 7.11 7.01 6.80 6.59 6.58
Commercial 5.41 5.55 5.57 5.69 5.84
Industrial 3.43 3.62 3.52 3.57 3.70
Total retail 4.92 5.12 4.93 4.93 5.04
Sales for resale 3.96 3.76 3.42 3.55 3.84
Total sales 4.65 4.71 4.50 4.53 4.69
Residential Average Annual
Kilowatt-Hour Use Per Customer * 14,301 14,376 13,132 13,469 13,307
Residential Average Annual
Revenue Per Customer * $1,017.42 $1,007.68 $892.68 $887.66 $875.69
Plant Nameplate Capacity
Ratings (year-end) (megawatts) 2,086 2,086 2,086 2,086 2,086
Maximum Peak-Hour Demand (megawatts):
Winter 2,125 1,740 1,922 2,030 1,637
Summer 2,439 2,339 2,209 2,117 2,095
Annual Load Factor (percent) 59.6 58.0 59.1 60.7 60.0
Plant Availability Fossil-Steam (percent): 91.0 90.0 92.4 91.8 92.1
- --------------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 69.4 66.5 70.5 70.4 58.0
Oil and gas 15.9 14.5 12.5 12.0 15.2
Purchased power -
From non-affiliates 6.2 8.0 3.0 6.5 2.4
From affiliates 8.5 11.0 14.0 11.1 24.4
- --------------------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0 100.0 100.0
================================================================================================================================
* 1999 data includes the true-up of the unbilled revenue estimates.
II-170
SAVANNAH ELECTRIC AND POWER COMPANY
FINANCIAL SECTION
II-171
MANAGEMENT'S REPORT
Savannah Electric and Power Company 1999 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 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 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 16, 2000
II-172
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, 1999 and 1998, and the
related statements of income, common stockholder's equity, and cash flows for
each of the three years in the period ended December 31, 1999. 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 auditing standards generally
accepted in the United States. 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-181 through II-194)
referred to above present fairly, in all material respects, the financial
position of Savannah Electric and Power Company as of December 31, 1999 and
1998, and the results of its operations and its cash flows for each of the three
years in the period ended December 31, 1999, in conformity with accounting
principles generally accepted in the United States.
/s/Arthur Andersen LLP
Atlanta, Georgia
February 16, 2000
II-173
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Savannah Electric and Power Company 1999 Annual Report
RESULTS OF OPERATIONS
Earnings
Savannah Electric and Power Company's net income after dividends on preferred
stock for 1999 totaled $23.1 million, representing a decrease of $0.6 million or
2.4 percent from the prior year. Earnings were down primarily due to lower
non-operating revenues.
In 1998, earnings were $23.6 million, representing a $0.2 million, or 0.9
percent decrease from the prior year. This was principally the result of a
decrease in other income, net.
Revenues
Total revenues for 1999 were $251.6 million, reflecting a 1.1 percent decrease
when compared to 1998. The following table summarizes the factors affecting
operating revenues for the past three years:
Increase (Decrease)
From Prior Year
--------------------------------------
1999 1998 1997
--------------------------------------
Retail -- (in thousands)
Growth and price
changes $ 5,633 $ (479) $ 7,664
Weather (5,257) 8,336 (6,186)
Fuel cost recovery
and other (438) 15,012 (10,002)
-----------------------------------------------------------------
Total retail (62) 22,869 (8,524)
-----------------------------------------------------------------
Sales for resale--
Non-affiliates (1,153) 1,081 1,469
Affiliates 1,135 964 (1,078)
-----------------------------------------------------------------
Total sales for resale (18) 2,045 391
-----------------------------------------------------------------
Other operating revenues (2,781) 3,264 336
-----------------------------------------------------------------
Total operating revenues $(2,861) $ 28,178 $ (7,797)
=================================================================
Percent change (1.1)% 12.5% (3.3)%
-----------------------------------------------------------------
Retail revenues were relatively unchanged in 1999 when compared to 1998.
Reduced demand for energy in the industrial sector and a base rate decrease to
the small business customers partially offset by increased demand in the
residential and commercial sectors contributed to this variance.
In 1998, retail revenues increased by 10.4 percent over the prior year due
primarily to unusually hot summer weather that resulted in increased energy
sales to residential and commercial customers. A base rate decrease to the small
business customer class, ordered by the Georgia Public Service Commission
(GPSC), was effective in July 1998. See Note 3 to the financial statements for
additional information.
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. Revenues from these sales
were not material during the three-year period.
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 1999 and the percent change by year were as
follows:
KWH Percent Change
------------ -----------------------------
1999 1999 1998 1997
------------ -----------------------------
(in millions)
Residential 1,579 2.6% 7.8% (1.9)%
Commercial 1,288 4.2 6.9 1.3
Industrial 713 (20.7) 2.1 5.1
Other 133 1.1 5.3 (1.4)
------------
Total retail 3,713 (2.5) 6.0 0.8
Sales for resale--
Non-affiliates 51 (3.3) (43.5) 2.9
Affiliates 77 31.8 7.2 30.4
------------
Total 3,841 (2.0)% 4.8 % 1.2 %
=====================================================================
Total retail energy sales in 1999 were down by 2.5% from the prior year
reflecting reduced energy sales of 20.7% to industrial customers due to the
shut-down of one industrial customer's facilities in late 1998 and completed
construction of a steam turbine unit by another industrial customer. These
reductions were partially mitigated by increased energy sales of 2.6% and 4.2%
to residential and commercial customers, respectively.
In 1998, total retail energy sales were up 6.0% over the prior year,
reflecting the impact of the hotter-than-normal weather on energy sales to
II-174
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 1999 Annual Report
residential and commercial customers and high demand from an industrial
customer.
Expenses
Total operating expenses for 1999 were $201.5 million, a slight increase of $1.2
million from the prior year due primarily to increases in purchased power from
non- affiliates and depreciation and amortization. Purchased power from
non-affiliates increased due principally to higher demand for energy and
increased costs associated with these power purchases. Maintenance expenses
decreased this year compared to 1998 due to repair costs in 1998 related to a
major turbine dismantle inspection. Depreciation and amortization increased
reflecting additional depreciation charges related to the GPSC's accounting
order. See Note 3 to the financial statements for additional information on the
GPSC's 1998 accounting order.
In 1998, total operating expenses were $200.3 million reflecting a $27.7
million increase from 1997. Major components of this increase included 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, however, were partially offset by a $6.4 million decrease in
purchased power from affiliates. The increase in fuel expense was primarily
attributed 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.
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:
1999 1998 1997
--------------------------
Total energy supply
(millions of KWHs) 4,039 4,182 3,964
Sources of energy supply
(percent) --
Coal 45 42 34
Oil 2 1 -
Gas 10 12 5
Purchased Power 43 45 61
Total average cost of
energy supply (cents) 2.44 2.35 2.02
- -----------------------------------------------------------------
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 lives. 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.
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).
II-175
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 1999 Annual Report
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, new short and long-term 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
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. The Company is positioning the business
to meet the challenge of this major change in the traditional practice of
selling electricity.
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 financial
condition and results of operation. 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, if the Company does not remain a low-cost producer and
provide quality service, then 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
1998, the GPSC issued a four-year accounting order settling its review of the
Company's earnings. See Note 3 to the financial statements for additional
information.
On December 20, 1999, the FERC issued its final rule on Regional
Transmission Organizations (RTOs). The order encourages utilities owning
transmission systems to form RTOs on a voluntary basis. To facilitate the
development of RTOs, the FERC will convene regional conferences for utilities,
customers, and other members of the public to discuss the formation of RTOs. In
addition to participating in the regional conferences, utilities owning
transmission systems, including the Company, are required to make a filing by
October 15, 2000. The filing must contain either a proposal for RTO
participation or a description of the efforts made to participate in an RTO, the
reasons for non-participation, any obstacles to participation, and any plans for
further work toward participation. The RTOs that are proposed in the filings
should be operational by December 15, 2001. The Company is evaluating this issue
and formulating its response. The outcome of this matter cannot now be
determined.
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
II-176
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 1999 Annual Report
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
statement as incurred. At December 31, 1999, 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, 1999, 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 January 1, 2001. 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.
Year 2000 Challenge
The work undertaken by the Company to prepare critical computer systems and
other date sensitive devices to function correctly in the Year 2000 was
successful. There were no material incidents reported and no disruption of
electric service within the service area. There were no reports of significant
events regarding third parties that impacted revenues or expenses.
Original projected total costs for Year 2000 readiness were approximately
$1.2 million. Final projected costs are $1.3 million of which $0.1 million is
projected to be spent in 2000. These costs include labor necessary to identify,
test, and renovate affected devices and systems, and costs for reporting
requirements to state and federal agencies. From its inception through December
31, 1999, the Year 2000 program costs, recognized as expense, amounted to $1.2
million.
FINANCIAL CONDITION
Overview
The principal change in the Company's financial condition in 1999 was the
addition of $29.8 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, 1999, the Company's capital structure consisted of 48.3
percent common stockholders' equity, 11.0 percent trust preferred securities,
and 40.7 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 stockholders' equity at 48 percent, preferred
securities at 10 percent and debt at 42 percent.
Maturities and retirements of long-term debt were $16 million in 1999,
$30 million in 1998 and $14 million in 1997. Included in the 1999 maturities and
retirements is the purchase by Savannah Electric of all $15 million outstanding
of its 7 7/8% Series First Mortgage Bonds due May 1, 2025.
During 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. Also
in 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.
II-177
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 1999 Annual Report
The composite interest rates and dividend rates for the years 1997 through
1999 as of year-end were as follows:
1999 1998 1997
-------------------------------
Composite interest rates
on long-term debt 6.4% 6.5% 6.9%
Preferred stock dividend rate -% -% 6.6%
Trust preferred securities
dividend rate 6.9% 6.9% -%
- -----------------------------------------------------------------
Capital Requirements for Construction
The Company's projected construction expenditures for the next three years total
$91.8 million ($25.6 million in 2000, $30.4 million in 2001, and $35.8 million
in 2002). 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. 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
$31.8 million will be needed by the end of 2002 for maturities of long-term debt
and present sinking fund requirements.
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.
Construction expenditures for Phase I nitrogen oxide and sulfur dioxide
emissions compliance totaled approximately $2 million for Savannah Electric.
For Phase II sulfur dioxide compliance, Southern Company currently uses
emission allowances and increased fuel switching. Also, equipment to control
nitrogen oxide emissions was installed on additional system fossil-fired plants
as necessary to meet Phase II limits and ozone non-attainment requirements.
Compliance for Phase II and initial ozone non-attainment requirements increased
total estimated construction expenditures by approximately $105 million. 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.
On November 3, 1999, the Environmental Protection Agency (EPA), brought a
civil action in the U.S. District Court against Alabama Power, Georgia Power
and the system service company. The complaint alleges violations of the
prevention of significant deterioration and new source review provisions of the
Clean Air Act with respect to five coal-fired generating facilities in
Alabama and Georgia. The EPA concurrently issued to the integrated Southeast
utilities a notice of violation related to 10 generating facilities, which
includes the five facilities mentioned previously and the Company's Plant Kraft.
In early 2000, the EPA filed a motion to amend its complaint to add the
violations alleged in its notice of violation, and to add Gulf Power,
Mississippi Power, and Savannah Electric as defendants. The complaint and
notice of violation are similar to those brought against and issued to
several other electric utilities. These complaints and notices of violation
allege that the utilities had failed to secure necessary permits or install
additional pollution equipment when performing maintenance and construction at
coal burning plants constructed or under construction prior to 1978. Southern
Company believes that its integrated utilities complied with applicable laws
and the EPA's regulations and interpretations in effect at the time the work in
question took place. The Clean Air Act authorizes civil penalties of up to
$27,500 per day per violation at each generating unit. Prior to January 30,
1997, the penalty was $25,000 per
II-178
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 1999 Annual Report
day. An adverse outcome of this matter could require substantial capital
expenditures that cannot be determined at this time and possibly require payment
of substantial penalties. This could affect future results of operations, cash
flows, and possibly financial condition if such costs are not recovered through
regulated rates.
In July 1997, the 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 final rule
affects 22 states including Georgia. The EPA's July 1997 standards and the
September 1998 rule are being challenged in the courts by several states and
industry groups. Implementation of the final state rules for these three
initiatives could require substantial further reductions in nitrogen oxide and
sulfur dioxide emissions from fossil-fired generating facilities and other
industries in these states. Additional compliance costs and capital expenditures
resulting from the implementation of these rules and standards 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: 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.
Sources of Capital
At December 31, 1999, the Company had $6.6 million of cash and $26.2 million of
unused short-term and revolving credit arrangements with banks to meet its
short-term cash needs and to provide additional interim funding for the
Company's construction program. Revolving credit arrangements total $20 million,
of which $10 million expires December 31, 2001 and $10 million expires December
31, 2002.
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 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.
II-179
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 1999 Annual Report
Cautionary Statement Regarding Forward-Looking Information
Savannah Electric and Power Company's 1999 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; 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-180
STATEMENTS OF INCOME
For the Years Ended December 31, 1999, 1998, and 1997
Savannah Electric and Power Company 1999 Annual Report
- --------------------------------------------------------------------------------------------------------------------
1999 1998 1997
- --------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Revenues (Note 1):
Retail sales $242,265 $242,327 $219,458
Sales for resale --
Non-affiliates 3,395 4,548 3,467
Affiliates 4,151 3,016 2,052
Other revenues 1,783 4,564 1,300
- --------------------------------------------------------------------------------------------------------------------
Total operating revenues 251,594 254,455 226,277
- --------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
Fuel 50,530 53,021 35,563
Purchased power --
Non-affiliates 14,398 9,460 2,347
Affiliates 33,398 35,687 42,107
Other 50,341 49,055 47,735
Maintenance 16,333 18,711 13,236
Depreciation and amortization (Notes 1 and 3) 23,841 22,032 20,152
Taxes other than income taxes 12,690 12,342 11,494
- --------------------------------------------------------------------------------------------------------------------
Total operating expenses 201,531 200,308 172,634
- --------------------------------------------------------------------------------------------------------------------
Operating Income 50,063 54,147 53,643
Other Income (Expense):
Interest income 169 384 279
Other, net (663) (1,698) (542)
- --------------------------------------------------------------------------------------------------------------------
Earnings Before Interest and Income Taxes 49,569 52,833 53,380
- --------------------------------------------------------------------------------------------------------------------
Interest Charges and Other:
Interest on long-term debt 9,300 10,383 10,907
Interest on notes payable 879 278 172
Amortization of debt discount, premium and expense, net 948 853 739
Other interest charges 811 341 205
Distributions on preferred securities of subsidiary 2,740 167 -
- --------------------------------------------------------------------------------------------------------------------
Total interest charges and other, net 14,678 12,022 12,023
- --------------------------------------------------------------------------------------------------------------------
Earnings Before Income Taxes 34,891 40,811 41,357
Income taxes (Notes 1 and 6) 11,808 15,101 15,186
- --------------------------------------------------------------------------------------------------------------------
Net Income 23,083 25,710 26,171
Dividends on Preferred Stock - 2,066 2,324
- --------------------------------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred Stock $ 23,083 $ 23,644 $ 23,847
====================================================================================================================
The accompanying notes are an integral part of these statements.
II-181
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1999, 1998, and 1997
Savannah Electric and Power Company 1999 Annual Report
- ------------------------------------------------------------------------------------------------------------------------
1999 1998 1997
- ------------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Activities:
Net income $ 23,083 $ 25,710 $ 26,171
Adjustments to reconcile net income
to net cash provided from operating activities --
Depreciation and amortization 25,454 23,531 21,083
Deferred income taxes and investment tax credits, net (3,353) 7,011 3,841
Other, net (47) (89) (2,816)
Changes in certain current assets and liabilities --
Receivables, net (5,999) (9,875) (1,938)
Fossil fuel stock (2,125) 221 687
Materials and supplies (1,906) 484 1,033
Accounts payable 1,133 470 (1,608)
Other 1,731 (4,859) 3,366
- ------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities 37,971 42,604 49,819
- ------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (29,833) (18,071) (18,846)
Other (1,715) 1,617 (1,418)
- ------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities (31,548) (16,454) (20,264)
- ------------------------------------------------------------------------------------------------------------------------
Financing Activities:
Increase (decrease) in notes payable, net 34,300 - (5,000)
Proceeds --
Other long-term debt - 30,000 13,870
Preferred securities - 40,000 -
Capital contribution from parent company 1,099 - -
Retirements --
First mortgage bonds (15,800) (30,000) -
Other long-term debt (481) (478) (14,303)
Preferred stock - (35,000) -
Payment of preferred stock dividends - (2,556) (2,324)
Payment of common stock dividends (25,200) (23,500) (20,500)
Other 250 (4,798) (368)
- ------------------------------------------------------------------------------------------------------------------------
Net cash used for financing activities (5,832) (26,332) (28,625)
- ------------------------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents 591 (182) 930
Cash and Cash Equivalents at Beginning of Period 5,962 6,144 5,214
- ------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ 6,553 $ 5,962 $ 6,144
========================================================================================================================
Supplemental Cash Flow Information:
Cash paid during the period for --
Interest (net of amount capitalized) $14,212 $12,198 $11,619
Income taxes (net of refunds) 12,647 9,666 11,150
- ------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
II-182
BALANCE SHEETS
At December 31, 1999 and 1998
Savannah Electric and Power Company 1999 Annual Report
- -------------------------------------------------------------------------------------------------------------------
Assets 1999 1998
- -------------------------------------------------------------------------------------------------------------------
(in thousands)
Current Assets:
Cash and cash equivalents $ 6,553 $ 5,962
Receivables --
Customer accounts receivable 20,752 18,030
Unrecovered retail fuel clause revenue 21,089 17,628
Other accounts and notes receivable 3,505 3,543
Affiliated companies 1,195 1,388
Accumulated provision for uncollectible accounts (237) (284)
Fossil fuel stock, at average cost 7,109 4,984
Materials and supplies, at average cost (Note 1) 8,402 6,496
Other 2,869 4,772
- -------------------------------------------------------------------------------------------------------------------
Total current assets 71,237 62,519
- -------------------------------------------------------------------------------------------------------------------
Property, Plant and Equipment:
In service (Notes 1 and 8) 804,096 781,964
Less accumulated provision for depreciation 360,639 341,930
- -------------------------------------------------------------------------------------------------------------------
443,457 440,034
Construction work in progress 6,561 2,908
- -------------------------------------------------------------------------------------------------------------------
Total property, plant and equipment 450,018 442,942
- -------------------------------------------------------------------------------------------------------------------
Other Property and Investments 1,506 1,420
- -------------------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets:
Deferred charges related to income taxes (Note 6) 16,063 17,130
Cash surrender value of life insurance for deferred compensation plans 16,305 14,179
Prepaid pension costs (Note 2) 1,201 3,281
Debt expense, being amortized 3,155 3,554
Premium on reacquired debt, being amortized 8,385 8,570
Other 2,348 2,204
- -------------------------------------------------------------------------------------------------------------------
Total deferred charges and other assets 47,457 48,918
- -------------------------------------------------------------------------------------------------------------------
Total Assets $570,218 $555,799
===================================================================================================================
The accompanying notes are an integral part of these balance sheets.
II-183
BALANCE SHEETS
At December 31, 1999 and 1998
Savannah Electric and Power Company 1999 Annual Report
- ------------------------------------------------------------------------------------------------------------------
Liabilities and Stockholder's Equity 1999 1998
- ------------------------------------------------------------------------------------------------------------------
(in thousands)
Current Liabilities:
Securities due within one year (Note 8) $ 704 $ 689
Notes payable 34,300 -
Accounts payable --
Affiliated 4,632 5,014
Other 11,118 10,833
Customer deposits 5,426 5,224
Taxes accrued --
Income taxes 3,046 2,467
Other 3,013 2,891
Interest accrued 3,237 3,815
Vacation pay accrued 2,142 1,978
Other 5,742 6,700
- ------------------------------------------------------------------------------------------------------------------
Total current liabilities 73,360 39,611
- ------------------------------------------------------------------------------------------------------------------
Long-term debt (See accompanying statements) 147,147 163,443
- ------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes (Note 6) 80,318 82,778
Deferred credits related to income taxes (Note 6) 19,687 21,349
Accumulated deferred investment tax credits (Note 6) 11,280 11,943
Deferred compensation plans 10,624 9,788
Employee benefits provisions (Note 2) 7,805 7,620
Other 5,150 3,402
- ------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 134,864 136,880
- --------------------------------------------------------------------------------------------------------------------
Company obligated mandatorily redeemable preferred
securities of subsidiary trust holding company junior
subordinated notes (See accompanying statements) (Note 7) 40,000 40,000
- ------------------------------------------------------------------------------------------------------------------
Common stockholder's equity (See accompanying statements) 174,847 175,865
- ------------------------------------------------------------------------------------------------------------------
Total Liabilities and Stockholder's Equity $570,218 $555,799
==================================================================================================================
The accompanying notes are an integral part of these balance sheets.
II-184
STATEMENTS OF CAPITALIZATION
At December 31, 1999 and 1998
Savannah Electric and Power Company 1999 Annual Report
- ------------------------------------------------------------------------------------------------------------------------------------
1999 1998 1999 1998
- ------------------------------------------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
Long-Term Debt (Note 8):
First mortgage bonds --
Maturity Interest Rates
-------- --------------
July 1, 2003 6.375% $20,000 $20,000
May 1, 2006 6.90% 20,000 20,000
July 1, 2023 7.40% 24,200 25,000
May 1, 2025 7.875% - 15,000
- ------------------------------------------------------------------------------------------------------------------------------------
Total first mortgage bonds 64,200 80,000
- ------------------------------------------------------------------------------------------------------------------------------------
Long-term notes payable --
6.88% due June 1, 2001 10,000 10,000
6.625% due March 17, 2015 30,000 30,000
Adjustable rates (6.28% and 6.66% at 1/1/00)
due 2001 20,000 20,000
- ------------------------------------------------------------------------------------------------------------------------------------
Total long-term notes payable 60,000 60,000
- ------------------------------------------------------------------------------------------------------------------------------------
Other long-term debt --
Pollution control revenue bonds --
Collateralized:
Variable rates (4.00% at 1/1/99)
due 2016 - 4,085
Non-collateralized:
Variable rates (3.65% to 3.95% at 1/1/00)
due 2016-2037 17,955 13,870
- ------------------------------------------------------------------------------------------------------------------------------------
Total other long-term debt 17,955 17,955
- ------------------------------------------------------------------------------------------------------------------------------------
Capitalized lease obligations 5,696 6,177
- ------------------------------------------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
requirement -- $9.5 million) 147,851 164,132
Less amount due within one year (Note 8) 704 689
- ------------------------------------------------------------------------------------------------------------------------------------
Total long-term debt excluding amount due within one year 147,147 163,443 40.7% 43.1%
- ------------------------------------------------------------------------------------------------------------------------------------
Company Obligated Mandatorily
Redeemable Preferred Securities (Note 7):
$25 liquidation value --
6.85% 40,000 40,000
- ------------------------------------------------------------------------------------------------------------------------------------
Total (annual distribution requirement -- $2.7 million) 40,000 40,000 11.0 10.5
- ------------------------------------------------------------------------------------------------------------------------------------
Common Stockholder's Equity (Note 9):
Common stock, par value $5 per share --
Authorized - 16,000,000 shares
Outstanding - 10,844,635 shares
Par value 54,223 54,223
Paid-in capital 9,787 8,688
Retained earnings 110,837 112,954
- ------------------------------------------------------------------------------------------------------------------------------------
Total common stockholder's equity 174,847 175,865 48.3 46.4
- ------------------------------------------------------------------------------------------------------------------------------------
Total Capitalization $361,994 $379,308 100.0% 100.0%
====================================================================================================================================
The accompanying notes are an integral part of these statements.
II-185
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
For the Years Ended December 31, 1999, 1998, and 1997
Savannah Electric and Power Company 1999 Annual Report
- ---------------------------------------------------------------------------------------------------------------------------------
Common Paid-In Retained
Stock Capital Earnings Total
- ---------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Balance at January 1, 1997 $54,223 $8,688 $109,373 $172,284
Net income after dividends on preferred stock - - 23,847 23,847
Cash dividends - - (20,500) (20,500)
- ---------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1997 54,223 8,688 112,720 175,631
Net income after dividends on preferred stock - - 23,644 23,644
Cash dividends - - (23,500) (23,500)
Other - - 90 90
- ---------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1998 54,223 8,688 112,954 175,865
Net income after dividends on preferred stock - - 23,083 23,083
Capital contributions from parent company - 1,099 - 1,099
Cash dividends - - (25,200) (25,200)
- ---------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1999 (Note 9) $54,223 $9,787 $110,837 $174,847
=================================================================================================================================
The accompanying notes are an integral part of these statements.
II-186
NOTES TO FINANCIAL STATEMENTS
Savannah Electric and Power Company 1999 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 integrated Southeast
utilities, Southern Company Services, Inc. (SCS), 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 integrated Southeast utilities
provide electric service in four states. Contracts among the integrated
Southeast utilities--related to 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, a 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. Southern Nuclear provides services to Southern
Company's nuclear power plants. Southern Energy acquires, develops, builds, owns
and operates power production and delivery facilities and provides a broad range
of energy-related services to utilities and industrial companies in selected
countries around the world. Southern Energy businesses include independent power
projects, integrated utilities, a distribution company, and energy trading and
marketing businesses outside the southeastern United States.
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.
Related-Party Transactions
The Company has an agreement with SCS under which the following services are
rendered to the Company at cost: general and design engineering, purchasing,
accounting and statistical, finance and treasury, tax, information resources,
marketing, auditing, insurance and pension, human resources, systems and
procedures, and other services with respect to business and operations and power
pool operations. Costs for these services amounted to $16.0 million, $15.3
million, and $13.3 million during 1999, 1998, and 1997, respectively.
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:
1999 1998
--------------------------
(in thousands)
Deferred income tax charges $ 16,063 $ 17,130
Premium on reacquired debt 8,385 8,570
Deferred income tax credits (19,687) (21,349)
Storm damage reserves (1,392) (1,580)
Accelerated depreciation (3,000) (1,000)
- ---------------------------------------------------------------
Total $ 369 $ 1,771
===============================================================
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 related 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-187
NOTES (continued)
Savannah Electric and Power Company 1999 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 of
southeastern Georgia, and to wholesale customers in the Southeast.
Revenues are accrued for service rendered but unbilled at the end of each
fiscal period. Fuel costs are expensed as the fuel is used. Electric rates for
the Company 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 regulated 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.
In 1999, the GPSC approved increases of slightly over three-tenths of a cent
per kilowatt-hour in the Company's fuel allowance.
Depreciation and Amortization
Depreciation of the original cost of plant in service is provided primarily by
using composite straight-line rates, which approximated 3.0 percent in 1999, and
2.9 percent in 1998 and 1997. 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 6.26 percent in 1999, 8.00 percent in 1998 and 9.24 percent in 1997.
Property, Plant and Equipment
Property, plant and equipment is stated at original cost less regulatory
disallowances and impairments. 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
capitalized.
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.
II-188
NOTES (continued)
Savannah Electric and Power Company 1999 Annual Report
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, 1999 $142 $136
At December 31, 1998 158 162
Trust preferred securities:
At December 31, 1999 $40 $31
At December 31, 1998 40 40
The fair values for long-term debt and preferred securities were based on
either closing market prices or closing prices of comparable instruments.
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 required by the GPSC. The measurement date for plan assets and
obligations is September 30 of 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
---------------------------
1999 1998
- ---------------------------------------------------------------
(in thousands)
Balance at beginning of year $59,207 $51,720
Service cost 1,746 1,495
Interest cost 3,893 3,806
Benefits paid (3,414) (3,392)
Actuarial (gain) loss and
employee transfers (1,856) 4,343
Amendments 385 1,235
- ---------------------------------------------------------------
Balance at end of year $59,961 $59,207
===============================================================
Plan Assets
---------------------------
1999 1998
- ---------------------------------------------------------------
(in thousands)
Balance at beginning of year $49,630 $50,630
Actual return on plan assets 8,168 171
Employer contributions - 2,464
Benefits paid (3,414) (3,392)
Employee transfers 96 (243)
- ---------------------------------------------------------------
Balance at end of year $54,480 $49,630
===============================================================
The accrued pension costs recognized in the Balance Sheets were as
follows:
1999 1998
- -----------------------------------------------------------------
(in thousands)
Funded status $(5,481) $(9,577)
Unrecognized transition
obligation 178 266
Unrecognized prior service cost 2,996 2,874
Unrecognized net loss 3,508 9,718
- -----------------------------------------------------------------
Prepaid asset recognized in
the Balance Sheets $ 1,201 $ 3,281
=================================================================
II-189
NOTES (continued)
Savannah Electric and Power Company 1999 Annual Report
Components of the plans' net periodic cost were as follows:
1999 1998 1997
- -----------------------------------------------------------------
(in thousands)
Service cost $1,746 $1,495 $1,393
Interest cost 3,893 3,806 3,556
Expected return on plan
assets (4,063) (3,992) (3,782)
Recognized net loss 152 2 475
Net amortization 352 334 280
- -----------------------------------------------------------------
Net pension cost $2,080 $1,645 $1,922
=================================================================
Postretirement Benefits
Changes during the year in the accumulated benefit obligations and in the fair
value of plan assets were as follows:
Accumulated
Benefit Obligations
---------------------------
1999 1998
- ---------------------------------------------------------------
(in thousands)
Balance at beginning of year $23,556 $20,899
Service cost 404 348
Interest cost 1,549 1,528
Benefits paid (756) (839)
Actuarial (gain) loss and
employee transfers (1,849) 1,620
- ---------------------------------------------------------------
Balance at end of year $22,904 $23,556
===============================================================
Plan Assets
---------------------------
1999 1998
- ---------------------------------------------------------------
(in thousands)
Balance at beginning of year $3,803 $3,110
Actual return on plan assets 476 85
Employer contributions 1,731 1,447
Benefits paid (756) (839)
- ---------------------------------------------------------------
Balance at end of year $5,254 $3,803
===============================================================
The accrued postretirement costs recognized in the Balance Sheets were as
follows:
1999 1998
- ---------------------------------------------------------------
(in thousands)
Funded status $(17,650) $(19,753)
Unrecognized transition
obligation 6,419 6,913
Unrecognized net loss 3,311 5,444
Fourth quarter contributions 1,336 1,152
- ---------------------------------------------------------------
Accrued liability recognized in
the Balance Sheets $(6,584) $ (6,244)
===============================================================
Components of the plans' net periodic cost were as follows:
1999 1998 1997
- ----------------------------------------------------------------
(in thousands)
Service cost $ 404 $ 348 $ 319
Interest cost 1,549 1,528 1,499
Expected return on plan assets (345) (276) (211)
Recognized net loss 152 104 125
Net amortization 494 494 494
- ----------------------------------------------------------------
Net postretirement cost $2,254 $2,198 $2,226
================================================================
The weighted average rates assumed in the actuarial calculations for both
the pension plans and postretirement benefits were:
1999 1998
- ---------------------------------------------------------------
Discount 7.50% 6.75%
Annual salary increase 5.00 4.25
Long-term return on plan assets 8.50 8.50
- ---------------------------------------------------------------
An additional assumption used in measuring the accumulated postretirement
benefit obligations was a weighted average medical care cost trend rate of 7.74
percent for 1999, decreasing gradually to 5.50 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,
1999 as follows:
II-190
NOTES (continued)
Savannah Electric and Power Company 1999 Annual Report
1 Percent 1 Percent
Increase Decrease
- ---------------------------------------------------------------
(in thousands)
Benefit obligation $1,316 $(1,244)
Service and interest costs 106 (100)
===============================================================
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 $0.5 million for 1999, and $0.4 million for 1998
and 1997.
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.
3. REGULATORY MATTERS
On November 3, 1999, the Environmental Protection Agency (EPA), brought a civil
action in the U.S. District Court against Alabama Power, Georgia Power
and the system service company. The complaint alleges violations of the
prevention of significant deterioration and new source review provisions of the
Clean Air Act with respect to five coal-fired generating facilities in Alabama
and Georgia. The EPA concurrently issued to the integrated Southeast utilities a
notice of violation related to 10 generating facilities, which includes the five
facilities mentioned previously and the Company's Plant Kraft. In early 2000,
the EPA filed a motion to amend its complaint to add the violations alleged in
its notice of violation, and to add Gulf Power, Mississippi Power, and Savannah
Electric as defendants. The complaint and notice of violation are similar to
those brought against and issued to several other electric utilities. These
complaints and notices of violation allege that the utilities had failed to
secure necessary permits or install additional pollution equipment when
performing maintenance and construction at coal burning plants constructed or
under construction prior to 1978. Southern Company believes that its integrated
utilities complied with applicable laws and the EPA's regulations and
interpretations in effect at the time the work in question took place. The Clean
Air Act authorizes civil penalties of up to $27,500 per day per violation at
each generating unit. Prior to January 30, 1997, the penalty was $25,000 per
day. An adverse outcome of this matter could require substantial capital
expenditures that cannot be determined at this time and possibly require payment
of substantial penalties. This could affect future results of operations, cash
flows, and possibly financial condition if such costs are not recovered through
regulated rates.
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 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 $25.6 million in 2000, $30.4 million in 2001, and $35.8 million in
2002. 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.
II-191
NOTES (continued)
Savannah Electric and Power Company 1999 Annual Report
5. FINANCING AND COMMITMENTS
General
To the extent possible, the Company's construction program is expected to be
financed from internal sources and from the issuance of additional long-term
debt and 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 1999, unused credit arrangements with six banks totaled $26.2
million and expire at various times during 2000.
The Company has revolving credit arrangements of $20 million, of which $10
million expires December 31, 2001 and $10 million expires December 31, 2002.
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.
Fuel and Purchased Power 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 $15 million and $9 million for 2000 and 2001, respectively.
In 1999, the Company entered into a purchased power agreement for 200
megawatts of capacity from Georgia Power Company's combined cycle combustion
turbine units currently under construction at Plant Wansley and due to begin
operation in 2002.
Operating Leases
The Company has rental agreements with various terms and expiration dates.
Rental expenses totaled $0.5 million for 1999, $1.1 million for 1998 and $1.2
million for 1997.
At December 31, 1999, estimated future minimum lease payments for
noncancelable operating leases were as follows:
Rental Commitments
--------------------
(in thousands)
2000 $ 483
2001 483
2002 483
2003 483
2004 483
2005 and thereafter $6,485
- -------------------------------------------------------------
6. INCOME TAXES
At December 31, 1999, tax-related regulatory assets and liabilities were $16.1
million and $19.7 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.
II-192
NOTES (continued)
Savannah Electric and Power Company 1999 Annual Report
Details of income tax provisions are as follows:
1999 1998 1997
--------------------------------
(in thousands)
Total provision for income taxes
Federal --
Currently payable $12,968 $ 6,763 $ 9,743
Deferred -- current year 354 8,377 4,522
-- reversal of
prior years (3,683) (2,565) (1,381)
- ------------------------------------------------------------------
9,639 12,575 12,884
- ------------------------------------------------------------------
State --
Currently payable 2,193 1,327 1,603
Deferred -- current year (34) 1,174 569
-- reversal of
prior years 10 25 130
- ------------------------------------------------------------------
2,169 2,526 2,302
- ------------------------------------------------------------------
Total $11,808 $15,101 $15,186
==================================================================
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:
1999 1998
--------------------
Deferred tax liabilities: (in thousands)
Accelerated depreciation $73,400 $75,187
Property basis differences 6,917 7,591
Other 12,031 10,187
- ----------------------------------------------------------------
Total 92,348 92,965
- ----------------------------------------------------------------
Deferred tax assets:
Pension and other benefits 6,925 4,892
Other 2,935 2,828
- ----------------------------------------------------------------
Total 9,860 7,720
- ----------------------------------------------------------------
Net deferred tax liabilities 82,488 85,245
Portions included in current assets, net (2,170) (2,467)
- ----------------------------------------------------------------
Accumulated deferred income taxes
in the Balance Sheets $80,318 $82,778
================================================================
Deferred investment tax credits are amortized over the lives 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 1999, 1998 and 1997. At December 31, 1999, 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:
1999 1998 1997
-----------------------------
Federal statutory tax rate 35% 35% 35%
State income tax, net of
federal income tax benefit 4 4 4
Other (5) (2) (2)
----------------------------------------------------------------
Effective income tax rate 34% 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.
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 the Trust
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.
II-193
NOTES (continued)
Savannah Electric and Power Company 1999 Annual Report
Maturities and retirements of long-term debt were $16 million in 1999,
$30 million in 1998 and $14 million in 1997. Included in the 1999 maturities and
retirements is the purchase by Savannah Electric of all $15 million outstanding
of its 7 7/8% Series First Mortgage Bonds due May 1, 2025.
In 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.
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:
1999 1998
---------------------
(in thousands)
Bond sinking fund requirement $650 $800
Less:
Portion to be satisfied by
certifying property additions 650 -
Reacquired bonds and/or cash deposits - 800
- -------------------------------------------------------------------
Cash sinking fund requirement - -
Other long-term debt maturities 704 689
- -------------------------------------------------------------------
Total $704 $689
===================================================================
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 1999 and 1998. It is anticipated that the 2000 requirement
will be satisfied by certifying property additions. Sinking fund requirements
and/or maturities through 2004 applicable to long-term debt are as follows: $0.7
million in 2000; $30.6 million in 2001; $0.5 million in 2002; $20.4 million in
2003; and $0.4 million in 2004.
9. COMMON STOCK DIVIDEND RESTRICTIONS
The Company's Indenture contains certain limitations on the payment of cash
dividends on common stock. At December 31, 1999, 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 1999 and 1998 are as follows (in
thousands):
Net Income After
Operating Operating Dividends on
Quarter Ended Revenues Income Preferred Stock
- ------------------------------------------------------------------
March 1999 $47,098 $ 5,637 $ 1,209
June 1999 61,692 12,495 5,268
September 1999 91,849 27,081 13,705
December 1999 50,955 4,850 2,901
March 1998 $48,381 $ 8,277 $ 2,426
June 1998 69,616 17,269 7,807
September 1998 84,224 24,777 12,518
December 1998 52,234 3,824 893
- ------------------------------------------------------------------
The Company's business is influenced by seasonal weather conditions and a
seasonal rate structure, among other factors.
The quarterly operating income information above has been reclassified to
reflect the Company's current presentation of income tax expense.
II-194
SELECTED FINANCIAL AND OPERATING DATA 1995-1999
Savannah Electric and Power Company 1999 Annual Report
- --------------------------------------------------------------------------------------------------------------------------------
1999 1998 1997 1996 1995
- --------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands) $251,594 $254,455 $226,277 $234,074 $225,729
Net Income after Dividends
on Preferred Stock (in thousands) $23,083 $23,644 $23,847 $23,940 $23,395
Cash Dividends
on Common Stock (in thousands) $25,200 $23,500 $20,500 $19,600 $17,600
Return on Average Common Equity (percent) 13.16 13.45 13.71 14.08 14.20
Total Assets (in thousands) $570,218 $555,799 $547,352 $544,900 $524,662
Gross Property Additions (in thousands) $29,833 $18,071 $18,846 $28,950 $26,503
- --------------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $174,847 $175,865 $175,631 $172,284 $167,812
Preferred stock - - 35,000 35,000 35,000
Company obligated mandatorily
redeemable preferred securities 40,000 40,000 - - -
Long-term debt 147,147 163,443 142,846 164,406 153,679
- --------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $361,994 $379,308 $353,477 $371,690 $356,491
================================================================================================================================
Capitalization Ratios (percent):
Common stock equity 48.3 46.4 49.7 46.4 47.1
Preferred stock - - 9.9 9.4 9.8
Company obligated mandatorily
redeemable preferred securities 11.0 10.5 - - -
Long-term debt 40.7 43.1 40.4 44.2 43.1
- --------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0 100.0 100.0 100.0
================================================================================================================================
Security Ratings:
First Mortgage Bonds -
Moody's A1 A1 A1 A1 A1
Standard and Poor's AA- AA- AA- A+ A+
Preferred Stock -
Moody's a2 a2 a2 a2 a2
Standard and Poor's A- A A A A
================================================================================================================================
Customers (year-end):
Residential 112,891 110,437 109,092 106,657 104,624
Commercial 15,433 15,328 14,233 13,877 13,339
Industrial 67 63 64 65 65
Other 417 377 1,129 1,097 1,048
- --------------------------------------------------------------------------------------------------------------------------------
Total 128,808 126,205 124,518 121,696 119,076
================================================================================================================================
Employees (year-end): 533 542 535 571 584
- --------------------------------------------------------------------------------------------------------------------------------
II-195
SELECTED FINANCIAL AND OPERATING DATA 1995-1999 (continued)
Savannah Electric and Power Company 1999 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------
1999 1998 1997 1996 1995
- -----------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $ 112,371 $109,393 $ 96,587 $ 101,607 $ 95,208
Commercial 88,449 86,231 78,949 80,494 75,117
Industrial 32,233 37,865 35,301 37,077 36,040
Other 9,212 8,838 8,621 8,804 8,386
- -----------------------------------------------------------------------------------------------------------------------------
Total retail 242,265 242,327 219,458 227,982 214,751
Sales for resale - non-affiliates 3,395 4,548 3,467 1,998 1,851
Sales for resale - affiliates 4,151 3,016 2,052 3,130 7,200
- -----------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 249,811 249,891 224,977 233,110 223,802
Other revenues 1,783 4,564 1,300 964 1,927
- -----------------------------------------------------------------------------------------------------------------------------
Total $251,594 $254,455 $226,277 $234,074 $225,729
=============================================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 1,579,068 1,539,792 1,428,337 1,456,651 1,402,148
Commercial 1,287,832 1,236,337 1,156,078 1,141,218 1,099,570
Industrial 713,448 900,012 881,261 838,753 887,141
Other 132,555 131,142 124,490 126,215 126,057
- -----------------------------------------------------------------------------------------------------------------------------
Total retail 3,712,903 3,807,283 3,590,166 3,562,837 3,514,916
Sales for resale - non-affiliates 51,548 53,294 94,280 91,610 87,747
Sales for resale - affiliates 76,988 58,415 54,509 41,808 63,731
- -----------------------------------------------------------------------------------------------------------------------------
Total 3,841,439 3,918,992 3,738,955 3,696,255 3,666,394
=============================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 7.12 7.10 6.76 6.98 6.79
Commercial 6.87 6.97 6.83 7.05 6.83
Industrial 4.52 4.21 4.01 4.42 4.06
Total retail 6.52 6.36 6.11 6.40 6.11
Sales for resale 5.87 6.77 3.71 3.84 5.98
Total sales 6.50 6.38 6.02 6.31 6.10
Residential Average Annual
Kilowatt-Hour Use Per Customer 14,100 14,061 13,231 13,771 13,478
Residential Average Annual
Revenue Per Customer $1,003.39 $998.94 $894.73 $960.58 $915.15
Plant Nameplate Capacity
Ratings (year-end) (megawatts) 788 788 788 788 788
Maximum Peak-Hour Demand (megawatts):
Winter 719 582 625 666 630
Summer 875 846 802 811 811
Annual Load Factor (percent) 51.2 54.9 54.3 53.1 52.9
Plant Availability Fossil-Steam (percent): 72.8 72.9 93.7 77.6 83.3
- -----------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 44.6 41.6 34.4 27.7 23.9
Oil and gas 12.3 12.9 5.2 3.1 5.9
Purchased power -
From non-affiliates 5.3 3.4 1.4 2.1 2.3
From affiliates 37.8 42.1 59.0 67.1 67.9
- -----------------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0 100.0 100.0
=============================================================================================================================
II-196
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 2000
annual meeting of stockholders. The ages of directors and executive officers in
Item 10 set forth below are as of December 31, 1999.
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 60
Served as Director since 3-1-89
Whit Armstrong (2)
Age 52
Served as Director since 9-24-82
David J. Cooper, Sr. (2)
Age 54
Served as Director since 4-24-98
H. Allen Franklin (2)
Age 55
Served as Director since 10-22-99
R. Kent Henslee (2)
Age 64
Served as Director since 10-22-99
Carl E. Jones, Jr. (2)
Age 59
Served as Director since 4-22-88
Patricia M. King (2)
Age 54
Served as Director since 7-25-97
James K. Lowder (2)
Age 50
Served as Director since 7-25-97
Wallace D. Malone, Jr. (2)
Age 63
Served as Director since 6-22-90
Thomas C. Meredith (2)
Age 58
Served as Director since 10-23-98
Mayer Mitchell (2)
Age 66
Served as Director since 10-22-99
William V. Muse (2)
Age 60
Served as Director since 2-26-93
John T. Porter (2)
Age 68
Served as Director since 10-22-93
Robert D. Powers (2)
Age 49
Served as Director since 1-24-92
Andreas Renschler (2)
Age 41
Served as Director since 1-23-98
C. Dowd Ritter (2)
Age 52
Served as Director since 7-25-97
James H. Sanford (2)
Age 55
Served as Director since 8-1-83
John C. Webb, IV (2)
Age 57
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 23, 1999) for one
year until the next annual meeting or until a successor is elected and
qualified, except for Mr. Franklin, Mr. Henslee and Mr. Mitchell, whose
elections were effective 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 or she 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 60
Served as Executive Officer since 3-1-89
Banks H. Farris
Executive Vice President
Age 64
Served as Executive Officer since 12-3-91
Michael D. Garrett
Executive Vice President
Age 50
Served as Executive Officer since 3-1-98
William B. Hutchins, III
Executive Vice President, Chief Financial Officer
and Treasurer
Age 56
Served as Executive Officer since 12-3-91
C. Alan Martin
Executive Vice President
Age 51
Served as Executive Officer since 1-1-00
Jerry L. Stewart
Senior Vice President
Age 50
Served as Executive Officer since 7-23-99
(1) Previously served as executive officer of ALABAMA from 1979 to 1985.
Each of the above is currently an executive officer of ALABAMA, serving a
term running from the last annual meeting of the directors (April 23, 1999) for
one year until the next annual meeting or until his successor is elected and
qualified, except for Mr. Martin and Mr. Stewart, whose elections were effective
on the dates 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 Chief Executive Officer of
The Citizens Bank, Enterprise, Alabama. Also, President, Chairman of the Board
and Chief Executive Officer of Enterprise Capital Corporation, 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.
H. Allen Franklin - President and Chief Operating Officer of SOUTHERN. He
previously served as President and Chief Executive Officer of GEORGIA from 1994
to 1999. Director of GEORGIA and GULF.
R. Kent Henslee - Managing Partner of the law firm of Henslee, Robertson &
Strawn, L.L.C., 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.
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.
Thomas C. Meredith - Chancellor of The University of Alabama System,
Tuscaloosa, Alabama. Director of ATMOS Energy Corporation, Dallas, Texas.
Mayer Mitchell - President of Mitchell Brothers, Inc. (real estate and
investments), Mobile, Alabama. Director of The Banc Corporation, Birmingham,
Alabama.
William V. Muse - President of Auburn University, Auburn, Alabama.
John T. Porter - Pastor of Sixth Avenue Baptist Church, Birmingham, Alabama.
Robert D. Powers - President of The Eufaula Agency, Inc. (real estate and
insurance), Eufaula, Alabama.
Andreas Renschler - President of Mcc smart Gmbh, Germany, a division of Daimler
Chrysler.
C. Dowd Ritter - Chairman, President, Chief Executive Officer of AmSouth
Bancorporation and AmSouth Bank, Birmingham, Alabama.
James H. Sanford - Chairman, HOME Place Farms Inc. (diversified farmers and
ginners), Prattville, Alabama. President, Autauga Quality Cotton Association,
Prattville, Alabama. Chairman of the Board, Sylvest Farms of Georgia, Inc.,
College Park, Georgia. Chairman of the Board, Sylvest Farms, Inc., Montgomery,
Alabama.
John C. Webb, IV - President, Webb Lumber Company, Inc. (wholesale lumber and
wood products sales), Demopolis, Alabama.
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.
Michael D. Garrett - Executive Vice President - External Affairs since 1998. He
previously served as Senior Vice President of External Affairs from February
1994 to March 1998. Responsible for governmental relations, environmental,
public relations, economic development, corporate real estate and corporate
services.
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.
C. Alan Martin - Executive Vice President - External Affairs since January 2000.
He previously served as Executive Vice President and Chief Marketing Officer for
SOUTHERN from 1998 to 1999. Responsible for governmental relations,
environmental, public relations, economic development, corporate real estate and
corporate services.
Jerry L. Stewart - Senior Vice President - Fossil and Hydro Generation since
1999. He previously served as Vice President of Fuel Services for SCS from 1992
to 1999. Responsible for providing overall management of the Fossil Generation,
Hydro Generation, Power Generation Support and Fuels Department.
Involvement in certain legal proceedings.
None.
III-3
GEORGIA
Identification of directors of GEORGIA.
David M. Ratcliffe
President and Chief Executive Officer
Age 51
Served as Director since 6-1-99
Daniel P. Amos (1)
Age 48
Served as Director since 5-21-97
Juanita P. Baranco (1)
Age 50
Served as Director since 5-21-97
William A. Fickling, Jr. (1)
Age 67
Served as Director since 4-18-73
H. Allen Franklin (1)
Age 55
Served as Director since 1-1-94
L. G. Hardman III (1)
Age 60
Served as Director since 6-25-79
James R. Lientz, Jr. (1)
Age 56
Served as Director since 7-21-93
Zell Miller (1)
Age 68
Served as Director since 2-17-99
G. Joseph Prendergast (1)
Age 54
Served as Director since 1-20-93
Herman J. Russell (1)
Age 69
Served as Director since 5-18-88
William Jerry Vereen (1)
Age 59
Served as Director since 5-18-88
Carl Ware (1) (2)
Age 56
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 19, 1999) for one
year until the next annual meeting or until a successor is elected and
qualified, except for Mr. Ratcliffe, 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 or 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.
David M. Ratcliffe
President, Chief Executive Officer and Director
Age 51
Served as Executive Officer since 3-1-98
William C. Archer, III
Executive Vice President - External Affairs
Age 51
Served as Executive Officer since 4-6-95
Thomas A. Fanning
Executive Vice President, Treasurer and
Chief Financial Officer
Age 42
Served as Executive Officer since 6-12-99
Gene R. Hodges
Executive Vice President - Customer Operations
Age 61
Served as Executive Officer since 11-19-86
Wayne T. Dahlke
Senior Vice President - Power Delivery
Age 58
Served as Executive Officer since 4-19-89
III-4
James K. Davis
Senior Vice President - Corporate Relations
Age 59
Served as Executive Officer since 10-1-93
Robert H. Haubein
Senior Vice President - Fossil/Hydro Power
Age 59
Served as Executive Officer since 2-19-92
Leonard J. Haynes
Senior Vice President - Marketing
Age 49
Served as Executive Officer since 10-13-98
Fred D. Williams
Senior Vice President - Resource Policy & Planning
Age 55
Served as Executive Officer since 11-18-92
Each of the above is currently an executive officer of GEORGIA, serving a
term running from the last annual meeting of the directors (May 19, 1999) for
one year until the next annual meeting or until his successor is elected and
qualified, except for Mr. Fanning, 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 relationship
None.
Business experience.
David M. Ratcliffe - President and Chief Executive Officer of GEORGIA since June
1999. He previously served as Executive Vice President, Treasurer and Chief
Financial Officer from 1998 to 1999. Senior Vice President of External Affairs
for SOUTHERN from 1995 to 1998. Director of Mississippi Chemical Corporation.
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.
William A. Fickling, Jr. - Chairman of the Board, Chief Executive Officer of
Beech Street Corporation (provider of managed care services) since 1989. He
previously served as President from 1995 to 1996.
H. Allen Franklin - President and Chief Operating Officer of SOUTHERN since
1999. He previously served as President and Chief Executive Officer of GEORGIA
from 1994 to 1999. Director of ALABAMA and GULF.
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.
James R. Lientz, Jr. - President, Bank of America (formerly NationsBank)
Mid-South Banking Group since 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 - President and Chief Operating Officer, Wachovia
Corporation and Wachovia Bank, N.A., Winston Salem, North Carolina since April
1999. He previously served as Senior Executive Vice President, Wachovia
Corporation, heading the banking division comprising the companies' consumer
and corporate banking activities and Wachovia Bank, N.A. Director of Willamette
Industries, Inc.
III-5
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 Citizens Bancshares Corporation and
National Service Industries, Atlanta, Georgia.
William Jerry Vereen - President, Treasurer, Chief Executive Officer, and
Director 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 - Executive Vice President, The Coca-Cola Company since January 2000.
He previously served as President, Africa Group, The Coca-Cola Company.
Director of Charlotte-based Coca-Cola Bottling Co. Consolidated.
William C. Archer, III - Executive Vice President - External Affairs since
September 1995. He previously served as Senior Vice President of External
Affairs from April 1995 to September 1995. Vice President of 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, corporate concerns and economic development.
Thomas A. Fanning - Executive Vice President, Treasurer and Chief Financial
Officer since June 1999. He previously served as Senior Vice President of
Strategy for SOUTHERN from June 1998 to June 1999. Senior Vice President and
Chief Information Officer for SOUTHERN from March 1995 to 1998. Vice President,
Treasurer and Assistant Secretary for SCS from January to March 1995.
Responsible for accounting, corporate secretary, finance and procurement.
Gene R. Hodges - Executive Vice President - Customer Operations, Power Delivery
and Safety since 1992. Responsible for the northern and southern regions and
power delivery, customer service, region safety and labor relations' areas.
Wayne T. Dahlke - Senior Vice President - Power Delivery since 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.
Responsible for corporate relations and consumer affairs.
Robert H. Haubein - Senior Vice President - Fossil/ Hydro Power since 1994.
Responsible for fossil/hydro power generation, labor relations, safety and
health.
Leonard J. Haynes - Senior Vice President - Marketing since 1998. He previously
served as 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 D. Williams - Senior Vice President - Resource Policy and Planning since
1997. He previously served as Senior Vice President of Wholesale Power Marketing
from 1995 to 1997. Senior Vice President of 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 61
Served as Director since 2-1-94
Fred C. Donovan, Sr. (1)
Age 59
Served as Director since 1-18-91
H. Allen Franklin (1)
Age 55
Served as Director since 6-29-99
W. Deck Hull, Jr. (1)
Age 67
Served as Director since 10-14-83
Joseph K. Tannehill (1)
Age 66
Served as Director since 7-19-85
Barbara H. Thames (1)
Age 59
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 29, 1999) for one year
until the next annual meeting or until a successor is elected and qualified.
There are no arrangements or understandings between any of the individuals
listed above and any other person pursuant to which he or she was or is to be
selected as a director or nominee, other than any arrangements or understandings
with directors or officers of GULF acting solely in their capacities as such.
Identification of executive officers of GULF.
Travis J. Bowden
President, Chief Executive Officer and Director
Age 61
Served as Executive Officer since 2-1-94
Francis M. Fisher, Jr.
Vice President - Power Delivery and Customer Operations
Age 51
Served as Executive Officer since 5-19-89
John E. Hodges, Jr.
Vice President - Marketing and Employee/External Affairs
Age 56
Served as Executive Officer since 5-19-89
Robert G. Moore
Vice President - Power Generation and Transmission
Age 50
Served as Executive Officer since 7-25-97
Arlan E. Scarbrough
Vice President - Finance
Age 63
Served as Executive Officer since 9-21-77
Each of the above is currently an executive officer of GULF, serving a term
running from the last annual meeting of the directors (July 23, 1999) 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.
Fred C. Donovan, Sr. - President of Baskerville - Donovan, Inc., an
architectural and engineering firm, Pensacola, Florida.
III-7
H. Allen Franklin - President and Chief Operating Officer of SOUTHERN since
1999. He previously served as President and Chief Executive Officer of GEORGIA
from 1994 to 1999. Director of ALABAMA and GEORGIA.
W. Deck Hull, Jr. - President and Director of Hull Company, Panama City, Florida
since 1997. He previously served as Vice Chairman of the SunTrust Bank, West
Florida, Panama City, Florida from 1993 to 1997.
Joseph K. Tannehill - President, Chairman and Chief Executive Officer of
Tannehill International Industries, Inc., Lynn Haven, Florida since 1991.
Chairman and Chief Executive Officer of Merrick Industries, Inc., Lynn Haven,
Florida since 1991. Director of Regions Bank of North Florida, Panama City,
Florida.
Barbara H. Thames - Chief Operating Officer of West Florida Regional Medical
Center, Pensacola, Florida (a-for-profit Healthcare Corporation) since 1998. 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 of 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 of Customer Operations from
1989 to 1996. Responsible for corporate communications, marketing, governmental
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 of Plant Bowen at GEORGIA. Responsible for the generation and
transmission of electricity and bulk power marketing 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 51
Served as Director since 3-27-95
Edwin E. Downer (1)
Age 68
Served as Director since 4-24-84
Robert S. Gaddis (1)
Age 68
Served as Director since 1-21-86
Linda T. Howard (1)
Age 56
Served as Director since 2-24-99
Aubrey K. Lucas (1)
Age 65
Served as Director since 4-24-84
Malcolm Portera (1)
Age 53
Served as Director since 4-6-99
George A. Schloegel (1)
Age 59
Served as Director since 7-26-95
Philip J. Terrell (1)
Age 46
Served as Director since 2-22-95
N. Eugene Warr (1)
Age 64
Served as Director since 1-21-86
(1) No position other than Director.
Each of the above is currently a director of MISSISSIPPI, serving a term
running from the last annual meeting of MISSISSIPPI's stockholder (April 6,
1999) for one year until the next annual meeting or until a successor is elected
and qualified.
There are no arrangements or understandings between any of the individuals
listed above and any other person pursuant to which he or she was or is to be
selected as a director or nominee, other than any arrangements or understandings
with directors or officers of MISSISSIPPI acting solely in their capacities as
such.
Identification of executive officers of MISSISSIPPI.
Dwight H. Evans
President, Chief Executive Officer and Director
Age 51
Served as Executive Officer since 3-27-95
H. E. Blakeslee
Vice President - Customer Services and Retail Marketing
Age 59
Served as Executive Officer since 1-25-84
Mark S. Lynch
Vice President - Power Generation and Delivery
Age 46
Served as Executive Officer since 10-1-99
Don E. Mason
Vice President - External Affairs and Corporate Services
Age 58
Served as Executive Officer since 7-27-83
Michael W. Southern
Vice President, Secretary, Treasurer and
Chief Financial Officer
Age 47
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 (April 28, 1999)
for one year until the next annual meeting or until a successor is elected and
qualified, except for Mr. Lynch, 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
MISSISSIPPI acting solely in their capacities as such.
III-9
Identification of certain significant employees.
None.
Family relationships.
None.
Business experience.
Dwight H. Evans - President and Chief Executive Officer since 1995. He
previously served as Executive Vice President of External Affairs of GEORGIA
from 1989 to 1995.
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.
Linda T. Howard - President of Howard Industries, Inc., Laurel, Mississippi.
Aubrey K. Lucas - President Emeritus and Distinguished Professor of Higher
Education at the University of Southern Mississippi, Hattiesburg, Mississippi.
Malcolm Portera - President, Mississippi State University, Starkville,
Mississippi.
George A. Schloegel - President and Chief Executive Officer of Hancock Bank.
President, Chief Executive Officer and Director of Hancock Bank Securities
Corporation. Vice Chairman of Hancock Holding Company. Director of Hancock
Bank of Mississippi and Hancock Bank of Louisiana.
Philip J. Terrell - Superintendent of Schools, Pass Christian Public School
District, Pass Christian, Mississippi; and adjunct Professor of Education at
William Carey College, Gulfport, Mississippi.
N. Eugene Warr - Retailer, Gulfport, Mississippi. Director of Coast
Community Bank, formerly SouthTrust Bank of Mississippi, Biloxi,
Mississippi.
H. E. Blakeslee - Vice President - Customer Services and Retail 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.
Mark S. Lynch - Vice President - Power Generation and Delivery since 1999. He
previously served as President and Chief Executive Officer of Empresa Electrica
del Norte Grande, S.A. from 1996 to 1999. 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.
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. He previously served as Director of Corporate Finance of SCS
from 1994 to 1995. Responsible for accounting, secretary/treasury, corporate
planning, procurement and information resources.
Involvement in certain legal proceedings.
None.
III-10
SAVANNAH
Identification of directors of SAVANNAH.
G. Edison Holland, Jr.
President and Chief Executive Officer
Age 47
Served as Director since 7-15-97
Gus H. Bell (1)
Age 62
Served as Director since 7-20-99
Archie H. Davis (1)
Age 58
Served as Director since 2-18-97
Walter D. Gnann (1)
Age 64
Served as Director since 5-17-83
Robert B. Miller, III (1)
Age 54
Served as Director since 5-17-83
Arnold M. Tenenbaum (1)
Age 63
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 18, 1999)
for one year until the next annual meeting or until a successor is elected and
qualified, except for Mr. Bell, 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 or 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 47
Served as Executive Officer since 7-15-97
Lewis A. Jeffers
Vice President - Power Generation
Age 44
Served as Executive Officer since 11-2-99
W. Miles Greer
Vice President - Customer Operations and External Affairs
Age 56
Served as Executive Officer since 11-20-85
Kirby R. Willis
Vice President, Treasurer, Chief Financial Officer
and Assistant Corporate Secretary
Age 48
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 20, 1999 for the
ensuing year, except for Mr. Jeffers 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
SAVANNAH acting solely in their capacities as such.
Identification of certain significant employees.
None.
Family relationships
None.
Business experience.
G. Edison Holland, Jr. - President and Chief Executive Officer since 1997. He
previously served as Vice President of 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.
Gus H. Bell, III - President and Chief Executive Officer of Hussey, Gay, Bell
and DeYoung, Inc., (specializing in environmental, industrial, structural,
architectural and civil engineering), Savannah, Georgia. Director of SunTrust
Bank of Savannah.
III-11
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..
Walter D. Gnann - President of Walt's TV, Appliance and Furniture Co., Inc.,
Springfield, 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 and
Cerulean Corporation.
W. Miles Greer - Vice President - Customer Operations and External Affairs since
1998. He previously served as Vice President of Marketing and Customer Service
from 1994 to 1998. Responsible for customer services, transmission and
distribution, engineering, system operation and external affairs.
Lewis A. Jeffers - Vice President - Power Generation since 1999. He previously
served as General Manager of Power Generation from February 1999 to November
1999; General Manager for Plants Smith and Scholz at GULF from May 1996 through
January 1999; and Assistant General Manager at ALABAMA for Plant Barry from
September 1993 to May 1996. Responsible for operations and maintenance of Plants
Kraft, Riverside and McIntosh.
Kirby R. Willis - Vice President, Treasurer and Chief Financial Officer since
1994 and Assistant Corporate Secretary effective 1998. Responsible primarily for
accounting, financial, labor relations, corporate services, corporate
compliance, environmental and safety activities.
Involvement in certain legal proceedings.
None
Section 16(a) Beneficial Ownership Reporting
Compliance.
MISSISSIPPI's Mr. Lynch filed an Initial Statement of Beneficial Ownership of
Equity Securities on Form 3, late.
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 $100,000 during
1999 for each of the integrated Southeast utilities (ALABAMA, GEORGIA, GULF,
MISSISSIPPI and SAVANNAH).
Key terms used in this Item will have the following meanings:-
AME.............................Above-market earnings on deferred compensation
ESP.............................Employee Savings Plan
ESOP............................Employee Stock Ownership Plan
SBP.............................Supplemental Benefit Plan
ERISA...........................Employee Retirement Income Security Act
ALABAMA
SUMMARY COMPENSATION TABLE
ANNUAL COMPENSATION LONG-TERM COMPENSATION
Number of
Securities Long-
Name Underlying Term
and Other Annual Stock Incentive All Other
Principal Compensation Options Payouts Compensation
Position Year Salary($) Bonus($) ($)1 (Shares) ($)2 ($)3
- ------------------------------------------------------------------------------------------------------------------------
Elmer B. Harris
President, 1999 550,674 97,125 15,301 31,341 330,618 29,800
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
Banks H. Farris 1999 306,954 46,723 16,342 13,485 205,980 16,439
Executive Vice 1998 275,822 32,631 8,530 11,473 178,829 14,764
President 1997 247,170 37,500 7,218 13,513 155,313 14,379
William B.
Hutchins, III
Executive Vice 1999 256,665 36,365 9,573 11,246 152,585 13,804
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
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. Garrett 4 1999 256,211 36,375 21,268 11,249 132,434 13,496
Executive Vice 1998 221,731 57,026 12,389 7,800 105,866 11,558
President 1997 - - - - - -
Jerry L. Stewart4 1999 182,097 26,996 1,884 6,340 122,003 9,794
Senior Vice President 1998 - - - - - -
1997 - - - - - -
1 Tax reimbursement by ALABAMA and certain personal benefits.
2 Payouts made in 1998, 1999 and 2000 for the four-year performance periods ending December 31, 1997, 1998 and 1999,
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 $5,691 $897 $23,212
Banks H. Farris 7,401 897 8,141
William B. Hutchins, III 6,603 897 6,304
Michael D. Garrett 5,691 897 6,908
Jerry L. Stewart 7,200 897 1,697
4 Messrs. Garrett and Stewart were named executive officers effective April 24, 1998 and July 23, 1999, respectively.
III-14
GEORGIA
SUMMARY COMPENSATION TABLE
ANNUAL COMPENSATION LONG-TERM COMPENSATION
Number of
Securities Long-
Name Underlying Term
and Other Annual Stock Incentive All Other
Principal Compensation Options Payouts Compensation
Position Year Salary($) Bonus($) ($)1 (Shares) ($)2 ($)3
- ----------------------------------------------------------------------------------------------------------------------------
H. Allen Franklin 4
President, 1999 603,658 126,000 31,023 71,153 375,137 32,654
Chief Executive 1998 564,329 237,502 7,078 30,521 283,629 31,590
Officer, Director 1997 511,505 129,426 14,219 36,544 280,513 31,350
David M. Ratcliffe
President, 1999 388,819 85,389 16,051 24,110 321,983 20,885
Chief Executive 1998 339,672 62,700 3,934 14,039 218,175 12,255
Officer, Director 1997 313,152 50,515 10,828 17,086 207,322 18,342
Robert H. 1999 278,502 59,882 11,801 11,209 152,585 13,693
Haubein, Jr. 1998 239,448 35,683 1,922 8,175 132,472 13,007
Senior Vice President 1997 220,358 35,683 657 9,952 115,170 11,981
Gene R. Hodges 1999 243,487 44,086 12,538 10,604 152,585 13,259
Executive 1998 244,284 42,595 4,543 8,317 132,472 13,087
Vice President 1997 228,336 39,058 5,544 10,271 126,075 13,111
Thomas A. Fanning 5
Executive Vice
President, Treasurer 1999 233,644 48,312 4,504 10,458 152,585 12,396
and Chief 1998 - - - - - -
Financial Officer 1997 - - - - - -
William C. Archer 1999 220,706 40,120 16,609 7,972 152,585 11,844
Executive 1998 216,246 121,261 67,940 7,390 132,472 11,404
Vice President 1997 197,870 40,054 3,410 8,953 84,048 11,280
1 Tax reimbursement by GEORGIA on certain personal benefits, including $64,679 in 1998 for Mr. Archer related to a cash award.
2 Payouts made in 1998, 1999 and 2000 for the four-year performance periods ending December 31, 1997, 1998 and 1999,
respectively.
3 GEORGIA contributions to the ESP, ESOP, and non-pension related accruals under the SBP (ERISA excess plan
under which accruals are made to offset Internal Revenue Code imposed limitations under the ESP and ESOP) for the following:-
Name ESP ESOP SBP
H. Allen Franklin $6,242 $897 $25,515
David M. Ratcliffe 7,301 897 12,687
Robert H. Haubein, Jr. 6,647 897 6,149
Gene R. Hodges 7,200 897 5,162
Thomas A. Fanning 7,200 897 4,299
William C. Archer 5,838 897 5,109
4 Mr. Franklin resigned as President and Chief Executive Officer of GEORGIA to become Chief Operating Officer of SOUTHERN
effective June, 1999. He was replaced by Mr. Ratcliffe effective June, 1999.
5 Mr. Fanning was named an executive officer effective June 12, 1999.
III-15
GULF
SUMMARY COMPENSATION TABLE
ANNUAL COMPENSATION LONG-TERM COMPENSATION
Number of
Securities Long-
Name Underlying Term
and Other Annual Stock Incentive All Other
Principal Compensation Options Payouts Compensation
Position Year Salary($) Bonus($) ($)1 (Shares) ($)2 ($)3
- ------------------------------------------------------------------------------------------------------------------------
Travis J. Bowden
President, 1999 332,482 40,229 10,199 14,514 251,300 18,171
Chief Executive 1998 329,280 35,121 3,839 13,583 218,175 18,068
Officer, Director 1997 306,584 33,933 2,842 16,694 207,322 17,888
Arlan E. Scarbrough 1999 199,142 14,839 6,557 7,181 111,258 10,641
Vice President 1998 196,661 18,071 3,253 6,721 96,594 10,218
1997 180,642 18,212 1,440 8,142 84,048 10,235
John E. Hodges, Jr. 1999 194,832 14,518 8,556 7,026 111,258 10,470
Vice President 1998 192,765 17,680 915 6,575 96,594 10,014
1997 178,428 17,989 2,418 8,042 91,977 10,185
Francis M. 1999 177,934 13,259 6,508 6,417 111,258 9,558
Fisher, Jr. 1998 175,719 16,147 240 6,005 96,594 9,329
Vice President 1997 160,783 16,274 479 7,275 84,048 9,182
Robert G. Moore 1999 161,641 22,981 13,949 5,829 97,722 8,569
Vice President 1998 159,332 18,626 525 4,881 72,767 8,325
1997 149,926 23,474 - 4,741 46,551 7,550
1 Tax reimbursement by GULF on certain personal benefits.
2 Payouts made in 1998, 1999 and 2000 for the four-year performance periods ending December 31, 1997,
1998 and 1999, 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 $6,779 $897 $10,495
Arlan E. Scarbrough 6,526 897 3,218
John E. Hodges, Jr. 6,390 897 3,183
Francis M. Fisher, Jr. 6,276 897 2,385
Robert G. Moore 6,699 897 973
III-16
MISSISSIPPI
SUMMARY COMPENSATION TABLE
ANNUAL COMPENSATION LONG-TERM COMPENSATION
Number of
Securities Long-
Name Underlying Term
and Other Annual Stock Incentive All Other
Principal Compensation Options Payouts Compensation
Position Year Salary($) Bonus($) ($)1 (Shares) ($)2 ($)3
- ------------------------------------------------------------------------------------------------------------------------
Dwight H. Evans
President, Chief 1999 288,494 43,702 3,375 12,614 251,300 15,507
Executive 1998 283,195 42,603 5,051 11,693 218,175 15,291
Officer, Director 1997 262,678 39,643 3,830 14,303 126,075 15,025
H. E. Blakeslee 1999 207,769 37,649 8,070 7,481 111,258 11,254
Vice President 1998 207,416 36,202 47 7,068 96,594 10,979
1997 192,029 38,863 697 8,687 91,977 10,991
Andrew J.
Dearman, III 4 1999 173,490 71,648 10,527 5,843 103,585 8,543
Vice President 1998 159,713 41,031 600 4,893 83,087 8,343
1997 141,393 21,008 2,083 5,871 42,903 21,354
Don E. Mason 1999 203,584 36,891 821 7,330 111,258 10,243
Vice President 1998 203,234 29,560 4,497 6,926 96,594 10,757
1997 188,126 41,889 839 8,512 84,048 10,675
Michael W. Southern
Vice President
Chief Financial 1999 189,117 34,369 8,891 6,469 103,585 9,590
Officer, Secretary, 1998 174,334 34,130 - 5,997 83,087 8,978
Treasurer 1997 155,151 31,406 1,590 6,281 65,768 8,757
Mark S. Lynch 5 1999 174,833 18,940 16 6,178 111,258 9,566
Vice President 1998 - - - - - -
1997 - - - - - -
1 Tax reimbursement by MISSISSIPPI on certain personal benefits.
2 Payouts made in 1998, 1999 and 2000 for the four-year performance periods ending December 31, 1997,
1998 and 1999, 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 $6,697 $897 $7,913
H. E. Blakeslee 5,691 897 4,666
Andrew J. Dearman, III 6,567 897 1,079
Don E. Mason 5,691 897 3,655
Michael W. Southern 5,691 897 3,002
Mark S. Lynch 7,200 897 1,469
4 Effective September 1999, Mr. Dearman transferred to Southern Energy into the position of Senior Vice President and Chief
Technical Officer.
5 Mr. Lynch was named an executive officer effective October 1, 1999.
III-17
SAVANNAH
SUMMARY COMPENSATION TABLE
ANNUAL COMPENSATION LONG-TERM COMPENSATION
Number of
Securities Long-
Name Underlying Term
and Other Annual Stock Incentive All Other
Principal Compensation Options Payouts Compensation
Position Year Salary($) Bonus($) ($)1 (Shares) ($)2 ($)3
- ---------------------------------------------------------------------------------------------------------------------------
G. Edison
Holland, Jr.
President, 1999 254,914 42,626 21,588 8,375 166,052 13,392
Chief Executive 1998 233,330 26,019 17,309 7,951 128,608 8,246
Officer, Director 1997 202,413 26,231 3,046 8,640 91,977 49,892
W. Miles Greer 1999 168,713 21,322 1,874 6,130 79,476 15,150
Vice President 1998 160,207 16,054 13 4,901 69,000 13,179
1997 138,643 16,294 805 4,924 60,636 10,740
Kirby R. Willis
Vice President, 1999 156,068 19,546 259 5,028 79,476 11,767
Chief Financial 1998 155,236 15,554 13 4,748 69,000 10,581
Officer, Treasurer 1997 134,794 15,915 182 4,809 60,636 9,322
Lewis A. Jeffers 4 1999 134,538 19,023 379 3,809 63,146 6,972
Vice President 1998 - - - - - -
1997 - - - - - -
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 1998, 1999 and 2000 for the four-year performance periods ending December 31, 1997, 1998
and 1999, respectively.
3 SAVANNAH contributions to the ESP, under Section 401(k) of the Internal Revenue Code, ESOP, and SBP or AME for
the following:-
Name ESP ESOP SBP or AME
G. Edison Holland, Jr. $6,983 $897 $5,512
W. Miles Greer 6,698 897 7,555
Kirby R. Willis 5,674 897 5,196
Lewis A. Jeffers 6,036 897 39
In 1997, Mr. Holland received a one-time lump-sum payment of $38,654, given in connection with his appointment
to his current position.
4 Mr. Jeffers was named an executive officer effective November 2, 1999.
III-18
STOCK OPTION GRANTS IN 1999
Stock Option Grants. The following table sets forth all stock option grants to
the named executive officers of each operating subsidiary during the year ending
December 31, 1999.
Individual Grants Grant Date Value
# of % of Total
Securities Options Exercise
Underlying Granted to or
Options Employees in Base Price Expiration Grant Date
Name Granted1 Fiscal Year2 ($/Sh)1 Date1 Present Value($)3
-----------------------------------------------------------------------------------------------------------
ALABAMA
Elmer B. Harris 31,341 1.5 26.5625 05/01/2009 197,135
Banks H. Farris 13,485 0.6 26.5625 06/01/2005 59,873
William B. Hutchins, III 11,246 0.5 26.5625 07/19/2009 70,737
Michael D. Garrett 11,249 0.5 26.5625 07/19/2009 70,756
Jerry L. Stewart 6,340 0.3 26.5625 07/19/2009 39,879
GEORGIA
H. Allen Franklin 71,153 3.4 26.5625 07/19/2009 447,552
David M. Ratcliffe 24,110 1.1 26.5625 07/19/2009 151,652
Robert H. Haubein, Jr. 11,209 0.5 26.5625 07/19/2009 70,505
Gene R. Hodges 10,604 0.5 26.5625 04/01/2008 62,352
Thomas A. Fanning 10,458 0.5 26.5625 07/19/2009 65,781
William C. Archer 7,972 0.4 26.5625 07/19/2009 50,144
GULF
Travis J. Bowden 14,514 0.7 26.5625 09/01/2008 85,342
Arlan E. Scarbrough 7,181 0.3 26.5625 11/01/2006 35,618
John E. Hodges, Jr. 7,026 0.3 26.5625 07/19/2009 44,194
Francis M. Fisher, Jr. 6,417 0.3 26.5625 07/19/2009 40,363
Robert G. Moore 5,829 0.3 26.5625 07/19/2009 36,664
See next page for footnotes.
III-19
STOCK OPTION GRANTS IN 1999
Individual Grants Grant Date Value
# of % of Total
Securities Options Exercise
Underlying Granted to or
Options Employees in Base Price Expiration Grant Date
Name Granted1 Fiscal Year2 ($/Sh)1 Date1 Present Value($)3
-----------------------------------------------------------------------------------------------------------
MISSISSIPPI
Dwight H. Evans 12,614 0.6 26.5625 07/19/2009 79,342
H. E. Blakeslee 7,481 0.4 26.5625 07/19/2009 47,055
Andrew J. Dearman, III 5,843 0.3 26.5625 07/19/2009 36,752
Don E. Mason 7,330 0.3 26.5625 07/19/2009 46,106
Michael W. Southern 6,469 0.3 26.5625 07/19/2009 40,690
Mark S. Lynch 6,178 0.3 26.5625 07/19/2009 38,860
SAVANNAH
G. Edison Holland, Jr. 8,375 0.4 26.5625 07/19/2009 52,679
W. Miles Greer 6,130 0.3 26.5625 07/19/2009 38,558
Kirby R. Willis 5,028 0.2 26.5625 07/19/2009 31,626
Lewis A. Jeffers 3,809 0.2 26.5625 07/19/2009 23,959
1 Performance Stock Plan grants were made on July 19, 1999, and vest annually at a rate of one-third on the anniversary date of
the grant. Grants fully vest upon termination because of death, total disability, or retirement and expire the earlier of five
years after such event or their normal expiration date. The exercise price is the average of the high and low fair market value
of SOUTHERN's common stock on the date granted. Options may be transferred to family trusts and family limited partnerships. In
accordance with the terms of the Performance Stock Plan, Mr. Bowden's unexercised options expire on September 1, 2008, five years
after his normal retirement date; Mr. Farris' unexercised options expire on June 1, 2005, five years after his normal retirement
date; Mr. Harris' unexercised options expire on May 1, 2009, five years after his normal retirement date; Mr. Gene R. Hodges'
unexercised options expire on April 1, 2008, five years after his normal retirement date; and Mr. Scarbrough's unexercised
options expire on November 1, 2006, five years after his normal retirement date.
2 A total of 2,108,818 stock options were granted in 1999.
3 Value was calculated using the Black-Scholes option valuation model. The actual value, if any, ultimately realized depends on
the market value of SOUTHERN's common stock at a future date. Significant assumptions used to calculate this value: price
volatility - 20.74%; risk-free rate of return - 5.79%; dividend opportunity -50%; time to exercise - 10 years; reductions for
probability of forfeiture before vesting - 7.79%; and reductions for probability of forfeiture before expiration - 13.40%. 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 1999 AND YEAR-END OPTION VALUES
Aggregated Stock Option Exercises. The following table sets forth information
concerning options exercised during the year ending December 31, 1999, by the
named executive officers and the value of unexercised options held by them as of
December 31, 1999.
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($)2 Unexercisable Unexercisable
- -------------------------------------------------------------------------------------------------------------
ALABAMA
Elmer B. Harris 4,718 71,802 219,394/70,733 915,188/30,688
Banks H. Farris - - 38,372/28,070 66,409/11,351
William B. Hutchins, III - - 43,701/22,100 113,519/8,458
Michael D. Garrett - - 11,596/20,918 16,443/6,946
Jerry L Stewart - - 16,843/14,169 23,814/6,151
GEORGIA
H. Allen Franklin - - 191,114/111,645 700,904/31,389
David M. Ratcliffe 3,984 53,908 85,160/42,959 307,716/14,711
Robert H. Haubein, Jr. - - 37,975/22,166 81,698/8,558
Gene R. Hodges - - 38,577/21,876 81,361/8,856
Thomas A. Fanning - - 16,422/20,560 22,818/7,872
William C. Archer - - 20,538/17,833 28,079/7,690
GULF
Travis J. Bowden - - 19,094/32,878 24,772/14,393
Arlan E. Scarbrough - - 9,292/16,184 12,007/7,011
John E. Hodges, Jr. - - 24,796/15,877 38,885/6,926
Francis M. Fisher, Jr. - - 7,853/14,264 10,158/6,166
Robert G. Moore - - 12,039/11,680 16,514/4,064
See next page for footnotes.
III-21
AGGREGATED STOCK OPTION EXERCISES IN 1999 AND YEAR-END OPTION VALUES
Number of
Securities Value of
Underlying Unexercised
Unexercised In-the-Money
Options at Options at
Fiscal Fiscal
Year-End (#) Year-End($)1
Shares Acquired Value Exercisable/ Exercisable/
Name on Exercise (#) Realized($)2 Unexercisable Unexercisable
- --------------------------------------------------------------------------------------------------------------
MISSISSIPPI
Dwight H. Evans - - 55,961/28,385 136,976/12,332
H. E. Blakeslee - - 31,701/16,982 66,471/7,463
Andrew J. Dearman, III - - 12,920/12,108 18,323/4,926
Don E. Mason - - 20,994/16,639 29,511/7,311
Michael W. Southern - - 15,139/13,930 20,562/5,396
Mark S. Lynch - - 10,336/13,490 11,447/5,367
SAVANNAH
G. Edison Holland, Jr. - - 40,342/18,475 105,982/7,440
W. Miles Greer - - 12,505/12,104 17,221/4,225
Kirby R. Willis - - 11,770/10,777 16,256/4,097
Lewis A. Jeffers - - 0/3,809 0/0
1 This represents the excess of the fair market value of SOUTHERN's common stock of $23.50 per share, as of December 31, 1999,
above the exercise price of the options. The Exercisable column reports the "value" of options that are vested and therefore
could be exercised. The Unexercisable column reports the "value" of options that are not vested and therefore could not be
exercised as of December 31, 1999.
2 The "Value Realized" is ordinary income, before taxes, and represents the amount equal to the excess of the fair market value
of the shares at the time of exercise over the exercise price.
III-22
LONG-TERM INCENTIVE PLANS - AWARDS IN 1999
Long-Term Incentive Plans. The following table sets forth the long-term
incentive plan awards made to the named executive officers for the performance
period January 1, 1999 through December 31, 2002.
Estimated Future Payouts under
Non-Stock Price-Based Plans
Performance or
Other Period
Number of Until Maturation Threshold Target Maximum
Name Units (#)1 or Payout ($)2 ($)2 ($)2
- ---------------------------------------------------------------------------------------------------------------
ALABAMA
Elmer B. Harris 321,879 4 years 160,940 321,879 643,758
Banks H. Farris 128,474 4 years 64,237 128,474 256,948
William B. Hutchins, III 95,170 4 years 47,585 95,170 190,340
Michael D. Garrett 82,601 4 years 41,301 82,601 165,203
Jerry L. Stewart 76,095 4 years 38,048 76,095 152,190
GEORGIA
H. Allen Franklin 438,499 4 years 219,250 438,499 876,998
David M. Ratcliffe 200,827 4 years 100,414 200,827 401,654
Robert H. Haubein, Jr. 95,170 4 years 47,585 95,170 190,340
Gene R. Hodges 95,170 4 years 47,585 95,170 190,340
Thomas A. Fanning 95,170 4 years 47,585 95,170 190,340
William C. Archer 95,170 4 years 47,585 95,170 190,340
GULF
Travis J. Bowden 156,741 4 years 78,370 156,741 313,482
Arlan E. Scarbrough 69,394 4 years 34,697 69,394 138,788
John E. Hodges, Jr. 69,394 4 years 34,697 69,394 138,788
Francis M. Fisher, Jr. 69,394 4 years 34,697 69,394 138,788
Robert G. Moore 60,952 4 years 30,476 60,952 121,903
See next page for footnotes.
III-23
LONG-TERM INCENTIVE PLANS - AWARDS IN 1999
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 156,741 4 years 78,370 156,741 313,482
H. E. Blakeslee 69,394 4 years 34,697 69,394 138,788
Andrew J. Dearman, III 64,608 4 years 32,304 64,608 129,215
Don E. Mason 69,394 4 years 34,697 69,394 138,788
Michael W. Southern 64,608 4 years 32,304 64,608 129,215
Mark S. Lynch 69,394 4 years 34,697 69,394 138,788
SAVANNAH
G. Edison Holland, Jr. 103,570 4 years 51,785 103,570 207,139
W. Miles Greer 49,571 4 years 24,786 49,571 99,142
Kirby R. Willis 49,571 4 years 24,786 49,571 99,142
Lewis A. Jeffers 39,385 4 years 19,692 39,385 78,770
1 A performance unit is a method of assigning a dollar value to a performance award opportunity. Under the
Executive Productivity Improvement Plan, the number of units granted to Messrs. Harris and Franklin is 65% of the average of
Messrs. Harris' and Franklin's base salary range 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 50 percent, 100 percent and 200 percent, respectively. These
percentages 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 annual pension
benefits payable at normal retirement age under SOUTHERN's qualified Pension
Plan, as well as supplemental benefits, based on the stated compensation and
years of service with the SOUTHERN system for the named executives at ALABAMA,
GEORGIA, GULF and MISSISSIPPI and Mr. Holland at SAVANNAH. Compensation 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, 1999, 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 $878,724 40
Banks H. Farris 429,312 40
William B. Hutchins, III 348,304 33
Michael D. Garrett 309,688 31
Jerry L. Stewart 257,848 26
III-25
GEORGIA
Compensation Accredited
Name Level Years of Service
H. Allen Franklin $967,132 28
David M. Ratcliffe 583,968 28
Robert H. Haubein, Jr. 344,444 32
Gene R. Hodges 356,788 35
Thomas A. Fanning 329,728 18
William C. Archer 323,200 28
GULF
Compensation Accredited
Name Level Years of Service
Travis J. Bowden1 $505,372 33
Arlan E. Scarbrough 257,876 36
John E. Hodges, Jr. 257,548 33
Francis M. Fisher, Jr. 240,780 28
Robert G. Moore 210,200 26
MISSISSIPPI
Compensation Accredited
Name Level Years of Service
Dwight H. Evans $448,124 28
H. E. Blakeslee 288,660 34
Andrew J. Dearman, III 229,043 24
Don E. Mason 281,516 33
Michael W. Southern 244,592 24
Mark S. Lynch 262,193 10
SAVANNAH
Compensation Accredited
Name Level Years of Service
G. Edison Holland, Jr.2 $336,428 16
W. Miles Greer 157,144 15
Kirby R. Willis 149,479 25
Lewis A. Jeffers 124,064 20
1 The number of accredited years of service includes 10 years credited to
Mr. Bowden pursuant to a supplemental pension agreement.
2 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 the
SOUTHERN 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 1999 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
320,000 224,000 224,000 224,000
340,000 238,000 238,000 238,000
III-27
Compensation of Directors.
Standard Arrangements. The following table presents compensation paid
to the directors, during 1999 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, 1999 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 still employed by SOUTHERN or one of its subsidiaries, Mr.
Franklin 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. GEORGIA assigned this agreement to SCS
effective July 8, 1999.
Report on Repricing of Options.
None.
Compensation Committee Interlocks and Insider Participation.
None.
III-29
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, 1999. 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, 1999.
Name of Directors,
Nominees and Number of Shares
Executive Officers Title of Class Beneficially Owned (1) (2)
- ------------------ -------------- --------------------------
ALABAMA
Whit Armstrong SOUTHERN Common 17,972
David J. Cooper, Sr. SOUTHERN Common 1,191
H. Allen Franklin SOUTHERN Common 220,337
Elmer B. Harris SOUTHERN Common 260,741
R. Kent Henslee SOUTHERN Common 4,019
Carl E. Jones, Jr. SOUTHERN Common 12,249
Patricia M. King SOUTHERN Common 306
James K. Lowder SOUTHERN Common 6,241
III-30
Name of Directors,
Nominees and Number of Shares
Executive Officers Title of Class Beneficially Owned (1) (2)
- ------------------ -------------- --------------------------
Wallace D. Malone, Jr. SOUTHERN Common 627
Thomas C. Meredith SOUTHERN Common 416
Mayer Mitchell SOUTHERN Common 19
William V. Muse SOUTHERN Common 726
John T. Porter SOUTHERN Common 1,181
Robert D. Powers SOUTHERN Common 726
Andreas Renschler SOUTHERN Common 1,223
C. Dowd Ritter SOUTHERN Common 306
James H. Sanford SOUTHERN Common 658
John C. Webb, IV SOUTHERN Common 12,925
Banks H. Farris SOUTHERN Common 43,485
Michael D. Garrett SOUTHERN Common 18,216
William B. Hutchins, III SOUTHERN Common 59,771
C. Alan Martin SOUTHERN Common 5,320
Jerry L. Stewart SOUTHERN Common 24,221
The directors, nominees,
and executive officers
as a group SOUTHERN Common 692,874
GEORGIA
Daniel P. Amos SOUTHERN Common 297
Juanita P. Baranco SOUTHERN Common 297
W. A. Fickling, Jr. SOUTHERN Common 1,245
III-31
Name of Directors,
Nominees and Number of Shares
Executive Officers Title of Class Beneficially Owned (1) (2)
- ------------------ -------------- --------------------------
H. Allen Franklin SOUTHERN Common 220,337
L. G. Hardman III SOUTHERN Common 17,422
James R. Lientz, Jr. SOUTHERN Common 1,271
Zell Miller SOUTHERN Common 373
G. Joseph Prendergast SOUTHERN Common 1,331
Herman J. Russell SOUTHERN Common 2,962
W. J. Vereen SOUTHERN Common 5,628
Carl Ware SOUTHERN Common 800
William C. Archer, III SOUTHERN Common 27,794
Thomas A. Fanning SOUTHERN Common 23,726
Robert H. Haubein, Jr. SOUTHERN Common 40,381
Gene R. Hodges SOUTHERN Common 56,540
David M. Ratcliffe SOUTHERN Common 95,158
The directors, nominees
and executive officers
as a group SOUTHERN Common 629,177
GULF
Travis J. Bowden SOUTHERN Common 29,368
Fred C. Donovan, Sr. SOUTHERN Common 526
H. Allen Franklin SOUTHERN Common 220,337
W. Deck Hull, Jr. SOUTHERN Common 3,164
Joseph K. Tannehill SOUTHERN Common 4,541
III-32
Name of Directors,
Nominees and Number of Shares
Executive Officers Title of Class Beneficially Owned (1) (2)
- ------------------ -------------- --------------------------
Barbara H. Thames SOUTHERN Common 247
Francis M. Fisher, Jr. SOUTHERN Common 14,873
John E. Hodges, Jr. SOUTHERN Common 48,551
Robert G. Moore SOUTHERN Common 24,517
Arlan E. Scarbrough SOUTHERN Common 26,396
The directors, nominees
and executive officers
as a group SOUTHERN Common 372,520
MISSISSIPPI
Edwin E. Downer SOUTHERN Common 5,289
Dwight H. Evans SOUTHERN Common 79,309
Robert S. Gaddis SOUTHERN Common 2,143
Linda T. Howard SOUTHERN Common 66
Malcolm Portera SOUTHERN Common 59
George A. Schloegel SOUTHERN Common 589
Philip J. Terrell SOUTHERN Common 945
N. Eugene Warr SOUTHERN Common 1,081
H. E. Blakeslee SOUTHERN Common 36,328
Mark S. Lynch SOUTHERN Common 70
Don E. Mason SOUTHERN Common 45,019
Michael W. Southern SOUTHERN Common 19,730
The directors, nominees
and executive officers
as a group SOUTHERN Common 190,628
III-33
Name of Directors,
Nominees and Number of Shares
Executive Officers Title of Class Beneficially Owned (1) (2)
- ------------------ -------------- --------------------------
SAVANNAH
Gus H. Bell, III SOUTHERN Common 38
Archie H. Davis SOUTHERN Common 275
Walter D. Gnann SOUTHERN Common 1,757
G. Edison Holland, Jr. SOUTHERN Common 43,065
Robert B. Miller, III SOUTHERN Common 536
Arnold M. Tenenbaum SOUTHERN Common 890
Lewis A. Jeffers SOUTHERN Common 7,923
W. Miles Greer SOUTHERN Common 15,900
Kirby R. Willis SOUTHERN Common 17,992
The directors, nominees
and executive officers
as a group SOUTHERN Common 88,377
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, 31,701 shares; Mr. Evans, 55,961 shares; Mr. Farris, 38,372
shares; Mr. Franklin, 191,114 shares; Mr. Greer, 12,505 shares; Mr. Harris,
219,394 shares; Mr. Haubein, 37,975 shares; Mr. G. R. Hodges, 38,577
shares; Mr. J. E. Hodges, 24,796 shares; Mr. Holland, 40,342 shares; Mr.
Hutchins, 43,701 shares; Mr. Mason, 20,994 shares; Mr. Southern, 15,139
shares, and Mr. Willis, 11,770 shares. Also included are shares of
SOUTHERN common stock held by the spouses of the following directors: Mr.
Gaddis, 1,200 shares; Mr. Hardman, 100 shares; and Mr. Harris, 310 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, 7,461 shares.
III-34
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
and Chief Executive Officer of AmSouth Bancorporation and AmSouth Bank,
Birmingham, Alabama. During 1999, 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 Bank of America
Mid-South Banking Group, Atlanta, Georgia; Mr. G. Joseph Prendergast is
President and Chief Operating Officer, Wachovia Corporation and Wachovia Bank,
N.A., Winston Salem, North Carolina, and Mr. Herman J. Russell is Chairman of
the Board of Citizens Trust Bank, Atlanta, Georgia. During 1999, 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 1999, GEORGIA leased a building from Riverside Manufacturing Co. for
$86,925. Also, Riverside Manufacturing sold to GEORGIA fire retardant uniforms
for $134,464. 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.
In 1999, GULF paid to Merrick Industries, Inc. and Merrick Environmental
Technology, Inc., $560,712 for coal handling equipment and air pollution control
equipment. Mr. Tannehill is Chairman and Chief Executive Officer of both
companies.
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 1999, 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-35
SAVANNAH
Transactions with management and others.
Mr. Archie Davis is President of The Savannah Bank, N.A., Savannah,
Georgia; During 1999, this bank furnished a number of regular banking services
in the ordinary course of business to SAVANNAH. SAVANNAH intends to maintain
normal banking relations with the aforesaid bank in the future.
Certain business relationships.
None.
Indebtedness of management.
None.
Transactions with promoters.
None.
III-36
PART IV
Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) The following documents are filed as a part of this report on this Form
10-K:
(1) Financial Statements:
Reports of Independent Public Accountants on the financial statements
for SOUTHERN and Subsidiary Companies, ALABAMA, GEORGIA, GULF,
MISSISSIPPI and SAVANNAH are listed under Item 8 herein.
The financial statements filed as a part of this report for SOUTHERN
and Subsidiary Companies, ALABAMA, GEORGIA, GULF, MISSISSIPPI and
SAVANNAH are listed under Item 8 herein.
(2) Financial Statement Schedules:
Reports of Independent Public Accountants as to Schedules for SOUTHERN
and Subsidiary Companies, ALABAMA, GEORGIA, GULF, MISSISSIPPI and
SAVANNAH are included herein on pages IV-11 through IV-16.
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 1999 were as follows:
None.
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 and
Chief Executive Officer
By: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 24, 2000
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 and
Chief Executive Officer
(Principal Executive Officer)
W. L. Westbrook
Financial Vice President, Chief Financial Officer and
Treasurer
(Principal Financial and Accounting Officer)
Directors:
Dorrit J. Bern Elmer B. Harris
Thomas F. Chapman Donald M. James
A. D. Correll David J. Lesar
H. Allen Franklin Zack T. Pate
L. G. Hardman III Gerald J. St. Pe'
By: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 24, 2000
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, 2000
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, and Comptroller
(Principal Accounting Officer)
Directors:
Whit Armstrong Thomas C. Meredith
David J. Cooper Mayer Mitchell
H. Allen Franklin William V. Muse
R. Kent Henslee John T. Porter
Carl E. Jones, Jr. Robert D. Powers
Patricia M. King C. Dowd Ritter
James K. Lowder James H. Sanford
Wallace D. Malone, Jr. John Cox Webb, IV
By: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 24, 2000
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: David M. Ratcliffe, President and
Chief Executive Officer
By: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 24, 2000
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities and on the dates indicated. The signature of each of the
undersigned shall be deemed to relate only to matters having reference to the
above-named company and any subsidiaries thereof.
David M. Ratcliffe
President, Chief Executive Officer and Director
(Principal Executive Officer)
Thomas A. Fanning
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:
Daniel P. Amos Zell Miller
Juanita P. Baranco G. Joseph Prendergast
William A. Fickling, Jr. Herman J. Russell
H. Allen Franklin William Jerry Vereen
L. G. Hardman III Carl Ware
James R. Lientz, Jr.
By: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 24, 2000
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, 2000
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:
Fred C. Donovan, Sr. Joseph K. Tannehill
H. Allen Franklin Barbara H. Thames
W. Deck Hull, Jr.
By: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 24, 2000
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, 2000
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:
Edwin E. Downer Malcolm Portera
Robert S. Gaddis George A. Schloegel
Linda T. Howard Philip J. Terrell
Aubrey K. Lucas Gene Warr
By: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 24, 2000
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, 2000
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:
Gus H. Bell, III Robert B. Miller, III
Archie H. Davis Arnold M. Tenenbaum
Walter D. Gnann
By: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 24, 2000
IV-4
Arthur Andersen LLP
Exhibit 23(a)
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation
of our reports dated February 16, 2000 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,
333-64871 and 333-31808.
/s/ Arthur Andersen LLP
Atlanta, Georgia
March 22, 2000
IV-5
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 16, 2000 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 No. 333-67453.
/s/ Arthur Andersen LLP
Birmingham, Alabama
March 22, 2000
IV-6
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 16, 2000 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 Nos. 333-43895 and 333-75193.
/s/ Arthur Andersen LLP
Atlanta, Georgia
March 22, 2000
IV-7
Arthur Andersen LLP
Exhibit 23(d)
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation
of our reports dated February 16, 2000 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, 2000
IV-8
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 16, 2000 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, 2000
IV-9
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 16, 2000 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, 2000
IV-10
Arthur Andersen LLP
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULE
To The Southern Company:
We have audited in accordance with auditing standards generally accepted in
the United States, the consolidated financial statements of The Southern Company
and its subsidiaries included in this Form 10-K, and have issued our report
thereon dated February 16, 2000. 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 16, 2000
IV-11
Arthur Andersen LLP
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULE
To Alabama Power Company:
We have audited in accordance with auditing standards generally accepted in
the United States, the financial statements of Alabama Power Company included in
this Form 10-K, and have issued our report thereon dated February 16, 2000. 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 16, 2000
IV-12
Arthur Andersen LLP
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULE
To Georgia Power Company:
We have audited in accordance with auditing standards generally accepted
in the United States, the financial statements of Georgia Power Company included
in this Form 10-K, and have issued our report thereon dated February 16, 2000.
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 16, 2000
IV-13
Arthur Andersen LLP
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULE
To Gulf Power Company:
We have audited in accordance with auditing standards generally accepted in
the United States, the financial statements of Gulf Power Company included in
this Form 10-K, and have issued our report thereon dated February 16, 2000. 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 16, 2000
IV-14
Arthur Andersen LLP
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULE
To Mississippi Power Company:
We have audited in accordance with auditing standards generally accepted in
the United States, the financial statements of Mississippi Power Company
included in this Form 10-K, and have issued our report thereon dated February
16, 2000. 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 16, 2000
IV-15
Arthur Andersen LLP
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AS TO SCHEDULE
To Savannah Electric and Power Company:
We have audited in accordance with auditing standards generally accepted in
the United States, the financial statements of Savannah Electric and Power
Company included in this Form 10-K, and have issued our report thereon dated
February 16, 2000. 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 16, 2000
IV-16
INDEX TO FINANCIAL STATEMENT SCHEDULES
Schedule Page
II Valuation and Qualifying Accounts and Reserves
1999, 1998 and 1997
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, 1999, 1998 AND 1997
(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
1999.......................... $112,511 $55,042 $(11,805) $96,838 (1) $ 58,910
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
- -------------------
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, 1999, 1998 AND 1997
(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
1999.......................... $1,855 $13,995 $- $11,733 (Note) $4,117
1998.......................... 2,272 7,702 - 8,119 (Note) 1,855
1997.......................... 1,171 8,580 - 7,479 (Note) 2,272
- -------------------
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, 1999, 1998 AND 1997
(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
1999.......................... $5,500 $14,406 $- $12,906 (Note) $7,000
1998.......................... 3,000 17,856 - 15,356 (Note) 5,500
1997.......................... 4,000 7,888 - 8,888 (Note) 3,000
- -------------------
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, 1999, 1998 AND 1997
(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
1999.......................... $996 $2,230 $- $2,200 (Note) $1,026
1998.......................... 796 2,288 - 2,088 (Note) 996
1997.......................... 789 1,350 - 1,343 (Note) 796
- -------------------
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, 1999, 1998 AND 1997
(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
1999.......................... $621 $1,964 $ - $1,888 (Note) $697
1998.......................... 698 1,510 31 1,618 (Note) 621
1997.......................... 839 1,128 56 1,325 (Note) 698
- -------------------
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, 1999, 1998 AND 1997
(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
1999.......................... $284 $594 $- $641 (Note) $237
1998.......................... 354 417 - 487 (Note) 284
1997.......................... 632 192 - 470 (Note) 354
- -------------------
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
December 2, 1998. (Designated in Registration Nos.
33-25183 as Exhibit 4(b)-(1), 33-45757 as Exhibit 4
(b)-(2), in Form 8-K dated November 9, 1993, File No.
1-5072, as Exhibit 4(b) and in SAVANNAH's Form 10-K
for the year ended December 31, 1998, as
Exhibit 3(f)2.)
(f) 2 - By-laws of SAVANNAH as amended effective February 16,
1994, and as presently in effect. (Designated in
SAVANNAH's Form 10-K for the year ended December 31,
1993, as Exhibit 3(f)2.)
(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.)
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(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.)
(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.)
E-4
(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 September 30, 1999. (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, in Form 8-K dated November 12, 1998, File
No. 1-3164, as Exhibit 4.2, in Form 8-K dated May 19,
1999, File No. 1-3164, as Exhibit 4.2, in Form 8-K
dated August 13, 1999, File No. 1-3164, as Exhibit 4.2
and in Form 8-K dated September 21, 1999, 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.)
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),
E-5
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, 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.)
E-6
(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 February 22, 2000. (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, in Form 8-K dated March 3, 1999, File No. 1-6469 as
Exhibit 4.2 and in Form 8-K dated February 15, 2000, 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 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.)
E-7
(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 August 24, 1999. (Designated in Form 8-K dated June 17,
1998, File No. 0-2429, as Exhibits 4.1 and 4.2 and in Form 8-K dated August 17, 1999, File No. 0-2429, as
Exhibit 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 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-8
(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.)
(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.)
E-9
(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).)
(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).)
E-10
(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).)
(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.)
E-11
(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).)
(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.)
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(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).)
(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).)
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(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 - Long Term Transaction Service Agreement between GEORGIA and OPC dated as of February 29, 1999.
(a) 47 - 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) 48 - 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.)
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(a) 49 - 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) 50 - 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) 51 - 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) 52 - 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) 53 - 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) 54 - 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) 55 - 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) 56 - Power Purchase Agreement dated as of December 3,
1993 between GEORGIA and FPC. (Designated in SOUTHERN's
Form 10-K for the year ended December 31, 1993, File
No. 1-3526, as Exhibit 10(a)59.)
(a) 57 - 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) 58 - The Southern Company Productivity Improvement Plan, Amended and Restated effective January 1, 1998.
(Designated in SOUTHERN's Form 10-K for the year ended December 31, 1998, File No. 1-3526 as
Exhibit 10(a)59.)
# * (a) 59 - The Southern Company Executive Productivity Improvement Plan, Amended and Restated effective
January 1, 1999.
E-15
(a) 60 - The Southern Company Employee Savings Plan, Amended and Restated effective January 1, 1997 and all
amendments thereto through Amendment Number Three. (Designated in SOUTHERN's Form 10-K for the year ended
December 31, 1998, File No. 1-3526 as Exhibit 10(a)61.)
* (a) 61 - Amendment Number Four and Amendment Number Five to The Southern Company Employee Savings Plan.
(a) 62 - The Southern Company Employee Stock Ownership Plan, Amended and Restated effective January 1, 1997 and all
amendments thereto through Amendment Number Two. (Designated in SOUTHERN's Form 10-K for the year ended
December 31, 1998, File No. 1-3526 as Exhibit 10(a)62.)
* (a) 63 - Amendment Number Three to The Southern Company Employee Stock Ownership Plan.
(a) 64 - The Southern Company Performance Pay Plan, Amended
and Restated effective January 1, 1998. (Designated in
SOUTHERN's Form 10-K for the year ended December 31,
1998, File No. 1-3526 as Exhibit 10(a)63.)
# * (a) 65 - The Deferred Compensation Plan for the Directors of The Southern Company, Amended and Restated effective
February 17, 1997.
# (a) 66 - 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) 67 - The Southern Company Deferred Compensation Plan, Amended and Restated effective January 1, 1998.
(Designated in SOUTHERN's Form 10-K for the year ended December 31, 1998, File No. 1-3526 as
Exhibit 10(a)66.)
# (a) 68 - 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) 69 - 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) 70 - The Southern Company Performance Dividend Plan, Amended and Restated effective January 1, 1999.
(a) 71 - The Southern Company Pension Plan, effective as of January 1, 1997 and all amendments thereto through
Amendment Number Three. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 1996, File No.
1-3526, as Exhibit 10(a)83, in SOUTHERN's Form 10-K for the year ended December 31, 1997, File No. 1-3526,
as Exhibit 10(a)79 and in SOUTHERN's Form 10-K for the year ended December 31, 1998, File No. 1-3526 as
Exhibit 10(a)71.)
* (a) 72 - Amendment Number Four to The Southern Company Pension Plan.
E-16
# (a) 73 - The Southern Company Performance Stock Plan, Amended and Restated effective July 19, 1999. (Designated in
Registration No. 333-31808 as Exhibit 4(c).)
# * (a) 74 - The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective
January 1, 1999.
# (a) 75 - The Southern Company Performance Sharing Plan effective January 1, 1997 and all amendments thereto through
Amendment Number Six. (Designated in SOUTHERN's Form 10-K for the year ended December 31, 1997, File No.
1-3526, as Exhibit 10(a)82 and in SOUTHERN's Form 10-K for the year ended December 31, 1998, File No.
1-3526 as Exhibit 10(a)76.)
# * (a) 76 - Amendment Number Seven to The Southern Company Performance Sharing Plan.
# (a) 77 - The Southern Company Supplemental Benefit Plan, Amended and Restated effective January 1, 1998. (Designated
in SOUTHERN's Form 10-K for the year ended December 31, 1998, File No. 1-3526 as Exhibit 10(a)77.)
# * (a) 78 - Amendment Number One to The Southern Company Supplemental Benefit Plan.
(a) 79 - Southern Company Change in Control Severance Plan, effective December 7, 1998. (Designated in SOUTHERN's
Form 10-K for the year ended December 31, 1998, File No. 1-3526 as Exhibit 10(a)78.)
* (a) 80 - Amendment Number One to Southern Company Change in Control Severance Plan.
# (a) 81 - Southern Company Executive Change in Control
Severance Plan, effective December 7, 1998. (Designated
in SOUTHERN's Form 10-K for the year ended December 31,
1998, File No. 1-3526 as Exhibit 10(a)79.)
# * (a) 82 - Amendment Number One to Southern Company Executive Change in Control Severance Plan.
# (a) 83 - Deferred Compensation Agreement between
SOUTHERN, GEORGIA and Henry Allen Franklin. (Designated
in SOUTHERN's Form 10-K for the year ended December 31,
1998, File No. 1-3526 as Exhibit 10(a)80.)
# * (a) 84 - Amendment Number One and Assignment to SCS of Deferred Compensation Agreement between SOUTHERN, GEORGIA and
Henry Allen Franklin.
# (a) 85 - Deferred Compensation Agreement between SOUTHERN, Southern Nuclear and William G. Hairston III. (Designated
in SOUTHERN's Form 10-K for the year ended December 31, 1998, File No. 1-3526 as Exhibit 10(a)81.)
# (a) 86 - Deferred Compensation Agreement between SOUTHERN, GEORGIA and Warren Y. Jobe. (Designated in SOUTHERN's
Form 10-K for the year ended December 31, 1998, File No. 1-3526 as Exhibit 10(a)82.)
# * (a) 87 - Deferred Compensation Agreement between SOUTHERN, Southern Energy Resources, Inc. and Gale E. Klappa and
First Amendment and Assignment to SCS.
E-17
# * (a) 88 - Deferred Compensation Agreement between SOUTHERN, Southern Energy Resources, Inc. and S. Marce Fuller.
# (a) 89 - Change in Control Agreement between SOUTHERN, GULF and Travis J. Bowden. (Designated in SOUTHERN's Form
10-K for the year ended December 31, 1998, File No. 1-3526 as Exhibit 10(a)84.)
# (a) 90 - Change in Control Agreement between SOUTHERN, SCS and A. W. Dahlberg. (Designated in SOUTHERN's Form 10-K
for the year ended December 31, 1998, File No. 1-3526 as Exhibit 10(a)85.)
# (a) 91 - Change in Control Agreement between SOUTHERN, MISSISSIPPI and Dwight H. Evans. (Designated in SOUTHERN's
Form 10-K for the year ended December 31, 1998, File No. 1-3526 as Exhibit 10(a)87.)
# (a) 92 - Change in Control Agreement between SOUTHERN, ALABAMA and Banks Harry Farris. (Designated in SOUTHERN's
Form 10-K for the year ended December 31, 1998, File No. 1-3526 as Exhibit 10(a)88.)
# * (a) 93 - Change in Control Agreement between SOUTHERN, SCS and Henry Allen Franklin.
# (a) 94 - Change in Control Agreement between SOUTHERN, Southern Nuclear and William G. Hairston, III. (Designated
in SOUTHERN's Form 10-K for the year ended December 31, 1998, File No. 1-3526 as Exhibit 10(a)90.)
# (a) 95 - Change in Control Agreement between SOUTHERN, ALABAMA and Elmer B. Harris. (Designated in SOUTHERN's Form
10-K for the year ended December 31, 1998, File No. 1-3526 as Exhibit 10(a)91.)
# (a) 96 - Change in Control Agreement between SOUTHERN, SAVANNAH and G. Edison Holland, Jr. (Designated in
SOUTHERN's Form 10-K for the year ended December 31, 1998, File No. 1-3526 as Exhibit 10(a)92.)
# (a) 97 - Change in Control Agreement between SOUTHERN, SCS and C. Alan Martin. (Designated in SOUTHERN's Form 10-K
for the year ended December 31, 1998, File No. 1-3526 as Exhibit 10(a)93.)
# (a) 98 - Change in Control Agreement between SOUTHERN, SCS and Charles Douglas McCrary. (Designated in SOUTHERN's
Form 10-K for the year ended December 31, 1998, File No. 1-3526 as Exhibit 10(a)94.)
# (a) 99 - Change in Control Agreement between SOUTHERN, GEORGIA and David M. Ratcliffe. (Designated in SOUTHERN's
Form 10-K for the year ended December 31, 1998, File No. 1-3526 as Exhibit 10(a)95.)
# (a) 100 - Change in Control Agreement between SOUTHERN, SCS and Stephen A. Wakefield. (Designated in SOUTHERN's Form
10-K for the year ended December 31, 1998, File No. 1-3526 as Exhibit 10(a)96.)
E-18
# (a) 101 - Change in Control Agreement between SOUTHERN, SCS and W. Lawrence Westbrook. (Designated in SOUTHERN's Form
10-K for the year ended December 31, 1998, File No. 1-3526 as Exhibit 10(a)97.)
# * (a) 102 - Change in Control Agreement between SOUTHERN, SCS and Gale E. Klappa.
# * (a) 103 - Change in Control Agreement between SOUTHERN, Southern Energy Resources, Inc. and S. Marce Fuller and First
Amendment thereto.
# * (a) 104 - Separation Agreement For Thomas G. Boren.
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.
(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.
E-19
(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 - Long Term Transmission Service Agreement between Entergy Power, Inc. and ALABAMA, MISSISSIPPI and SCS. See
Exhibit 10(a)52 herein.
(b) 17 - Operating Agreement for the Joseph M. Farley Nuclear Plant between ALABAMA and Southern Nuclear dated as
of December 23, 1991. See Exhibit 10(a)57 herein.
# (b) 18 - The Southern Company Productivity Improvement Plan, Amended and Restated effective January 1, 1998. See
Exhibit 10(a)58 herein.
# * (b) 19 - The Southern Company Executive Productivity Improvement Plan, Amended and Restated effective January 1,
1999. See Exhibit 10(a)59 herein.
(b) 20 - 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)60 herein.
* (b) 21 - Amendment Number Four and Amendment Number Five to The Southern Company Employee Savings Plan. 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 - Amendment Number Three to The Southern Company Employee Stock Ownership Plan. See Exhibit 10(a)63 herein.
(b) 24 - The Southern Company Performance Pay Plan, Amended and Restated effective January 1, 1998. See Exhibit
10(a)64 herein.
E-20
# (b) 25 - The Southern Company Deferred Compensation Plan, Amended and Restated effective January 1, 1998. See
Exhibit 10(a)67 herein.
# (b) 26 - The Southern Company Outside Directors Pension Plan. See Exhibit 10(a)66 herein.
# (b) 27 - Outside Directors Stock Plan for Subsidiaries of The Southern Company and First Amendment thereto. See
Exhibit 10(a)69 herein.
(b) 28 - The Southern Company Pension Plan, effective as of January 1, 1997 and all amendments thereto through
Amendment Number Three. See Exhibit 10(a)71 herein.
* (b) 29 - Amendment Number Four to The Southern Company Pension Plan. See Exhibit 10(a)72 herein.
# * (b) 30 - The Southern Company Performance Stock Plan, Amended and Restated effective July 19, 1999. See Exhibit
10(a)73 herein.
# * (b) 31 - The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective January 1,
1999. See Exhibit 10(a)74 herein.
# * (b) 32 - The Southern Company Performance Dividend Plan, Amended and Restated effective January 1, 1999. See
Exhibit 10(a)70 herein.
# (b) 33 - The Southern Company Performance Sharing Plan effective January 1, 1997 and all amendments thereto through
Amendment Number Six. See Exhibit 10(a)75 herein.
# * (b) 34 - Amendment Number Seven 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 - Amendment Number One to The Southern Company Supplemental Benefit Plan. See Exhibit 10(a)78 herein.
(b) 37 - Southern Company Change in Control Severance Plan, effective December 7, 1998. See Exhibit 10(a)79 herein.
* (b) 38 - Amendment Number One to Southern Company Change in Control Severance Plan. See Exhibit 10(a)80 herein.
# (b) 39 - Southern Company Executive Change in Control Severance Plan, effective December 7, 1998. See Exhibit
10(a)81 herein.
# * (b) 40 - Amendment Number One to Southern Company Executive Change in Control Severance Plan. See Exhibit 10(a)82
herein.
# (b) 41 - Change in Control Agreement between SOUTHERN, ALABAMA and Banks Harry Farris. See Exhibit 10(a)92 herein.
E-21
# (b) 42 - Change in Control Agreement between SOUTHERN, ALABAMA and Elmer B. Harris. See Exhibit 10(a)95 herein.
# (b) 43 - Supplemental Pension Agreement between ALABAMA, GULF and Travis J. Bowden. (Designated in ALABAMA's Form
10-K for the year ended December 31, 1998, File No. 1-3164, as Exhibit 10(b)40.)
# * (b) 44 - Deferred Compensation Plan for Directors of Alabama Power Company, Amended and Restated as of April 25,
1997.
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.
(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.
E-22
(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.
(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. 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.
E-23
(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.
(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)56 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.
E-24
(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 - Long Term Transaction Service Agreement between GEORGIA and OPC dated as of November 12, 1990. See Exhibit
10(a)46 herein.
(c) 41 - 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)47 herein.
(c) 42 - 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)48 herein.
(c) 43 - Integrated Transmission System Agreement, Power Sale and Coordination Umbrella Agreement between GEORGIA
and OPC dated as of November 12, 1990. See Exhibit 10(a)49 herein.
(c) 44 - Revised and Restated Integrated Transmission System Agreement between GEORGIA and Dalton dated as of
December 7, 1990. See Exhibit 10(a)50 herein.
(c) 45 - Revised and Restated Integrated Transmission System Agreement between GEORGIA and MEAG dated as of December
7, 1990. See Exhibit 10(a)51 herein.
(c) 46 - 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)53 herein.
(c) 47 - Plant McIntosh Combustion Turbine Purchase and Ownership Participation Agreement between GEORGIA and
SAVANNAH dated as of December 15, 1992. See Exhibit 10(a)54 herein.
(c) 48 - Plant McIntosh Combustion Turbine Operating Agreement between GEORGIA and SAVANNAH dated as of December 15,
1992. See Exhibit 10(a)55 herein.
(c) 49 - Certificate of Limited Partnership of Georgia Power Capital. (Designated in Certificate of Notification,
File No. 70-8461, as Exhibit B.)
(c) 50 - 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) 51 - 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.)
E-25
(c) 52 - 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) 53 - The Southern Company Productivity Improvement Plan, Amended and Restated effective January 1, 1998. See
Exhibit 10(a)58 herein.
# * (c) 54 - The Southern Company Executive Productivity Improvement Plan, Amended and Restated effective January 1,
1999. See Exhibit 10(a)59 herein.
(c) 55 - 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)60 herein.
* (c) 56 - Amendment Number Four and Amendment Number Five to The Southern Company Employee Savings Plan. 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 - Amendment Number Three to The Southern Company Employee Stock Ownership Plan. See Exhibit 10(a)63 herein.
(c) 59 - The Southern Company Performance Pay Plan, Amended and Restated effective January 1, 1998. See Exhibit
10(a)64 herein.
# (c) 60 - The Southern Company Deferred Compensation Plan, Amended and Restated effective January 1, 1998. See
Exhibit 10(a)67 herein.
# (c) 61 - The Southern Company Outside Directors Pension Plan. See Exhibit 10(a)66 herein.
# (c) 62 - Outside Directors Stock Plan for Subsidiaries of The Southern Company and First Amendment thereto. See
Exhibit 10(a)69 herein.
(c) 63 - The Southern Company Pension Plan, effective as of January 1, 1997 and all amendments thereto through
Amendment Number Three. See Exhibit 10(a)71 herein.
* (c) 64 - Amendment Number Four to The Southern Company Pension Plan. See Exhibit 10(a)72 herein.
# * (c) 65 - The Southern Company Performance Stock Plan, Amended and Restated effective July 19, 1999. See Exhibit
10(a)73 herein.
# * (c) 66 - The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective January 1,
1999. See Exhibit 10(a)74 herein.
# * (c) 67 - The Southern Company Performance Dividend Plan, Amended and Restated effective January 1, 1999. See
Exhibit 10(a)70 herein.
E-26
# (c) 68 - The Southern Company Performance Sharing Plan effective January 1, 1997 and all amendments thereto through
Amendment Number Six. See Exhibit 10(a)75 herein.
# * (c) 69 - Amendment Number Seven 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 - Amendment Number One to The Southern Company Supplemental Benefit Plan. See Exhibit 10(a)78 herein.
(c) 72 - Southern Company Change in Control Severance Plan, effective December 7, 1998. See Exhibit 10(a)79 herein.
* (c) 73 - Amendment Number One to Southern Company Change in Control Severance Plan. See Exhibit 10(a)80 herein.
# (c) 74 - Southern Company Executive Change in Control Severance Plan, effective December 7, 1998. See Exhibit
10(a)81 herein.
# * (c) 75 - Amendment Number One to Southern Company Executive Change in Control Severance Plan. See Exhibit 10(a)82
herein.
# (c) 76 - Deferred Compensation Agreement between SOUTHERN, GEORGIA and Henry Allen Franklin. See Exhibit 10(a)83
herein.
# * (c) 77 - Amendment Number One and Assignment to SCS of Deferred Compensation Agreement between SOUTHERN, GEORGIA and
Henry Allen Franklin. See Exhibit 10(a)84 herein.
# (c) 78 - Deferred Compensation Agreement between SOUTHERN, GEORGIA and Warren Y. Jobe. See Exhibit 10(a)86 herein.
# (c) 79 - Change in Control Agreement between SOUTHERN, GEORGIA and David M. Ratcliffe. See Exhibit 10(a)99 herein.
# (c) 80 - Supplemental Pension Agreement between GEORGIA and Warren Y. Jobe. (Designated in GEORGIA's Form 10-K for
the year ended December 31, 1998, File No. 1-6468, as Exhibit 10(c)77.)
# * (c) 81 - Deferred Compensation Plan For Directors of Georgia Power Company, Amended and Restated Effective November
19, 1986 and all amendments thereto through Amendment Number Three.
E-27
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)53 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.
(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.
E-28
(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)58 herein.
# * (d) 16 - The Southern Company Executive Productivity Improvement Plan, Amended and Restated effective January 1,
1999. See Exhibit 10(a)59 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)60 herein.
* (d) 18 - Amendment Number Four and Amendment Number Five to The Southern Company Employee Savings Plan. See Exhibit
10(a)61 herein.
(d) 19 - 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) 20 - Amendment Number Three to The Southern Company Employee Stock Ownership Plan. See Exhibit 10(a)63 herein.
(d) 21 - The Southern Company Performance Pay Plan, Amended and Restated effective January 1, 1998. See Exhibit
10(a)64 herein.
# (d) 22 - The Southern Company Deferred Compensation Plan, Amended and Restated effective January 1, 1998. See
Exhibit 10(a)67 herein.
# (d) 23 - The Southern Company Outside Directors Pension Plan. See Exhibit 10(a)66 herein.
# (d) 24 - Outside Directors Stock Plan for Subsidiaries of The Southern Company and First Amendment thereto. See
Exhibit 10(a)69 herein.
(d) 25 - The Southern Company Pension Plan, effective as of January 1, 1997 and all amendments thereto through
Amendment Number Three. See Exhibit 10(a)71 herein.
* (d) 26 - Amendment Number Four to The Southern Company Pension Plan. See Exhibit 10(a)72 herein.
# (d) 27 - The Southern Company Supplemental Benefit Plan, Amended and Restated effective January 1, 1998. See
Exhibit 10(a)77 herein.
# * (d) 28 - Amendment Number One to The Southern Company Supplemental Benefit Plan. See Exhibit 10(a)78 herein.
E-29
(d) 29 - Southern Company Change in Control Severance Plan, effective December 7, 1998. See Exhibit 10(a)79 herein.
* (d) 30 - Amendment Number One to Southern Company Change in Control Severance Plan. See Exhibit 10(a)80 herein.
# (d) 31 - Southern Company Executive Change in Control Severance Plan, effective December 7, 1998. See Exhibit
10(a)81 herein.
# * (d) 32 - Amendment Number One to Southern Company Executive Change in Control Severance Plan. See Exhibit 10(a)82
herein.
# (d) 33 - Change in Control Agreement between SOUTHERN, GULF and Travis J. Bowden. See Exhibit 10(a)89 herein.
# * (d) 34 - The Southern Company Performance Stock Plan, Amended and Restated effective July 19, 1999. See Exhibit
10(a)73 herein.
# * (d) 35 - The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective January 1,
1999. See Exhibit 10(a)74 herein.
# * (d) 36 - The Southern Company Performance Dividend Plan, Amended and Restated effective January 1, 1999. See
Exhibit 10(a)70 herein.
# (d) 37 - The Southern Company Performance Sharing Plan effective January 1, 1997 and all amendments thereto through
Amendment Number Six. See Exhibit 10(a)75 herein.
# * (d) 38 - Amendment Number Seven to The Southern Company Performance Sharing Plan. See Exhibit 10(a)76 herein.
# (d) 39 - Supplemental Pension Agreement between SAVANNAH, GULF and G. Edison Holland, Jr. (Designated in GULF's
Form 10-K for the year ended December 31, 1998, File No. 0-2429, as Exhibit 10(d)35.)
# (d) 40 - Supplemental Pension Agreement between ALABAMA, GULF and Travis J. Bowden. See Exhibit 10(b)43 herein.
# * (d) 41 - Deferred Compensation Plan For Directors of Gulf Power Company, Amended and Restated Effective January 1,
1987 and all amendments thereto through Amendment Number Three.
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-30
(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) 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 - Long Term Transmission Service Agreement between Entergy Power, Inc. and ALABAMA, MISSISSIPPI and SCS.
See Exhibit 10(a)52 herein.
# (e) 13 - The Southern Company Productivity Improvement Plan, Amended and Restated effective January 1, 1998. See
Exhibit 10(a)58 herein.
# * (e) 14 - The Southern Company Executive Productivity Improvement Plan, Amended and Restated effective January 1,
1999. See Exhibit 10(a)59 herein.
E-31
(e) 15 - 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)60 herein.
* (e) 16 - Amendment Number Four and Amendment Number Five to The Southern Company Employee Savings Plan. See Exhibit
10(a)61 herein.
(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 - Amendment Number Three to The Southern Company Employee Stock Ownership Plan. See Exhibit 10(a)63 herein.
(e) 19 - The Southern Company Performance Pay Plan, Amended and Restated effective January 1, 1998. See Exhibit
10(a)64 herein.
# (e) 20 - The Southern Company Deferred Compensation Plan, Amended and Restated effective January 1, 1998. See
Exhibit 10(a)67 herein.
# (e) 21 - The Southern Company Outside Directors Pension Plan. See Exhibit 10(a)66 herein.
# (e) 22 - Outside Directors Stock Plan for Subsidiaries of The Southern Company and First Amendment thereto. See
Exhibit 10(a)69 herein.
(e) 23 - The Southern Company Pension Plan, effective as of January 1, 1997 and all amendments thereto through
Amendment Number Three. See Exhibit 10(a)71 herein.
* (e) 24 - Amendment Number Four to The Southern Company Pension Plan. See Exhibit 10(a)72 herein.
# (e) 25 - The Southern Company Supplemental Benefit Plan, Amended and Restated effective January 1, 1998. See
Exhibit 10(a)77 herein.
# * (e) 26 - Amendment Number One to The Southern Company Supplemental Benefit Plan. See Exhibit 10(a)78 herein.
(e) 27 - Southern Company Change in Control Severance Plan, effective December 7, 1998. See Exhibit 10(a)79 herein.
* (e) 28 - Amendment Number One to Southern Company Change in Control Severance Plan. See Exhibit 10(a)80 herein.
# (e) 29 - Southern Company Executive Change in Control Severance Plan, effective December 7, 1998. See Exhibit
10(a)81 herein.
# * (e) 30 - Amendment Number One to Southern Company Executive Change in Control Severance Plan. See Exhibit 10(a)82
herein.
E-32
# (e) 31 - Change in Control Agreement between SOUTHERN, MISSISSIPPI and Dwight H. Evans. See Exhibit 10(a)91 herein.
# * (e) 32 - The Southern Company Performance Stock Plan, Amended and Restated effective July 19, 1999. See Exhibit
10(a)73 herein.
# * (e) 33 - The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective January 1,
1999. See Exhibit 10(a)74 herein.
# * (e) 34 - The Southern Company Performance Dividend Plan, Amended and Restated effective January 1, 1999. See
Exhibit 10(a)70 herein.
# (e) 35 - The Southern Company Performance Sharing Plan effective January 1, 1997 and all amendments thereto through
Amendment Number Six. See Exhibit 10(a)75 herein.
# * (e) 36 - Amendment Number Seven to The Southern Company Performance Sharing Plan. See Exhibit 10(a)76 herein.
# * (e) 37 - Deferred Compensation Plan for Directors of Mississippi Power Company, Amended and Restated Effective
January 1, 2000.
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.
E-33
(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)54 herein.
(f) 10 - Plant McIntosh Combustion Turbine Operating Agreement between GEORGIA and SAVANNAH dated December 15, 1992.
See Exhibit 10(a)55 herein.
# (f) 11 - The Southern Company Productivity Improvement Plan, Amended and Restated effective January 1, 1998. See
Exhibit 10(a)58 herein.
# * (f) 12 - The Southern Company Executive Productivity Improvement Plan, Amended and Restated effective January 1,
1999. See Exhibit 10(a)59 herein.
(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)60 herein.
* (f) 14 - Amendment Number Four and Amendment Number Five to The Southern Company Employee Savings Plan. See Exhibit
10(a)61 herein.
(f) 15 - 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) 16 - Amendment Number Three to The Southern Company Employee Stock Ownership Plan. See Exhibit 10(a)63 herein.
# (f) 17 - 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) 18 - Deferred Compensation Plan for Key Employees of SAVANNAH and all amendments thereto through Amendment
Number Three. (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, in SAVANNAH's Form 10-K for the year ended December 31, 1996, File No. 1-5072, as Exhibit
10(f)22 and in SAVANNAH's Form 10-K for the year ended December 31, 1998, File No. 1-5072, as Exhibit
10(f)17.)
(f) 19 - The Southern Company Performance Pay Plan, Amended and Restated effective January 1, 1998. See Exhibit
10(a)64 herein.
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# (f) 20 - The Southern Company Outside Directors Pension Plan. See Exhibit 10(a)66 herein.
# (f) 21 - 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) 22 - Outside Directors Stock Plan for Subsidiaries of The Southern Company and First Amendment thereto. See
Exhibit 10(a)69 herein.
(f) 23 - The Southern Company Pension Plan, effective as of January 1, 1997 and all amendments thereto through
Amendment Number Three. See Exhibit 10(a)71 herein.
* (f) 24 - Amendment Number Four to The Southern Company Pension Plan. See Exhibit 10(a)72 herein.
# (f) 25 - The Southern Company Supplemental Benefit Plan, Amended and Restated effective January 1, 1998. See
Exhibit 10(a)77 herein.
# * (f) 26 - Amendment Number One to The Southern Company Supplemental Benefit Plan. See Exhibit 10(a)79 herein.
(f) 27 - Southern Company Change in Control Severance Plan, effective December 7, 1998. See Exhibit 10(a)79 herein.
* (f) 28 - Amendment Number One to Southern Company Change in Control Severance Plan. See Exhibit 10(a)80 herein.
# (f) 29 - Southern Company Executive Change in Control Severance Plan, effective December 7, 1998. See
Exhibit 10(a)81 herein.
# * (f) 30 - Amendment Number One to Southern Company Executive Change in Control Severance Plan. See Exhibit 10(a)82
herein.
# (f) 31 - Change in Control Agreement between SOUTHERN, SAVANNAH and G. Edison Holland, Jr. See Exhibit 10(a)96
herein.
# (f) 32 - The Southern Company Deferred Compensation Plan, Amended and Restated effective January 1, 1998. See
Exhibit 10(a)67 herein.
# * (f) 33 - The Southern Company Performance Stock Plan, Amended and Restated effective July 19, 1999. See Exhibit
10(a)73 herein.
# * (f) 34 - The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective
January 1, 1999. See Exhibit 10(a)74 herein.
# * (f) 35 - The Southern Company Performance Dividend Plan, Amended and Restated effective January 1, 1999. See Exhibit
10(a)70 herein.
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# (f) 36 - The Southern Company Performance Sharing Plan effective January 1, 1997 and all amendments thereto through
Amendment Number Six. See Exhibit 10(a)75 herein.
# * (f) 37 - Amendment Number Seven to The Southern Company Performance Sharing Plan. See Exhibit 10(a)76 herein.
# (f) 38 - Supplemental Pension Agreement between SAVANNAH, GULF and G. Edison Holland, Jr. See Exhibit 10(d)38
herein.
(21) Subsidiaries of Registrants
SOUTHERN
* (a) - Subsidiaries of Registrant.
ALABAMA
* (b) - Subsidiaries of Registrant.
GEORGIA
* (c) - Subsidiaries of Registrant.
GULF
* (d) - Subsidiaries of Registrant.
MISSISSIPPI
* (e) - Subsidiaries of Registrant.
SAVANNAH
* (f) - Subsidiaries of Registrant.
(23) Consents of Experts and Counsel
SOUTHERN
* (a) - The consent of Arthur Andersen LLP is contained herein at page IV-5.
ALABAMA
* (b) - The consent of Arthur Andersen LLP is contained herein at page IV-6.
GEORGIA
* (c) - The consent of Arthur Andersen LLP is contained herein at page IV-7.
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GULF
* (d) - The consent of Arthur Andersen LLP is contained herein at page IV-8.
MISSISSIPPI
* (e) - The consent of Arthur Andersen LLP is contained herein at page IV-9.
SAVANNAH
* (f) - The consent of Arthur Andersen LLP is contained herein at page IV-10.
(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 16, 2000, File No. 1-3526, as Exhibit 27.)
ALABAMA
(b) - Financial Data Schedule. (Designated in Form 8-K dated February 16, 2000, File No. 1-3164, as Exhibit 27.)
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GEORGIA
(c) - Financial Data Schedule. (Designated in Form 8-K dated February 16, 2000, File No. 1-6468, as Exhibit 27.)
GULF
(d) - Financial Data Schedule. (Designated in Form 8-K dated February 16, 2000, File No. 0-2429, as Exhibit 27.)
MISSISSIPPI
(e) - Financial Data Schedule. (Designated in Form 8-K dated February 16, 2000, File No. 0-6849, as Exhibit 27.)
SAVANNAH
(f) - Financial Data Schedule. (Designated in Form 8-K dated February 16, 2000, File No. 1-5072, as Exhibit 27.)
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