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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, 2002
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
001-11229 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
333-98553 Southern Power Company 58-2598670
(A Delaware Corporation)
270 Peachtree Street, N.W.
Atlanta, Georgia 30303
(404) 506-5000
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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 1/8% Trust Originated Preferred Securities 2
6.875% Cumulative Quarterly Income Preferred Securities 3
7.125% Trust Preferred Securities 4
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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
---------------------------------------------------
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
6.85% Trust Preferred Securities 5
7 1/8% Trust Preferred Securities 6
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Company obligated mandatorily redeemable Gulf Power Company
preferred securities, $25 liquidation amount
7.625% Cumulative Quarterly Income Preferred Securities 7
7.00% Cumulative Quarterly Income Preferred Securities 8
7.375% Trust Preferred Securities 9
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1 As of December 31, 2002.
2 Issued by Southern Company Capital Trust IV and guaranteed by The Southern
Company.
3 Issued by Southern Company Capital Trust V and guaranteed by The Southern
Company.
4 Issued by Southern Company Capital Trust VI and guaranteed by The Southern
Company.
5 Issued by Georgia Power Capital Trust IV and guaranteed by Georgia Power
Company.
6 Issued by Georgia Power Capital Trust V and guaranteed by Georgia Power
Company.
7 Issued by Gulf Power Capital Trust I and guaranteed by Gulf Power Company.
8 Issued by Gulf Power Capital Trust II and guaranteed by Gulf Power Company.
9 Issued by Gulf Power Capital Trust III and guaranteed by Gulf Power Company.
Depositary preferred shares, Mississippi Power Company
each 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
7.20% Trust Originated Preferred Securities 10
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Company obligated mandatorily redeemable Savannah Electric and Power Company
preferred securities, $25 liquidation amount
6.85% Trust Preferred Securities 11
Securities registered pursuant to Section 12(g) of the Act: 12
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
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Preferred stock, cumulative, $100 stated value Georgia Power Company
$4.60 Series (1954)
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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% Series 4.60% Series
4.72% Series 7.00% Series
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- --------
10 Issued by Mississippi Power Capital Trust II and guaranteed by Mississippi
Power Company.
11 Issued by Savannah Electric Capital Trust I and guaranteed by Savannah
Electric and Power Company.
12 As of December 31, 2002.
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. ( )
Indicate by checkmark if the registrants are accelerated filers as defined
in Rule 12b-2 of the Securities Exchange Act of 1934.
Yes X (except for Southern Power Company) No___
Aggregate market value of voting and non-voting stock held by
non-affiliates of The Southern Company at June 28, 2002: $19.4 billion and at
February 28, 2003: $20.3 billion. Each of such other registrants is a
wholly-owned subsidiary of The Southern Company. A description of registrants'
common stock follows:
Description of Shares Outstanding
Registrant Common Stock at February 28, 2003
- ---------- -------------- --------------------
The Southern Company Par Value $5 Per Share 718,075,975
Alabama Power Company Par Value $40 Per Share 6,000,000
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
Southern Power Company Par Value $0.01 Per Share 1,000
Documents incorporated by reference: specified portions of The Southern
Company's Proxy Statement relating to the 2003 Annual Meeting of Stockholders
are incorporated by reference into PART III. In addition, specified portions of
the Information Statements of Alabama Power Company, Georgia Power Company,
Gulf Power Company and Mississippi Power Company relating to each of their
respective 2003 Annual Meeting of Shareholders 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, Savannah Electric and Power Company and Southern 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
Operating Companies.................................................................................. I-2
Southern Power....................................................................................... I-2
Other Business....................................................................................... I-3
Mirant Corporation................................................................................... I-3
Risk Factors......................................................................................... I-4
Construction Programs................................................................................ I-9
Financing Programs................................................................................... I-11
Fuel Supply.......................................................................................... I-12
Territory Served by the Operating Companies.......................................................... I-13
Competition.......................................................................................... I-17
Regulation........................................................................................... I-18
Rate Matters......................................................................................... I-21
Employee Relations................................................................................... I-22
Item 2 Properties............................................................................................. I-24
Item 3 Legal Proceedings...................................................................................... I-28
Item 4 Submission of Matters to a Vote of Security Holders.................................................... I-32
Executive Officers of Southern Company................................................................. I-33
Executive Officers of Alabama Power.................................................................... I-34
Executive Officers of Georgia Power.................................................................... I-35
Executive Officers of Gulf Power....................................................................... I-36
Executive Officers of Mississippi Power................................................................ I-37
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-3
Item 8 Financial Statements and Supplementary Data............................................................ II-4
Item 9 Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure.................................................................. II-5
PART III
Item 10 Directors and Executive Officers of the Registrants................................................... III-1
Item 11 Executive Compensation................................................................................ III-5
Item 12 Security Ownership of Certain Beneficial Owners and
Management and Related Stockholder Matters.......................................................... III-12
Item 13 Certain Relationships and Related Transactions........................................................ III-15
Item 14 Controls and Procedures............................................................................... III-15
PART IV
Item 15 Exhibits, Financial Statement Schedules, and Reports
on Form 8-K......................................................................................... IV-1
Signatures and Certifications......................................................................... IV-2
i
DEFINITIONS
When used in Items 1 through 5 and Items 10 through 15, the following terms will have the meanings indicated.
Term Meaning
AEC........................................... Alabama Electric Cooperative, Inc.
AFUDC......................................... Allowance for Funds Used During Construction
Alabama Power................................. Alabama Power Company
AMEA.......................................... Alabama Municipal Electric Authority
Clean Air Act................................. Clean Air Act Amendments of 1990
Dalton........................................ City of Dalton, Georgia
DOE........................................... United States Department of Energy
EMF........................................... Electromagnetic field
Energy Act.................................... Energy Policy Act of 1992
Energy Solutions.............................. Southern Company Energy Solutions, Inc.
EPA........................................... United States Environmental Protection Agency
FERC.......................................... Federal Energy Regulatory Commission
FPC........................................... Florida Power Corporation
FP&L.......................................... Florida Power & Light Company
Georgia Power................................. Georgia Power Company
Gulf Power.................................... Gulf Power Company
Holding Company Act........................... Public Utility Holding Company Act of 1935, as amended
IBEW.......................................... International Brotherhood of Electrical Workers
IPP........................................... Independent power producer
IRP........................................... Integrated Resource Plan
IRS........................................... Internal Revenue Service
ISA........................................... Independent System Administrator
JEA........................................... Jacksonville Electric Authority
MEAG.......................................... Municipal Electric Authority of Georgia
MESH.......................................... Mobile Energy Services Holdings
Mirant........................................ Mirant Corporation
Mississippi Power............................. Mississippi Power Company
Moody's....................................... Moody's Investors Service, Inc.
NRC........................................... Nuclear Regulatory Commission
OPC........................................... Oglethorpe Power Corporation
operating companies........................... Alabama Power Company, Georgia Power Company, Gulf Power Company,
Mississippi Power Company and Savannah Electric and Power Company
PPA........................................... Power Purchase Agreement
PSC........................................... Public Service Commission
RFP........................................... Request for Proposal
RTO........................................... Regional Transmission Organization
RUS........................................... Rural Utility Service (formerly Rural Electrification
Administration)
S&P........................................... Standard and Poor's Ratings Services, a division of The
McGraw-Hill Companies
ii
DEFINITIONS
(continued)
Savannah Electric............................. Savannah Electric and Power Company
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
SeTrans....................................... A proposed regional transmission organization consisting
of eleven public and private companies, including
Southern Company, located in eight southeastern states
SMEPA......................................... South Mississippi Electric Power Association
Southern Company.............................. The Southern Company
Southern Company GAS.......................... Southern Company Gas LLC
Southern LINC................................. Southern Communications Services, Inc.
Southern Management Development............... Southern Management Development, Inc.
Southern Nuclear.............................. Southern Nuclear Operating Company, Inc.
Southern Power................................ Southern Power Company
SOUTHERN system............................... Southern Company, the operating companies, Southern
Power, SEGCO, Southern Nuclear, SCS, Southern
LINC, Southern Management Development, Southern Company GAS and other
subsidiaries
Southern Telecom.............................. Southern Telecom, Inc.
Super Southeast............................... Southern Company's traditional service territory, Alabama,
Florida, Georgia and Mississippi, plus the surrounding
States of Kentucky, Louisiana, North Carolina, South
Carolina, Tennessee and Virginia
TVA........................................... Tennessee Valley Authority
iii
CAUTIONARY STATEMENT REGARDING
FORWARD-LOOKING INFORMATION
This Annual Report on Form 10-K contains forward-looking and historical
information. Forward-looking information includes, among other things,
statements concerning the strategic goals for Southern Company's wholesale
business, estimated construction expenditures and Southern Company's projections
for energy sales and its goals for future generating capacity, dividend payout
ratio, equity ratio, earnings per share and earnings growth. In some cases,
forward-looking statements can be identified by terminology such as "may,"
"will," "could," "should," "expects," "plans," "anticipates," "believes,"
"estimates," "projects," "predicts," "potential" or "continue" or the negative
of these terms or other comparable terminology. Southern Company cautions that
there are various important factors that could cause actual results to differ
materially from those indicated in the forward-looking statements; accordingly,
there can be no assurance that such indicated results will be realized. These
factors include the impact of recent and future federal and state regulatory
change, including legislative and regulatory initiatives regarding deregulation
and restructuring of the electric utility industry and also changes in
environmental and other laws and regulations to which Southern Company and its
subsidiaries are subject, as well as changes in application of existing laws and
regulations; current and future litigation, including the pending EPA civil
actions against certain Southern Company subsidiaries; the effects, extent and
timing of the entry of additional competition in the markets in which Southern
Company's subsidiaries operate; the impact of fluctuations in commodity prices,
interest rates and customer demand; state and federal rate regulations;
political, legal and economic conditions and developments in the United States;
the performance of projects undertaken by the non-traditional business and the
success of efforts to invest in and develop new opportunities; internal
restructuring or other restructuring options that may be pursued; potential
business strategies, including acquisitions or dispositions of assets or
businesses, which cannot be assured to be completed or beneficial to Southern
Company or its subsidiaries; the ability of counterparties of Southern Company
and its subsidiaries to make payments as and when due; the effects of, and
changes in, economic conditions in the areas in which Southern Company's
subsidiaries operate, including the current soft economy; the direct or indirect
effects on Southern Company's business resulting from the terrorist incidents on
September 11, 2001, or any similar such incidents or responses to such
incidents; financial market conditions and the results of financing efforts; the
timing and acceptance of Southern Company's new product and service offerings;
the ability of Southern Company to obtain additional generating capacity at
competitive prices; weather and other natural phenomena; and other factors
discussed elsewhere herein and in other reports filed from time to time with the
SEC.
iv
PART I
Item 1. BUSINESS
Southern Company was incorporated under the laws of Delaware on November 9,
1945. Southern Company is domesticated under the laws of Georgia and is
qualified to do business as a foreign corporation under the laws of Alabama.
Southern Company owns all the outstanding common stock of Alabama Power, Georgia
Power, Gulf Power, Mississippi Power and Savannah Electric, each of which is an
operating public utility company. The operating companies supply electric
service in the states of Alabama, Georgia, Florida, Mississippi and Georgia,
respectively. More particular information relating to each of the operating
companies is as follows:
Alabama Power 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 Power 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 Power 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 Power 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 Electric 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.
In addition, Southern Company owns all of the common stock of Southern Power
which is also an operating public utility company. Southern Power is the primary
growth engine for Southern Company's competitive wholesale market-based energy
business. Southern Power is a corporation which was organized under the laws of
Delaware on January 8, 2001, and admitted to do business in Alabama, Florida and
Georgia on January 10, 2001 and in Mississippi on January 30, 2001.
Southern Company also owns all the outstanding common stock of Southern
LINC, Southern Company GAS, Southern Nuclear, SCS, Southern Management
Development, Southern Telecom, Southern Company Holdings and other direct and
indirect subsidiaries. Southern LINC provides digital wireless communications
services to Southern Company's operating companies and also markets these
services to the public within the Southeast. Southern Company GAS, which began
operation in August 2002, is a competitive retail natural gas marketer serving
communities in Georgia. Southern Nuclear provides services to Alabama Power's
and Georgia Power's nuclear plants. SCS is the system service company providing,
at cost, specialized services to Southern Company and its subsidiary companies.
Southern Management Development focuses on new and existing programs to enhance
customer satisfaction, efficiency and stockholder value. Southern Telecom
provides wholesale fiber optic solutions to telecommunication providers in the
Southeastern United States. Southern Company Holdings is an intermediate holding
subsidiary for Southern Company's investments in leveraged leases, alternative
fuel products and an energy services business.
Alabama Power and Georgia Power 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 Power and Georgia Power are each entitled to one-half of
SEGCO's capacity and energy. Alabama Power 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
I-1
Gaston to the Georgia state line at which point connection is made with the
Georgia Power transmission line system.
Reference is made to Note 12 to the financial statements of Southern Company
in Item 8 herein for additional information regarding Southern Company's segment
and related information.
The registrants' Annual Report on Form 10-K, Quarterly Reports on Form 10-Q,
Current Reports on Form 8-K and all amendments to those reports are made
available, free of charge, as soon as reasonably practicable after such material
is electronically filed with or furnished to the SEC. Southern Company's
internet address is http://www.southerncompany.com.
The SOUTHERN System
Operating Companies
The transmission facilities of each of the operating companies are connected to
the respective company's own generating plants and other sources of power and
are interconnected with the transmission facilities of the other operating
companies and SEGCO by means of heavy-duty high voltage lines. (For information
on Georgia Power's integrated transmission system, see Item 1 - BUSINESS -
"Territory Served by the Operating Companies" herein.)
Operating contracts covering arrangements in effect with principal
neighboring utility systems provide for capacity exchanges, capacity purchases
and sales, transfers of economy energy and other similar transactions.
Additionally, the operating companies have entered into voluntary reliability
agreements with the subsidiaries of Entergy Corporation, Florida Electric Power
Coordinating Group and TVA and with Carolina Power & Light Company, Duke Energy
Corporation, South Carolina Electric & Gas Company and Virginia Electric and
Power Company, each of which provides for the establishment and periodic review
of principles and procedures for planning and operation of generation and
transmission facilities, maintenance schedules, load retention programs,
emergency operations and other matters affecting the reliability of bulk power
supply. The operating companies have joined with other utilities in the
Southeast (including those referred to above) to form the SERC to augment
further the reliability and adequacy of bulk power supply. Through the SERC, the
operating companies are represented on the National Electric Reliability
Council.
An intra-system interchange agreement provides for coordinating operations
of the power producing facilities of the operating companies and Southern Power
and the capacities available to such companies from non-affiliated sources and
for the pooling of surplus energy available for interchange. Coordinated
operation of the entire interconnected system is conducted through a central
power supply coordination office maintained by SCS. The available sources of
energy are allocated to the operating companies and Southern Power to provide
the most economical sources of power consistent with good operation. The
resulting benefits and savings are apportioned among the operating companies and
Southern Power.
SCS has contracted with Southern Company, each operating company, Southern
Power, various of the other subsidiaries, Southern Nuclear and SEGCO to furnish,
at direct or allocated cost and upon request, the following services: general
and design engineering, purchasing, accounting and statistical analysis, finance
and treasury, tax, information resources, marketing, auditing, insurance and
pension administration, human resources, systems and procedures; and other
services with respect to business and operations and power pool transactions.
Southern Management Development, Southern Company GAS, Southern LINC and
Southern Telecom have also secured from the operating companies certain services
which are furnished at cost.
Southern Nuclear has contracts with Alabama Power to operate the Farley
Nuclear Plant and with Georgia Power to operate Plants Hatch and Vogtle. See
Item 1 - BUSINESS - "Regulation - Atomic Energy Act of 1954" herein.
Southern Power
Southern Power is an electric wholesale generation subsidiary that is the
primary growth engine for Southern Company's competitive wholesale market-based
energy business. Southern Power constructs, acquires and owns generating
facilities and sells the output under long-term, fixed-price capacity contracts
both to unaffiliated wholesale purchasers as well as the operating companies
(under PPAs approved by the respective PSCs). Southern Power's wholesale
I-2
generating assets are not placed in the operating companies' rate bases, and
Southern Power is only able to recover costs based on the terms of its PPAs.
Southern Power has attempted to insulate itself from significant fuel supply,
fuel transportation and electric transmission risk by making such risks the
responsibility of the counterparties to the PPAs. However, Southern Power's
overall profit will depend on the parameters of the wholesale market and its
efficient operation of its wholesale generating assets. Southern Power is a
party to the intra-system interchange agreement and shares in the benefits and
burdens of such arrangement. By the end of 2005, Southern Power plans to have
approximately 6,600 megawatts of available generating capacity in commercial
operation. At December 31, 2002, Southern Power had 2,400 megawatts of
generating capacity in commercial operation.
Other Business
On June 3, 2002, Southern Company formed a wholly-owned subsidiary, Southern
Company GAS. Southern Company GAS operates as a retail gas marketer in the State
of Georgia. On July 19, 2002, Southern Company GAS completed its acquisition out
of bankruptcy from The New Power Company (New Power) of approximately 210,000
retail natural gas customers located in the State of Georgia, representing a 15%
market share. Southern Company GAS also purchased from New Power proprietary
risk management software and hardware systems, natural gas inventory and
accounts receivable. The total purchase price was approximately $60 million.
In 2001, Energy Solutions changed its name to Southern Management
Development. Southern Management Development then created a separate entity,
Southern Company Energy Solutions LLC (SCES LLC), for its energy services
business which was contributed to Southern Company Holdings. SCES LLC provides
energy related services and products. Southern Management Development focuses on
new and existing programs to enhance customer satisfaction, efficiency and
stockholder value.
Southern Company Holdings is an intermediate holding subsidiary for
Southern Company's investments in leveraged leases and alternative fuel
products, in addition to SCES LLC.
In 1996, Southern LINC began serving Southern Company's operating companies
and marketing its services to non-affiliates within the Southeast. Its system
covers approximately 127,000 square miles and combines the functions of two-way
radio dispatch, cellular phone, short text and numeric messaging and wireless
internet access and data transfer.
These continuing efforts to invest in and develop new business opportunities
offer potential returns exceeding those of rate-regulated operations. However,
these activities also involve a higher degree of risk.
In 1999, MESH, a subsidiary of Southern Company, filed a petition for
Chapter 11 bankruptcy relief in the U.S. Bankruptcy Court. In August 2000, MESH
filed a proposed plan of reorganization with the U.S. Bankruptcy Court. The
proposed plan of reorganization was most recently amended on December 13, 2001.
Southern Company expects that approval of a plan of reorganization would result
in termination of Southern Company's ownership interest in MESH but would not
affect Southern Company's continuing guarantee obligations. Reference is made to
Item 3 - "Legal Proceedings" and Note 3 to the financial statements of Southern
Company in Item 8 herein under the heading "Mobile Energy Services' Petition for
Bankruptcy" herein for additional information relating to this matter.
Mirant Corporation
In April 2000, Southern Company announced an initial public offering of up to
19.9 percent of Mirant and its intention to spin off the remaining ownership of
Mirant to Southern Company stockholders within 12 months of the initial stock
offering. On October 2, 2000, Mirant completed its initial public offering of
66.7 million shares of common stock priced at $22 per share. This represented
19.7 percent of the 338.7 million shares outstanding.
On February 19, 2001, Southern Company's board of directors approved the spin
off of its remaining ownership of 272 million Mirant shares. On April 2, 2001,
the tax-free distribution of Mirant shares was completed at a ratio of
approximately 0.4 shares for every share of Southern Company common stock held
on the record date.
As a result of the spin off, Southern Company's financial statements reflect
Mirant's results of operations, balance sheets and cash flows as discontinued
operations.
I-3
Southern Company is involved in various matters being litigated. Reference is
made to Item 3 - "Legal Proceedings" and to Note 3 to the financial statements
of Southern Company in Item 8 herein for information regarding material issues
that could possibly affect future earnings.
Risk Factors
In addition to the other information in this Form 10-K, the following factors
should be considered in evaluating Southern Company and its subsidiaries. Such
factors could affect actual results and cause results to differ materially from
those expressed in any forward-looking statements made by, or on behalf of,
Southern Company and/or its subsidiaries. Some or all of these factors may
apply to Southern Company and/or its subsidiaries.
Risks Related to the Energy Industry
- ------------------------------------
Southern Company is subject to substantial governmental regulation. Compliance
with current and future regulatory requirements and procurement of necessary
approvals, permits and certificates may result in substantial costs to Southern
Company.
Southern Company is subject to substantial regulation from federal, state
and local regulatory agencies. Southern Company and its subsidiaries are
required to comply with numerous laws and regulations and to obtain numerous
permits, approvals and certificates from the governmental agencies that regulate
various aspects of their businesses, including customer rates, service
regulations, retail service territories, sales of securities, asset acquisitions
and sales, accounting policies and practices, and the operation of fossil-fuel,
hydroelectric and nuclear generating facilities. For example, the rates charged
to wholesale customers by the operating companies and by Southern Power must be
approved by the FERC. In addition, the respective state PSCs must approve the
operating companies' rates for retail customers. Southern Company believes the
necessary permits, approvals and certificates have been obtained for its
existing operations and that its business is conducted in accordance with
applicable laws; however, Southern Company is unable to predict the impact on
its operating results from future regulatory activities of these agencies.
Southern Company is also subject to regulation by the SEC under the Holding
Company Act. The rules and regulations promulgated under the Holding Company Act
impose a number of restrictions on the operations of registered utility holding
companies and their subsidiaries. These restrictions include a requirement that,
subject to a number of exceptions, the SEC approve in advance securities
issuances, acquisitions and dispositions of utility assets or of securities of
utility companies, and acquisitions of other businesses. The Holding Company Act
also generally limits the operations of a registered holding company to a single
integrated public utility system, plus additional energy-related businesses. The
Holding Company Act requires that transactions between affiliated companies in a
registered holding company system be performed at cost, with limited exceptions.
The impact of any future revision or changes in interpretations of existing
regulations or the adoption of new laws and regulations applicable to Southern
Company or any of its subsidiaries cannot now be predicted. Changes in
regulation or the imposition of additional regulations could influence Southern
Company's operating environment and may result in substantial costs to Southern
Company.
General Risks Related to Operation of Southern Company's Utility Subsidiaries
- -----------------------------------------------------------------------------
The regional power market in which Southern Company and its subsidiaries compete
has changing transmission regulatory structures, which could affect the
ownership of these assets and related revenues and expenses.
The operating companies currently own and operate transmission facilities
as part of a vertically integrated utility. Transmission revenues are not
separated from generation and distribution revenues in their approved retail
rates. Federal governmental authorities are advocating the formation of RTOs and
are proposing the adoption of new regulations that would impact electric
markets, including the transmission regulatory structure. Under this new
transmission regulatory structure, the operating companies would transfer
functional control (but not ownership) of their transmission facilities to an
independent third party. Because it remains unclear how RTOs will develop or
I-4
what new market rules will be established, Southern Company is unable to assess
fully the impact that these developments may have on its business. Southern
Company's revenues, expenses, assets and liabilities could be adversely affected
by changes in the transmission regulatory structure in its regional power
market.
Recent events in the energy markets that are beyond Southern Company's control
have increased the level of public and regulatory scrutiny in the energy
industry and in the capital markets. The reaction to these events may result in
new laws or regulations related to Southern Company's business operations or the
accounting treatment of its existing operations which could have a negative
impact on Southern Company's net income or access to capital.
As a result of the energy crisis in California during the summer of 2001,
the filing of bankruptcy by Enron Corporation and investigations by governmental
authorities into energy trading activities, companies generally in the regulated
and unregulated utility businesses have been under an increased amount of public
and regulatory scrutiny. The capital markets and ratings agencies also have
increased their level of scrutiny. This increased scrutiny could lead to
substantial changes in laws and regulations affecting Southern Company,
including new accounting standards that could change the way Southern Company is
required to record revenues, expenses, assets and liabilities. These types of
disruptions in the industry and any resulting regulations may have a negative
impact on Southern Company's net income or access to capital.
Deregulation or restructuring in the electric industry may result in increased
competition and unrecovered costs which could negatively impact Southern
Company's earnings.
Increased competition which may result from restructuring efforts could
have a significant adverse financial impact on Southern Company and its
operating companies. Increased competition could result in increased pressure to
lower the cost of electricity. Any adoption in the territories served by the
operating companies of retail competition and the unbundling of regulated energy
service could have a significant adverse financial impact on Southern Company
and its subsidiaries due to an impairment of assets, a loss of retail customers,
lower profit margins or increased costs of capital. Southern Company cannot
predict if or when it will be subject to changes in legislation or regulation,
nor can Southern Company predict the impact of these changes.
Additionally, the electric utility industry has experienced a substantial
increase in competition at the wholesale level, caused by changes in federal law
and regulatory policy. As a result of the Public Utility Regulatory Policies Act
of 1978 and the Energy Act, competition in the wholesale electricity market has
greatly increased due to a greater participation by traditional electricity
suppliers, non-utility generators, independent power producers, wholesale power
marketers and brokers, and due to the trading of energy futures contracts on
various commodities exchanges. In 1996, the FERC issued new rules on
transmission service to facilitate competition in the wholesale market on a
nationwide basis. The rules give greater flexibility and more choices to
wholesale power customers. Also, in July 2002, the FERC issued a notice of
proposed rulemaking (which has not yet been adopted) related to open access
transmission service and standard electricity market design. As a result of the
changing regulatory environment and the relatively low barriers to entry (which
include, in addition to open access transmission service, relatively low
construction costs for new generating facilities), Southern Company expects
competition to steadily increase. This increased competition could affect
Southern Company's load forecasts, plans for power supply and wholesale energy
sales and related revenues. The effect on Southern Company's net income and
financial condition could vary depending on the extent to which: (i) additional
generation is built to compete in the wholesale market; (ii) new opportunities
are created for Southern Company to expand its wholesale load; or (iii) current
wholesale customers elect to purchase from other suppliers after existing
contracts expire.
I-5
Risks Related to Environmental Regulation
- -----------------------------------------
Southern Company's costs of compliance with environmental laws are significant.
The costs of compliance with future environmental laws and the incurrence of
environmental liabilities could harm Southern Company's cash flow and
profitability.
Southern Company and its subsidiaries are subject to extensive federal,
state and local environmental requirements which, among other things, regulate
air emissions, water discharges and the management of hazardous and solid waste
in order to adequately protect the environment. Compliance with these legal
requirements requires Southern Company to commit significant expenditures for
installation of pollution control equipment, environmental monitoring, emissions
fees and permits at all of its facilities. These expenditures are significant
and Southern Company expects that they will increase in the future. For example,
construction expenditures for achieving compliance with Phase I and Phase II of
Title IV of the Clean Air Act totaled approximately $400 million. Construction
expenditures for compliance with one-hour ozone non-attainment standards in
Atlanta and Birmingham are expected to total approximately $980 million when
completed in 2003.
If Southern Company fails to comply with environmental laws and
regulations, even if caused by factors beyond its control, that failure may
result in the assessment of civil or criminal penalties and fines against
Southern Company. The EPA has filed civil actions against Alabama Power, Georgia
Power and Savannah Electric alleging violations of the new source review
provisions of the Clean Air Act. The EPA has also issued notices of violation to
Gulf Power and Mississippi Power. An adverse outcome in any one of these cases
could require substantial capital expenditures that cannot be determined at this
time and could require payment of substantial penalties.
Existing environmental laws and regulations may be revised, or new laws and
regulations seeking to protect the environment may be adopted or become
applicable to Southern Company. Revised or additional laws and regulations could
result in additional operating restrictions on Southern Company's facilities or
increased compliance costs which may not be fully recoverable from Southern
Company's customers and would therefore reduce Southern Company's net income.
Risks Related to Southern Company and its Business
- --------------------------------------------------
Southern Company may be unable to meet its ongoing and future financial
obligations and to pay dividends on its common stock if its subsidiaries are
unable to pay upstream dividends or repay funds to Southern Company.
Southern Company is a holding company and, as such, Southern Company has no
operations of its own. Southern Company's ability to meet its financial
obligations and to pay dividends on its common stock at the current rate is
primarily dependent on the earnings and cash flows of its subsidiaries and their
ability to pay upstream dividends or to repay funds to Southern Company. Prior
to funding Southern Company, Southern Company's subsidiaries have financial
obligations that must be satisfied, including among others, debt service and
preferred stock dividends.
Southern Company's financial performance may be adversely affected if its
subsidiaries are unable to successfully operate their electric generating
facilities.
Southern Company's financial performance depends on the successful
operation of its subsidiaries' electric generating facilities. Operating
electric generating facilities involves many risks, including:
o operator error and breakdown or failure of equipment or processes;
o operating limitations that may be imposed by environmental or other regulatory
requirements;
o labor disputes;
o fuel supply interruptions; and
o catastrophic events such as fires, earthquakes, explosions, floods or other
similar occurrences.
A decrease or elimination of revenues from power produced by the electric
generating facilities or an increase in the cost of operating the facilities
would reduce Southern Company's net income and could decrease or eliminate funds
available to Southern Company.
I-6
Changes in technology may make Southern Company's electric generating facilities
less competitive.
A key element of Southern Company's business model is that generating power
at central power plants achieves economies of scale and produces power at
relatively low cost. There are other technologies that produce power, most
notably fuel cells, microturbines, windmills and solar cells. It is possible
that advances in technology will reduce the cost of alternative methods of
producing power to a level that is competitive with that of most central power
station electric production. If this were to happen and if these technologies
achieved economies of scale, Southern Company's market share could be eroded,
and the value of its electric generating facilities could be reduced. Changes in
technology could also alter the channels through which retail electric customers
buy power, which could reduce Southern Company's revenues or increase expenses.
Operation of nuclear facilities involves inherent risks, including
environmental, health, regulatory, terrorism and financial risks that could
result in fines or the closure of Southern Company's nuclear units, and which
may present potential exposures in excess of Southern Company's insurance
coverage.
As of December 31, 2002, Southern Company owns six nuclear units through
Alabama Power (two units) and through Georgia Power, which holds undivided
interests in, and contracts for operation of, four units. These six nuclear
units are operated by Southern Nuclear and represent approximately 3,680
megawatts, or 10.1% of Southern Company's generation capacity. Southern
Company's nuclear facilities are subject to environmental, health and financial
risks such as on-site storage of spent nuclear fuel, the ability to maintain
adequate reserves for decommissioning, potential liabilities arising out of the
operation of these facilities and the threat of a possible terrorist attack.
Southern Company maintains decommissioning trusts and external insurance
coverage to minimize the financial exposure to these risks; however, it is
possible that damages could exceed the amount of Southern Company's insurance
coverage.
The NRC has broad authority under federal law to impose licensing and
safety-related requirements for the operation of nuclear generation facilities.
In the event of non-compliance, the NRC has the authority to impose fines or
shut down a unit, or both, depending upon its assessment of the severity of the
situation, until compliance is achieved. Recent NRC orders related to increased
security measures and any future safety requirements promulgated by the NRC
could require Southern Company to make substantial operating and capital
expenditures at its nuclear plants. In addition, although Southern Company has
no reason to anticipate a serious nuclear incident at its plants, if an incident
did occur, it could result in substantial costs to Southern Company. A major
incident at a nuclear facility anywhere in the world could cause the NRC to
limit or prohibit the operation or licensing of any domestic nuclear unit.
Southern Company's nuclear units require licenses that need to be renewed
or extended in order to continue operating beyond their initial forty-year
terms. As a result of potential terrorist threats and increased public scrutiny
of utilities, the licensing process could result in increased licensing or
compliance costs that are difficult or impossible to predict.
Southern Company's generation and marketing operations are subject to risks,
many of which are beyond its control, that may reduce Southern Company's
revenues and increase its costs.
Southern Company's generation and marketing operations are subject to
changes in power prices or fuel costs, which could increase the cost of
producing power or decrease the amount Southern Company receives from the sale
of power. The market prices for these commodities may fluctuate over relatively
short periods of time. Southern Company attempts to mitigate risks associated
with fluctuating fuel costs by passing these costs on to customers in its PPAs.
Among the factors that could influence power prices and fuel costs are:
o prevailing market prices for coal, natural gas, fuel oil and other
fuels used in Southern Company's generation facilities, including
associated transportation costs, and supplies of such commodities;
o demand for energy and the extent of additional supplies of energy
available from current or new competitors;
o liquidity in the general wholesale electricity market;
o weather conditions impacting demand for electricity;
I-7
o seasonality;
o transmission or transportation constraints or inefficiencies;
o availability of competitively priced alternative energy sources;
o natural disasters, wars, embargos, acts of terrorism and other
catastrophic events; and
o federal, state and foreign energy and environmental regulation and
legislation.
Certain of these factors could increase Southern Company's expenses. For
the operating companies, such increases may not be fully recoverable through
rates. Other of these factors could reduce Southern Company's revenues.
Southern Company may not be able to obtain adequate fuel supplies, which could
limit its ability to operate its facilities.
Southern Company purchases fuel from a number of suppliers. Disruption in
the delivery of fuel, including disruptions as a result of, among other things,
weather, labor relations or environmental regulations affecting Southern
Company's fuel suppliers, could limit Southern Company's ability to operate its
facilities, and thus, reduce its net income.
Demand for power could exceed Southern Company's supply capacity, resulting in
increased costs to Southern Company for purchasing capacity in the open market
or building additional generation capabilities.
Southern Company is currently obligated to supply power to regulated retail
and wholesale customers. At peak times, the demand for power required to meet
this obligation could exceed Southern Company's available generation capacity.
Market or competitive forces may require that Southern Company purchase capacity
on the open market or build additional generation capabilities. Because
regulators may not permit the operating companies to pass all of these purchase
or construction costs on to their customers, the operating companies may not
recover any of these costs or may have exposure to regulatory lag associated
with the time between the incurrence of costs of purchased or constructed
capacity and the operating companies' recovery in customers' rates. Under
Southern Power's long-term, fixed price PPAs, it would not have the ability to
recover any of these costs.
Southern Company's operating results are affected by weather conditions and may
fluctuate on a seasonal and quarterly basis.
Electric power generation is generally a seasonal business. In many parts
of the country, demand for power peaks during the hot summer months, with market
prices also peaking at that time. In other areas, power demand peaks during the
winter. As a result, Southern Company's overall operating results in the future
may fluctuate substantially on a seasonal basis. In addition, Southern Company
has historically sold less power, and consequently earned less income, when
weather conditions are milder. Unusually mild weather in the future could reduce
Southern Company's revenues, net income, available cash and borrowing ability.
Risks Related to Market and Economic Volatility
- -----------------------------------------------
Southern Company's business is dependent on its ability to successfully access
capital markets. Southern Company's inability to access capital may limit its
ability to execute its business plan or pursue improvements and make
acquisitions that Southern Company may otherwise rely on for future growth.
Southern Company relies on access to both short-term money markets and
longer-term capital markets as a significant source of liquidity for capital
requirements not satisfied by the cash flow from its operations. If Southern
Company is not able to access capital at competitive rates, its ability to
implement its business plan or pursue improvements and make acquisitions that
Southern Company may otherwise rely on for future growth will be limited.
Southern Company believes that it will maintain sufficient access to these
financial markets based upon current credit ratings. However, certain market
disruptions or a downgrade of Southern Company's credit rating may increase its
cost of borrowing or adversely affect its ability to raise capital through the
issuance of securities or other borrowing arrangements. Such disruptions could
include:
o an economic downturn;
o the bankruptcy of an unrelated energy company;
o capital market conditions generally;
o market prices for electricity and gas;
I-8
o terrorist attacks or threatened attacks on Southern Company's facilities or
unrelated energy companies;
o war or threat of war; or
o the overall health of the utility industry.
Southern Company is subject to risks associated with a changing economic
environment, including Southern Company's ability to obtain insurance, the
financial stability of its customers and Southern Company's ability to raise
capital.
Due to the September 11, 2001 terrorist attacks and the resulting ongoing
war against terrorism by the United States, the nation's economy and financial
markets have been disrupted in general. Additionally, the bankruptcy of Enron
Corporation and events related to the California electric market crisis have
both limited the availability and increased the cost of capital for Southern
Company's businesses and that of Southern Company's competitors. The insurance
industry has also been disrupted by these events. The availability of insurance
covering risks Southern Company and its competitors typically insure against may
decrease, and the insurance that Southern Company is able to obtain may have
higher deductibles, higher premiums and more restrictive policy terms. The
continuation of the current economic downturn and disruption of financial
markets could also constrain the capital available to Southern Company's
industry and could reduce Southern Company's access to funding for its
operations, as well as the financial stability of its customers and
counterparties. These factors could adversely affect Southern Company's
subsidiaries' ability to achieve energy sales growth, thereby decreasing
Southern Company's level of future earnings.
Construction Programs
The subsidiary companies of Southern Company are engaged in continuous
construction programs to accommodate existing and estimated future loads on
their respective systems. Construction additions or acquisitions of property
during 2003 through 2005 by the operating companies, Southern Power, SEGCO, SCS,
Southern LINC, and other subsidiaries are estimated as follows:
------------------------------------------------------------
2003 2004 2005
--------------------------------
(in millions)
Alabama Power $ 643 $ 787 $ 948
Georgia Power 759 781 806
Gulf Power 108 150 156
Mississippi Power 76 86 75
Savannah Electric 41 51 44
SEGCO 13 22 5
SCS 22 25 20
Southern LINC 28 22 22
Southern Power 377 381 278
Other 8 3 -
------------------------------------------------------------
Southern Company system $2,075 $2,308 $2,354
============================================================
I-9
Estimated construction costs in 2003 are expected to be apportioned
approximately as follows: (in millions)
----------------------------------------------------------------------------------------------------------------------------------
Southern Alabama Georgia Gulf Mississippi Savannah Southern
Company Power Power Power Power Electric Power
system*
-------------------------------------------------------------------------------------------------
New generation $ 377 $ - $ - $ - $ - $ - $377
Other generating
facilities including
associated plant
substations 508 238 176 60 17 4 -
New business 359 129 183 23 13 11 -
Transmission 357 122 200 7 12 16 -
Joint line and substation 52 - 43 2 7 - -
Distribution 177 82 58 9 20 8 -
Nuclear fuel 106 39 67 - - - -
General plant 139 33 32 7 7 2 -
-------------------------------------------------------------------------------------------------
$2,075 $643 $759 $108 $76 $41 $377
=================================================================================================
* SCS, Southern LINC and other businesses plan capital additions to general
plant in 2003 of $22 million, $28 million and $8 million, respectively, while
SEGCO plans capital additions of $13 million to generating facilities. (See Item
1 - BUSINESS - "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 changes
in such factors as: business conditions; environmental regulations; nuclear
plant regulations; FERC rules and transmission regulations; load projections;
the cost and efficiency of construction 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.
By the end of 2005, Southern Power plans to have approximately 6,600
megawatts of available generating capacity in commercial operation. At December
31, 2002, 2,400 megawatts were in commercial operation. Significant construction
of transmission and distribution facilities and upgrading of generating plants
will also be continuing, including expenditures to meet environmental compliance
requirements.
Under Georgia law, Georgia Power and Savannah Electric each are required 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 PPAs. (See Item 1 - BUSINESS - "Rate Matters - Integrated Resource Planning"
herein.)
See Item 1 - BUSINESS - "Regulation - Environmental Statutes and 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 Power's, Georgia Power's
and Southern Power's joint ownership of certain generating units and related
facilities with certain non-affiliated utilities.
I-10
Financing Programs
The amount and timing of additional equity capital to be raised in 2003, 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 and Southern Company's stock plans.
The operating companies plan to obtain the funds required for construction
and other purposes from sources similar to those used in the past, which were
primarily from internal sources and by the issuances of new debt and preferred
equity securities, term loans and short-term borrowings. However, the type and
timing of any financings -- if needed -- will depend on market conditions and
regulatory approval. In recent years, financings primarily have been unsecured
debt and trust preferred securities.
Southern Power will use both external funds and equity capital from Southern
Company to finance its construction program. External funds are expected to be
obtained from the issuance of unsecured senior debt and commercial paper or
through existing credit arrangements from banks.
Short-term debt is often utilized as appropriate at Southern Company, the
operating companies, SEGCO and Southern Power.
The maximum amounts of short-term and/or term-loan indebtedness authorized
by the appropriate regulatory authorities and, in the case of Southern Power,
long-term debt which also falls under Southern Power's regulatory authority, are
shown in the following table:
Amount Outstanding at
Authorized December 31, 2002
-------------- ------------------
(in millions)
Alabama Power $1,000(1) $ 37
Georgia Power 3,200(2) 358
Gulf Power 300(1) 28
Mississippi Power 500(1) -
Savannah Electric 120(2) 28
Southern Power 2,500(3) 955
Southern Company 2,000(1) 435
-----------------------------------------------------
Notes:
(1) Alabama Power's authority is based on authorization received from the
Alabama PSC, which expires December 31, 2004. No SEC authorization is required
for Alabama Power. Gulf Power, Mississippi Power and Southern Company 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, March 31, 2006 and December 31, 2004, respectively.
(2) Georgia Power and Savannah Electric 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 March 31, 2006. Authorization for
term-loan indebtedness is also required by the Georgia PSC. Savannah Electric
has $16 million remaining authority for long-term debt and term loans expiring
December 31, 2003. Georgia Power has $837 million remaining authority for
long-term debt expiring December 31, 2004. Georgia Power also has authority
for up to $1.765 billion for borrowings under the term loan provisions of its
credit facilities.
(3) Southern Power has been authorized by the SEC to enter into various
financing arrangements, including short-term loans, through June 30, 2005, which
in the aggregate may not exceed $2.5 billion.
Reference is made to Note 8 to the financial statements for Southern Company
and Gulf Power, Note 7 to the financial statements for Alabama Power and
Mississippi Power, Note 6 to the financial statements for Savannah Electric and
Note 9 to the financial statements for Georgia Power under the heading "Bank
Credit Arrangements" and Note 7 to the financial statements for Southern Power
under the heading "Long-Term Debt" in Item 8 herein for information regarding
the registrants' bank credit arrangements.
I-11
Fuel Supply
The operating companies' and SEGCO's supply of electricity is derived
predominantly from coal. Southern Power's supply of electricity is primarily
fueled by natural gas. The sources of generation for the years 2000 through 2002
are shown below:
Coal Nuclear Hydro Gas Oil
% % % % %
---------------------------------------------
Alabama Power
2000 72 19 3 6 *
2001 64 18 6 12 *
2002 62 19 6 13 *
Georgia Power
2000 76 21 1 1 1
2001 75 23 1 1 *
2002 78 21 1 * *
Gulf Power
2000 98 ** ** 2 *
2001 99 ** ** 1 *
2002 82 ** ** 18 *
Mississippi Power
2000 83 ** ** 17 *
**
2001 59 ** ** 41 *
2002 57 ** ** 43 *
Savannah Electric
2000 88 ** ** 8 4
2001 93 ** ** 6 1
2002 91 ** ** 8 1
SEGCO
2000 100 ** ** * *
2001 100 ** ** * *
2002 100 ** ** * *
Southern Power
2000 ** ** ** ** **
2001 ** ** ** 100 *
2002 ** ** ** 100 *
Southern Company system***
2000 78 16 2 4 *
2001 72 16 3 9 *
2002 69 16 3 12 *
- ------------------------------------------------------------------
*Less than 0.5%.
**Not applicable.
*** Amounts shown for the Southern Company system are weighted averages of the
operating companies, Southern Power and SEGCO.
The average costs of fuel in cents per net kilowatt-hour generated for 2000
through 2002 are shown below:
2000 2001 2002
-------------------------------
Alabama Power 1.54 1.56 1.47
Georgia Power 1.39 1.38 1.44
Gulf Power 1.68 1.76 2.08
Mississippi Power 1.80 1.89 2.03
Savannah Electric 2.28 2.16 2.44
SEGCO 1.51 1.44 1.50
Southern Power - 4.07 2.81
Southern Company
System* 1.51 1.56 1.61
- --------------------------------------------------------------
* Amounts shown for the Southern Company system are weighted averages of the
operating companies, Southern Power and SEGCO.
I-12
The operating companies have long-term agreements in place from which they
expect to receive approximately 84% of their coal burn requirements in 2003.
These agreements cover remaining terms up to 8 years. In 2002, the weighted
average sulfur content of all coal burned by the operating companies was 0.76%
sulfur. This sulfur level, along with banked sulfur dioxide allowances, allowed
the operating companies to remain within limits as set forth by Phase II of the
Clean Air Act. 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 Statutes and Regulation" herein.
The operating companies, Southern Power and Southern Company GAS also have
long-term agreements in place for their natural gas burn requirements. For 2003,
the operating companies and Southern Power have contracted for 200 billion cubic
feet of natural gas supply. These agreements cover remaining terms up to 4
years. In addition to gas supply, the operating companies, Southern Power and
Southern Company GAS have contracts in place for both firm gas transportation
and storage. Management believes that these contracts provide sufficient natural
gas supplies, transportation and storage to ensure normal operations of the
Southern Company system's natural gas generating units.
Changes in fuel prices are generally reflected in fuel adjustment clauses
contained in rate schedules. See Item 1 - BUSINESS - "Rate Matters - Rate
Structure" herein.
Alabama Power and Georgia Power 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 Company system's nuclear
generating units.
Alabama Power and Georgia Power 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 pool storage capacity is available at Plant Farley to maintain
full-core discharge capability until the refueling outages scheduled for 2006
and 2008 for units 1 and 2, respectively. Sufficient pool storage capacity for
spent fuel is available at Plant Vogtle to maintain full-core discharge
capability for both units into 2014. At Plant Hatch, an on-site dry storage
facility became operational in 2000. Sufficient dry storage capacity is believed
to be available to continue dry storage operations at Plant Hatch through the
life of the plant. Procurement of on-site dry storage capacity at Plant Farley
is in progress, with the intent to place the capacity in operation in 2005.
Procurement of on-site dry storage capacity at Plant Vogtle will begin in
sufficient time to maintain pool full-core discharge capability.
The Energy Act 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, including Alabama Power and Georgia
Power. 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.
Territory Served by the Operating Companies
The territory in which the operating companies provide electric service
comprises most of the states of Alabama and Georgia together with the
northwestern portion of Florida and southeastern Mississippi. In this territory
there are non-affiliated electric distribution systems which obtain some or all
of their power requirements either directly or indirectly from the operating
companies. The territory has an area of approximately 120,000 square miles and
an estimated population of approximately 11 million.
Alabama Power 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 Power also
I-13
supplies steam service in downtown Birmingham. Alabama Power also sells, and
cooperates with dealers in promoting the sale of, electric appliances.
Georgia Power 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, Dalton and the City of Hampton.
Gulf Power 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.
Mississippi Power 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 Electric 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 Company 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 Company system, each of the operating companies and
Southern Power, reference is made to Item 6 herein.
A portion of the area served by the operating companies adjoins the area
served by TVA and its municipal and cooperative distributors. An Act of Congress
limits the distribution of TVA power, unless otherwise authorized by Congress,
to specified areas or customers which generally were those served on July 1,
1957.
The RUS has authority to make loans to cooperative associations or
corporations to enable them to provide electric service to customers in rural
sections of the country. There are 71 electric cooperative organizations
operating in the territory in which the operating companies 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 Power'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 Power's service territory obtain a portion of their power requirements
directly from Alabama Power.
Four electric cooperative associations, financed by the RUS, operate within
Gulf Power's service area. These cooperatives purchase their full requirements
from AEC and SEPA (a federal power marketing agency). A non-affiliated utility
also operates within Gulf Power's service area and purchases its full
requirements from Gulf Power.
Alabama Power and Gulf Power have entered into separate agreements with AEC
involving interconnection between their respective systems. The delivery of
capacity and energy from AEC to certain distributing cooperatives in the service
areas of Alabama Power and Gulf Power is governed by the Southern Company/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 Power's
joint-ownership with AEC of a portion of Plant Miller.
Mississippi Power 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 Power to SMEPA.
SMEPA has a generating capacity of 1,947 megawatts and a transmission system
estimated to be 1,570 miles in length.
I-14
There are 43 electric cooperative organizations operating in, or in areas
adjoining, territory in the State of Georgia in which Georgia Power provides
electric service at retail or wholesale. Three of these organizations obtain
their power from TVA and one from other sources. OPC has a wholesale power
contract with the remaining 39 of these cooperative organizations. OPC utilizes
self-owned generation, some of which is acquired and jointly-owned with Georgia
Power, megawatt capacity purchases from Georgia Power under power supply
agreements, and other arrangements to meet its power supply obligations.
Pursuant to the latest agreement entered into in April 1999, OPC will purchase
250 megawatts of steam capacity through March 2006.
There are 65 municipally-owned electric distribution systems operating in
the territory in which the operating companies provide electric service at
retail or wholesale.
AMEA was organized under an act of the Alabama legislature and is comprised
of 11 municipalities. In October 1991, Alabama Power entered into a power sales
contract with AMEA entitling AMEA to scheduled amounts of additional capacity
(up to a maximum 80 megawatts) for a period of 15 years. Under the terms of the
contract, Alabama Power received payments from AMEA representing the net present
value of the revenues associated with the respective capacity entitlements. (See
Note 5 to Alabama Power's financial statements under the heading "Alabama
Municipal Electric Authority (AMEA) Capacity Contracts" in Item 8 herein for
further information on this contract.)
Forty-eight municipally-owned electric distribution systems and one
county-owned system receive their requirements through MEAG, which was
established by a Georgia state statute in 1975. MEAG serves these requirements
from self-owned generation facilities, some of which are acquired and
jointly-owned with Georgia Power, power purchased from Georgia Power and
purchases from other resources. In 1997, a pseudo scheduling and services
agreement was implemented between Georgia Power and MEAG. Since 1977, Dalton has
filled its requirements from self-owned generation facilities, some of which are
acquired and jointly-owned with Georgia Power, and through purchases from
Georgia Power pursuant to their partial requirements tariff. Beginning January
1, 2003, Dalton has entered into a new power supply agreement pursuant to which
it will purchase 136 megawatts from Georgia Power for a fifteen-year term. One
municipally-owned electric distribution system's full requirements are served
under a market-based contract by Georgia Power. (See Item 2 - PROPERTIES -
"Jointly-Owned Facilities" herein.)
Georgia Power 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.)
In June 2002, Southern Power executed PPAs to coordinate the existing
generating resources and meet the load growth and resource-retirement capacity
requirements (Requirements Agreements) of 11 Georgia Electric Membership
Corporations (EMCs). These Requirements Agreements were entered into pursuant to
market-based tariff arrangements and are subject to filing and acceptance by the
FERC. No state PSC approval is required. Under the terms of the agreements, both
the loads and the resources of the EMCs will be integrated into the Southern
Company system power pool as obligations and resources of Southern Power.
Southern Power will fulfill the load requirements of the EMCs by utilizing the
EMCs' entitlements to capacity resources owned by OPC and other capacity
purchase contracts.
In January 2003, Southern Power entered into contracts with North Carolina
Municipal Power Authority 1 (North Carolina) and Dalton. Under the North
Carolina contract, Southern Power will be responsible for supplying North
Carolina's capacity and energy needs in excess of North Carolina's existing
resources and disposing of North Carolina's surplus energy. The contract term is
January 1, 2003 through December 31, 2004. Under the Dalton contract, Southern
Power is responsible for supplying Dalton's requirements for capacity and energy
in excess of Dalton's existing resources. The contract term is for 15 years,
beginning January 1, 2003, with a customer option to convert to a fixed capacity
purchase at the end of year 10.
I-15
SCS, acting on behalf of Alabama Power, Georgia Power, Gulf Power,
Mississippi Power and Savannah Electric, also has a contract with SEPA 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 Power; 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 Electric 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 and Vernonburg, and in conjunction with a
secondary supplier, the Town of Richmond Hill. In addition, Savannah Electric
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 Power and to
six distribution rural cooperatives operating in southeastern Mississippi, then
served in whole or in part by Mississippi Power, 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
The operating companies have long-term contractual agreements for the sale of
capacity to certain non-affiliated utilities located outside the Southern
Company system service area. These agreements are related to specific generating
units and the availability of energy at those units. Because the energy is
generally provided at cost under these agreements, profitability is primarily
affected by capacity revenues.
Mississippi Power and Southern Power have contractual agreements with
non-affiliated companies for the sale of capacity from certain generating units.
Reference is made to "Management's Discussion and Analysis - Future Earnings
Potential" in Item 7 herein of Mississippi Power and Southern Power for
information on a customer for such capacity that is experiencing liquidity
problems and has had its credit rating reduced below investment grade.
Unit power from specific generating plants is currently being sold to FP&L,
FPC and JEA. Under these agreements, approximately 1,500 megawatts of capacity
is scheduled to be sold annually unless reduced by FP&L, FPC and JEA for the
periods after 2002 with a minimum of three years notice, until the expiration of
the contracts in 2010.
Reference is made to Note 5 to the financial statements for Southern
Company, Alabama Power and Southern Power, Note 6 to the financial statements
for Gulf Power and Note 7 to the financial statements for Georgia Power under
I-16
the heading "Long-Term Sales Agreements" and Note 5 to the financial statements
for Mississippi Power under the heading "Long-Term Sales and Facility
Agreements" in Item 8 herein for additional information regarding contracts for
the sales and lease of capacity and energy to non-territorial customers.
Competition
The electric utility industry in the United States is continuing to evolve as a
result of regulatory and competitive factors. Among the early primary agents of
change was the Energy Act. The Energy Act allows IPPs to access a utility's
transmission network in order to sell electricity to other utilities. This
enhanced the incentive for IPPs to build power plants for a utility's large
industrial and commercial customers and sell energy generation to other
utilities. Also, electricity sales for resale rates were affected by numerous
new energy suppliers, including power marketers and brokers.
This past year, merchant energy companies and traditional electric utilities
with significant energy marketing and trading activities came under severe
financial pressures. Many of these companies have completely exited or
drastically reduced all energy marketing and trading activities as well as
selling foreign and domestic electric infrastructure assets. Southern Company
has not experienced any material financial impact regarding its limited energy
trading operations and recent generating capacity additions. In general,
Southern Company only constructs new generating capacity after entering into
long-term capacity contracts for the new facilities or to meet requirements of
Southern Company's regulated retail markets.
Although the Energy Act does not provide for retail customer access, it was a
major catalyst for recent restructuring and consolidations that took place
within the utility industry. Numerous federal and state initiatives that promote
wholesale and retail competition are in varying stages. Among other things,
these initiatives allow customers to choose their electricity provider. 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 discussed in Alabama, Florida, Georgia, and
Mississippi, none have been enacted. Enactment would require numerous issues to
be resolved, including significant ones relating to recovery of any stranded
investments, full cost recovery of energy produced, and other issues related to
the energy crisis that occurred in California. As a result of that crisis, many
states, including those in Southern Company's retail service area, have either
discontinued or delayed implementation of initiatives involving retail
deregulation.
Continuing to be a low-cost producer could provide opportunities to
increase market share and profitability in markets that evolve with changing
regulation and competition. Conversely, if Southern Company's electric utilities
do not remain low-cost producers and provide quality service, then energy sales
growth could be limited, and this could significantly erode earnings. Reference
is made to Alabama Power, Georgia Power, Gulf Power, Mississippi Power and
Savannah Electric, "Management's Discussion and Analysis - Future Earnings
Potential" in Item 7 herein for further discussion of rate matters.
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 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. (See Item 1
- - BUSINESS - "Southern Power" and "Other Business" herein.)
The Energy Act amended the Holding Company Act to facilitate acquisitions of
interest in exempt wholesale generators, which sell electricity exclusively for
resale.
Southern Company is working to maintain and expand its share of wholesale
energy sales in the Southeast. In January 2001, Southern Company formed Southern
Power. This subsidiary constructs, owns, and manages wholesale generating assets
in the Southeast. Southern Power is the primary growth engine for Southern
I-17
Company's competitive wholesale market-based energy business.
Reference is made to Item 1 - BUSINESS - "FERC Matters" herein for
information relating to Southern Company's RTO filing with the FERC.
Alabama Power currently has cogeneration contracts in effect with 11
industrial customers. Under the terms of these contracts, Alabama Power
purchases excess generation of such companies. During 2002, Alabama Power
purchased approximately 169.3 million kilowatt-hours from such companies at a
cost of $4.8 million.
Georgia Power currently has contracts in effect with nine small power
producers whereby Georgia Power purchases their excess generation. During 2002,
Georgia Power purchased 16.7 million kilowatt-hours from such companies at a
cost of $384 thousand. Georgia Power has PPAs for electricity with two
cogeneration facilities. Payments are subject to reductions for failure to meet
minimum capacity output. During 2002, Georgia Power purchased 867 million
kilowatt-hours at a cost of $75 million from these facilities. Reference is made
to Note 4 to the financial statements for Georgia Power in Item 8 herein for
information regarding purchased power commitments.
Gulf Power currently has agreements in effect with four industrial
customers pursuant to which Gulf Power purchases "as available" energy from
customer-owned generation. During 2002, Gulf Power purchased 199 million
kilowatt-hours from such companies for $5 million.
During 2002, Savannah Electric purchased energy from six customer owned
generating facilities. Five of the six provide only excess energy to Savannah
Electric and are paid Savannah Electric's avoided energy cost. These five
customers make no capacity commitment and are not dispatched by Savannah
Electric. Savannah Electric does have a contract for five megawatts of
dispatchable capacity and energy with one customer. During 2002, Savannah
Electric purchased a total of 23.6 million kilowatt-hours from the six suppliers
at a cost of approximately $730 thousand.
The competition for retail energy sales among competing suppliers of energy
is influenced by various factors, including price, availability, technological
advancements and reliability. These factors are, in turn, affected by, among
other influences, regulatory, political and environmental considerations,
taxation and supply.
The operating companies 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 Operating Companies" herein for information concerning
suppliers of electricity operating within or near the areas served at retail by
the operating companies.)
Regulation
State Commissions
The operating companies 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 Operating Companies" herein.)
Holding Company Act
Southern Company 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
Company's other 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 operating companies, Southern Power and SEGCO
to regulation by the FERC as companies engaged in the transmission or sale at
I-18
wholesale of electric energy in interstate commerce, including regulation of
accounting policies and practices.
Alabama Power and Georgia Power 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 Power
generating stations having an aggregate installed capacity of 1,600,750
kilowatts and 18 existing Georgia Power generating stations having an aggregate
installed capacity of 1,074,696 kilowatts.
Georgia Power filed a relicensing application with the FERC for the Middle
Chattahoochee project in December 2002. This project consists of the Goat Rock,
Oliver and North Highlands facilities. Georgia Power also started the
relicensing process for the Morgan Falls Project in 2003. Alabama Power
initiated the relicensing process in 2002 for its seven projects on the Coosa
River (Weiss, Henry, Logan Martin, Lay, Mitchell, Jordan and Bouldin) and the
Smith and Bankhead Projects on the Warrior River. The FERC licenses for all of
these nine projects expire in 2007.
Georgia Power 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.)
Licenses for all projects, excluding those discussed above, expire in the
period 2007-2033 in the case of Alabama Power's projects and in the period
2005-2039 in the case of Georgia Power'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 Power, Georgia Power 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, and in January 2027 and February 2029
for Plant Vogtle units 1 and 2, respectively. In January 2002, the NRC granted
Georgia Power a 20-year extension of the licenses for both units at Plant Hatch
which permits the operation of units 1 and 2 until 2034 and 2038, respectively.
Applications are currently being prepared to request extension of the Plant
Farley units 1 and 2 licenses until 2037 and 2041, respectively.
Reference is made to Notes 1 and 10 to
Southern Company's financial statements, Notes 1 and 9 to Alabama Power's
financial statements and Notes 1 and 5 to Georgia Power's financial statements
in Item 8 herein for information on nuclear decommissioning costs and nuclear
insurance. Additionally, Note 3 to Georgia Power's financial statements contains
information regarding nuclear performance standards imposed by the Georgia PSC
that may impact retail rates.
FERC Matters
In December 1999, the FERC issued its final rule on RTOs. The order encouraged
utilities owning transmission systems to form RTOs on a voluntary basis.
Southern Company has submitted a series of status reports informing the FERC of
progress toward the development of a Southeastern RTO. In these status reports,
Southern Company explained that it is developing a for-profit RTO known as
SeTrans with a number of non-jurisdictional cooperative and public power
entities. In 2001, Entergy Corporation and Cleco Power joined the SeTrans
development process. In 2002, the sponsors of SeTrans established a Stakeholder
Advisory Committee, which will participate in the development of the RTO, and
held public meetings to discuss the SeTrans proposal. On October 10, 2002, the
FERC granted Southern Company's and other SeTrans' sponsors petition for a
I-19
declaratory order regarding the governance structure and the selection process
for the Independent System Administrator (ISA) of the SeTrans RTO. The FERC also
provided guidance on other issues identified in the petition. The SeTrans
sponsors announced the selection of ESB International, Ltd. (ESBI) to be the
preferred ISA candidate. Should negotiations with this candidate successfully
conclude with final agreement among the parties, the SeTrans sponsors intend to
seek any regulatory or other approvals necessary for formation of the SeTrans
RTO and the approval of ESBI to serve in the capacity of the SeTrans ISA. The
creation of SeTrans is not expected to have a material impact on Southern
Company's financial statements; however, the outcome of this matter cannot now
be determined.
In July 2002, the FERC issued a notice of proposed rulemaking regarding open
access transmission service and standard electricity market design. The
proposal, if adopted, would among other things: (1) require transmission assets
of jurisdictional utilities to be operated by an independent entity; (2)
establish a standard market design; (3) establish a single type of transmission
service that applies to all customers; (4) assert jurisdiction over the
transmission component of bundled retail service; (5) establish a generation
reserve margin; (6) establish bid caps for a day ahead and spot energy markets;
and (7) revise the FERC policy on the pricing of transmission expansions.
Comments on certain aspects of the proposed rule have been submitted by Southern
Company. Any impact of this proposal on Southern Company and its subsidiaries
will depend on the form in which final rules may be ultimately adopted; however,
Southern Company's revenues, expenses, assets, and liabilities could be
adversely affected by changes in the transmission regulatory structure in its
regional power market.
Environmental Statutes and Regulations
Southern Company's operations are subject to extensive regulation by state and
federal environmental agencies under a variety of statutes and regulations
governing environmental media, including air, water, and land resources.
Compliance with these environmental requirements will involve significant costs,
a major portion of which is expected to be recovered through existing ratemaking
provisions. There is no assurance, however, that all such costs will, in fact,
be recovered.
Compliance with the federal Clean Air Act and resulting regulations has been,
and will continue to be, a significant focus for Southern Company. For
additional information about the Clean Air Act and other environmental issues,
including the litigation brought under the New Source Review provisions of the
Clean Air Act, reference is made to each registrant's "Management's Discussion
and Analysis - Environmental Matters" in Item 7 herein. Also see Item 3 - "Legal
Proceedings," herein for information about lawsuits brought on behalf of the EPA
or by citizen's groups with respect to environmental compliance matters.
The operating companies', Southern Power's and SEGCO's estimated capital
expenditures for environmental quality control facilities for the years 2003,
2004 and 2005 are as follows:
---------------------------------------------------------
2003 2004 2005
-------------------------------
(in millions)
Alabama Power $100 $157 $234
Georgia Power 106 64 51
Gulf Power 38 64 55
Mississippi
Power 11 6 -
Savannah Electric 1 5 3
Southern Power - - -
SEGCO 1 4 3
---------------------------------------------------------
Total $257 $300 $346
=========================================================
The foregoing estimates are included in the current construction programs.
(See Item 1 - BUSINESS - "Construction Programs" herein.)
Additionally, each operating company and SEGCO have incurred costs for
environmental remediation of various sites. Reference is made to each
registrant's "Management's Discussion and Analysis - Financial Condition" in
Item 7 herein for information regarding the registrants' environmental
remediation efforts. Also, see Note 3 to Southern Company's and Georgia Power's
financial statements in Item 8 herein for information regarding the
identification of sites that may require environmental remediation by Georgia
Power.
The operating companies and SEGCO are unable to predict at this time what
additional steps they may be required to take as a result of the implementation
I-20
of existing or future quality control requirements for air, water and hazardous
or toxic materials, but such steps could adversely affect system operations and
result in substantial additional costs.
The outcome of the matters mentioned above under "Regulation" cannot now be
determined, except that these developments may result in delays in obtaining
appropriate licenses for generating facilities, increased construction and
operating costs or reduced generation, the nature and extent of which, while not
determinable at this time, could be substantial.
Rate Matters
Rate Structure
The rates and service regulations of the operating companies 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 and
include rates with special features to encourage off-peak usage. Additionally,
the operating companies 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
Power, Georgia Power, Mississippi Power and Savannah Electric 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 as needed. Gulf Power also recovers from retail customers costs of fuel,
net purchased power, energy conservation and environmental compliance through
provisions approved by the Florida PSC which are adjusted annually to reflect
increases or decreases in such costs. Revenues are adjusted for differences
between recoverable costs and amounts actually recovered in current rates.
Reference is made to "Management's Discussion and Analysis - Future
Earnings Potential" in Item 7 and to Note 3 to the financial statements in Item
8 herein for Alabama Power, Georgia Power, Gulf Power, Mississippi Power and
Savannah Electric for a discussion of rate matters.
Integrated Resource Planning
Georgia Power and Savannah Electric must file plans with the Georgia PSC that
specify how each intends to meet the future electrical needs of its customers
through a combination of demand-side and supply-side resources. The Georgia PSC
must certify these new resources. Once certified, all prudently incurred
construction costs and purchase power costs will be recoverable through rates.
In July 2001, the Georgia PSC approved Georgia Power's 2003/04
certification request for approximately 1,800 megawatts of purchased power and
12 megawatts of upgraded hydro generation. This certification request included a
seven-year PPA with Southern Power for two gas-fired combined cycle units that
will be constructed at Plant Franklin. The first unit will be for 570 megawatts
starting in 2003, with approximately 250 megawatts made available in June 2002.
The second unit will be for 610 megawatts starting in 2004, with approximately
300 megawatts being available by June 2003. Also, an upgrade of 12 megawatts was
approved for the existing Goat Rock hydro Units 1 and 2. In addition, this
certification request included a seven-year PPA with Southern Power for 615
megawatts of gas-fired combined cycle generation at Plant Harris in Alabama.
Based on an agreement with the Georgia PSC, the seven-year term was modified to
be 15 years.
In December 2002, the Georgia PSC approved Georgia Power's and Savannah
Electric's plans to expand their electricity generating capacity starting in
2005 through PPAs. Beginning in June 2005, Georgia Power and Savannah Electric
will purchase 1,040 and 200 megawatts of capacity, respectively, from the
planned combined-cycle plant at Plant McIntosh, to be built and owned by
Southern Power under a 15-year PPA. Beginning June 1, 2005, Georgia Power will
also buy 620 megawatts of capacity from a Murray County plant owned by Duke
Energy Trading and Marketing under a seven-year PPA. The Georgia PSC also
approved the retirement of 415 megawatts from 11 units at Georgia Power Plants
Arkwright, Atkinson, and Mitchell. Savannah Electric also plans to retire a 102
I-21
megawatt peaking facility in May 2005. Reference is made to Georgia Power's and
Savannah Electric's "Management's Discussion and Analysis - Future Earnings
Potential" in Item 7 herein for information regarding these PPAs and
retirements.
In December 2002, Georgia Power issued an RFP for 600 to 800 megawatts of
capacity to serve 2007 needs in accordance with the updated IRP that was filed
during the 2005 certification with the Georgia PSC.
Georgia Power and Savannah Electric will file a new IRP with the Georgia
PSC in January 2004.
Environmental Cost Recovery Plans
In 1993, the Florida Legislature adopted legislation for an Environmental Cost
Recovery Clause (ECRC), which allows Gulf Power to petition the Florida PSC for
recovery of 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.
This legislation was amended in 2002 to allow recovery of costs incurred as
a result of an agreement between Gulf Power and the Florida Department of
Environmental Protection for the purpose of ensuring compliance with ozone
ambient air quality standards adopted by the EPA.
In 1992, the Mississippi PSC approved Mississippi Power's Environmental
Compliance Overview Plan (ECO Plan). The ECO Plan establishes procedures to
facilitate the Mississippi PSC's overview of Mississippi Power's environmental
strategy and provides for recovery of costs (including costs of capital
associated with environmental projects approved by the Mississippi PSC). Under
the ECO Plan, any increase in the annual revenue requirement is limited to 2
percent of retail revenues. However, the ECO Plan also provides for carryover of
any amount over the 2 percent limit into the next year's revenue requirement.
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. Mississippi Power recovers such
costs under the ECO Plan as they are incurred, as provided for in Mississippi
Power's 1995 ECO Plan order. Mississippi Power filed its 2003 ECO Plan in
January 2003, which, if approved as filed, will result in a slight increase in
customer prices.
Employee Relations
The Southern Company system had a total of 26,178 employees on its payroll at
December 31, 2002.
----------------------------------------------------------
Employees
at
December 31, 2002
---------------------
Alabama Power 6,715
Georgia Power 8,837
Gulf Power 1,339
Mississippi Power 1,301
Savannah Electric 550
SCS 3,499
Southern Nuclear 3,295
Southern Power *
Other 642
----------------------------------------------------------
Total 26,178
==========================================================
* Southern Power has no employees. Southern Power has agreements with SCS and
the operating companies whereby employee services are rendered at cost.
The operating companies 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 Power has agreements with the IBEW on a three-year contract
extending to August 14, 2004. 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 Power has an agreement with the IBEW covering wages and working
conditions, which is in effect through June 30, 2005.
Gulf Power has an agreement with the IBEW on a three-year contract
extending to August 15, 2005.
Mississippi Power has an agreement with the IBEW on a four-year contract
extending to August 16, 2006.
I-22
Savannah Electric 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. Savannah Electric began negotiations with
the IBEW in February 2003.
Southern Nuclear has agreements with the IBEW on a five-year contract
extending to August 15, 2006 for Plant Farley and an agreement with the
Security, Police and Fire Professionals of America on a three-year contract
extending to September 30, 2004 for Plant Hatch. 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 is currently in negotiations with the IBEW at Plants Hatch
and Vogtle. The prior contract with the Local 84 of the IBEW which extended to
June 30, 2002 was not terminated, so the terms of the existing agreement have
continued while a new agreement is under negotiation. The parties will have the
opportunity to terminate the agreement 60 days prior to June 30, 2003 if no
agreement is reached prior to that time.
The agreements also subject the terms of the pension plans for the companies
discussed above to collective bargaining with the unions at either a five-year
or a ten-year cycle, depending upon union and company actions.
I-23
Item 2. PROPERTIES
Electric Properties - The Electric Utilities
The operating companies, Southern Power and SEGCO, at December 31, 2002, owned
and/or operated 34 hydroelectric generating stations, 33 fossil fuel generating
stations, three nuclear generating stations and eight combined
cycle/cogeneration stations. The amounts of capacity for 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
Greene County Demopolis, AL 300,000 (2)
Gaston Unit 5 Wilsonville, AL 880,000
Miller Birmingham, AL 2,532,288 (3)
---------
Alabama Power Total 6,578,538
---------
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 125,000
Scherer Macon, GA 750,924 (4)
Wansley Carrollton, GA 925,550 (5)
Yates Newnan, GA 1,250,000
---------
Georgia Power Total 9,156,174
---------
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 Power 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 Power 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 Electric Total 546,531
-----------
Gaston Units 1-4 Wilsonville, AL
SEGCO Total 1,000,000 (7)
-----------
Total Fossil Steam 21,275,243
-----------
Nuclear Steam
Farley Dothan, AL
Alabama Power Total 1,720,000
-----------
Hatch Baxley, GA 899,612 (8)
Vogtle Augusta, GA 1,060,240 (9)
-----------
Georgia Power Total 1,959,852
----------
Total Nuclear Steam 3,679,852
-----------
Combustion Turbines
Greene County Demopolis, AL
Alabama Power Total 720,000
-----------
Atkinson Atlanta, GA 78,720
Bowen Cartersville, GA 39,400
Intercession City Intercession City, FL 47,667 (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
Wansley Carrollton, GA 26,322
Wilson Augusta, GA 354,100
-----------
Georgia Power Total 1,864,909
- ---------
Lansing Smith
Unit A Panama City, FL 39,400
Pea Ridge
Units 1-3 Pea Ridge, FL 15,000
---------
Gulf Power Total 54,400
---------
Chevron Cogenerating
Station Pascagoula, MS 147,292 (11)
Sweatt Meridian, MS 39,400
Watson Gulfport, MS 39,360
---------
Mississippi Power Total 226,052
---------
-------------------------------------------------------------------
I-24
------------------------------------------------------------------
Generating Station Location Nameplate
Capacity
------------------------------------------------------------------
(Kilowatts)
Boulevard Savannah, GA 59,100
Kraft Port Wentworth,
GA 22,000
McIntosh Units 5&6 Effingham
County, GA 160,000
-------
Savannah Electric Total 241,100
-------
241,100
Dahlberg 756,000 (12)
--------
Southern Power Total 756,000
-------
Gaston (SEGCO) Wilsonville, AL 19,680 (7)
-----------
Total Combustion Turbines 3,882,141
-----------
Cogeneration
Washington County Washington
County, AL 123,428
GE Plastics Project Burkeville, AL 104,800
Theodore Theodore, AL 236,418
-----------
Alabama Power Total 464,646
-----------
Combined Cycle
Barry Mobile, AL
Alabama Power Total 1,070,424
---------
Smith
Gulf Power Total 619,650
-------
Daniel (Leased) Pascagoula, MS
Mississippi Power Total 1,070,424
---------
Franklin 538,900 (12)
Wansley 1,073,000 (12)
---------
Southern Power Total 1,611,900
---------
Total Combined Cycle 4,372,398
---------
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 60,000
Lewis Smith Jasper, AL 157,500
Bankhead Holt, AL 54,000
Holt Holt, AL 46,000
-----------
Alabama Power Total 1,599,600
-----------
------------------------------------------------------------------
Generating Station Location Nameplate
Capacity
------------------------------------------------------------------
(Kilowatts)
(Kilowatts)
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 (13)
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 Power Total 1,077,736
-----------
Total Hydroelectric Facilities 2,677,336
-----------
Total Generating Capacity 36,351,616
===========
------------------------------------------------------------------
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 Power and Mississippi Power as tenants in common in the
proportions of 60% and 40%, respectively.
(3) Excludes the capacity owned by AEC.
(4) Capacity shown for Georgia Power is 8.4% of Units 1 and 2 and 75% of Unit 3.
Capacity shown for Gulf Power is 25% of Unit 3.
(5) Capacity shown is Georgia Power's portion (53.5%) of total plant capacity.
(6) Represents 50% of the plant which is owned as tenants in common by Gulf
Power and Mississippi Power.
(7) SEGCO is jointly-owned by Alabama Power and Georgia Power. (See Item 1 -
BUSINESS herein.)
(8) Capacity shown is Georgia Power's portion (50.1%) of total plant capacity.
(9) Capacity shown is Georgia Power's portion (45.7%) of total plant capacity.
(10)Capacity shown represents 33-1/3% of total plant capacity. Georgia Power
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)In connection with various PPAs, Southern Power conducts unit testing to set
contract capacity availability. At December 31, 2002, such capacity was as
follows:
810,000 kilowatts - Dahlberg
561,300 kilowatts - Franklin
1,134,500 kilowatts - Wansley
(13)Capacity shown is Georgia Power's portion (25.4%) of total plant capacity.
OPC operates the plant.
I-25
Except as discussed below under "Titles to Property," the principal plants
and other important units of the operating companies, Southern Power 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 Power 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 40-year period covering all expenses and the amortization of the
original $57 million cost of the line. At December 31, 2002, the unamortized
portion of this cost was approximately $32.1 million.
The all-time maximum demand on the operating companies, Southern Power and
SEGCO was 32,355,000 kilowatts and occurred in July 2002. 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 operating companies, Southern Power and SEGCO at that
time was 13.3%. For additional information on peak demands, reference is made to
Item 6 - SELECTED FINANCIAL DATA herein.
Alabama Power and Georgia Power 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 the
financial statements of Southern Company, Alabama Power and Georgia Power under
the heading "Depreciation and Nuclear Decommissioning" in Item 8 herein.)
Jointly-Owned Facilities
Alabama Power and Georgia Power have sold and Georgia Power 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:
Percentage Ownership
-------------------------------------------------------------------------------
Total Alabama Georgia
Capacity Power AEC Power 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 143 - - 33.3 - - - 66.7
-------------------------------------------------------------------------------------------------------------------------------
Alabama Power and Georgia Power 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 Power 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 Power's Statements of Income in Item 8 herein.
Additionally, jointly-owned facilities also include Southern Power's 65%
undivided interest in Stanton Unit A and related facilities jointly owned with
the Orlando Utilities Commission, the Kissimmee Utility Authority and the
I-26
Florida Municipal Power Agency. Currently under construction near Orlando,
Florida, this project will be a 610 megawatt combined cycle unit and is
scheduled for commercial operation in October 2003.
Titles to Property
The operating companies', Southern Power's and SEGCO's interests in the
principal plants (other than certain pollution control facilities, one small
hydroelectric generating station leased by Georgia Power, Mississippi Power's
combined cycle units at Plant Daniel and the land on which five combustion
turbine generators of Mississippi Power 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 of
Alabama Power, Gulf Power, Mississippi Power and Savannah Electric and to
excepted encumbrances as defined therein. The operating companies 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.
I-27
Item 3. LEGAL PROCEEDINGS
(1) United States of America v. Alabama Power
(United States District Court for the Northern District of Alabama)
On November 3, 1999, the EPA brought a civil action in the U.S. District
Court in Georgia against Alabama Power. The complaint alleges violations
of the New Source Review provisions of the Clean Air Act with respect to
coal-fired generating facilities at Alabama Power'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 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 relating to these
specific facilities, as well as Plants Greene County and Gaston. On
August 1, 2000, the U.S. District Court granted Alabama Power's motion to
dismiss for lack of jurisdiction in Georgia. On January 12, 2001, the EPA
re-filed its claims against Alabama Power in federal district court in
Birmingham, Alabama. Alabama Power's case has been stayed since the
spring of 2001, pending a ruling by the U.S. Court of Appeals for the
Eleventh Circuit in the appeal of a very similar New Source Review
enforcement action against the TVA. The TVA appeal involves many of the
same legal issues raised by the actions against Alabama Power. Because
the outcome of the TVA appeal could have a significant adverse impact on
Alabama Power, Alabama Power is a party to that case as well. In February
2003, the U.S. District Court in Alabama extended the stay of the EPA
litigation proceeding in Alabama until the earlier of May 6, 2003 or a
ruling by the U.S. Court of Appeals for the Eleventh Circuit in the
related litigation involving TVA.
Alabama Power 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 could possibly require payment of substantial penalties.
(2) United States of America v. Georgia Power and Savannah Electric
(United States District Court for the Northern District of Georgia)
On November 3, 1999, the EPA brought a civil action in the U.S. District
Court in Georgia against Georgia Power. The complaint alleges violation
of the New Source Review provisions of the Clean Air Act with respect to
coal-fired generating facilities at Georgia Power's Plants Bowen and
Scherer. 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. On March 27, 2001, the U.S. District Court granted the EPA's motion
to amend its complaint to add the alleged violations at Savannah
Electric's Plant Kraft and to add Savannah Electric as a defendant. The
EPA concurrently issued a notice of violation relating to these two
Georgia Power plants and Savannah Electric's Plant Kraft.
The cases have been stayed since the spring of 2001, pending a ruling by
the U.S. Court of Appeals for the Eleventh Circuit in the appeal of a
very similar New Source Review enforcement action against the TVA. The
TVA appeal involves many of the same legal issues raised by the actions
against Georgia Power and Savannah Electric. Because the outcome of the
TVA appeal could have a significant adverse impact on Georgia Power,
Georgia Power has been a party to that case as well. On August 21, 2002,
the U.S. District Court in Georgia denied the EPA's motion to reopen the
Georgia case. The denial was without prejudice to the EPA to refile the
I-28
Item 3. LEGAL PROCEEDINGS (Continued)
motion at a later date, which he EPA has not done at this time.
Georgia Power and Savannah Electric believe that they 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 these
matters could require substantial capital expenditures that cannot be
determined at this time and could possibly require payment of substantial
penalties.
(3) Cooper et al. v. Georgia Power, Southern Company, SCS and Energy
Solutions
(Superior Court of Fulton County, Georgia)
On July 28, 2000, a lawsuit alleging race discrimination was filed by
three Georgia Power employees against Georgia Power, Southern Company,
and SCS in the Superior Court of Fulton County, Georgia. Shortly
thereafter, the lawsuit was removed to the United States District Court
for the Northern District of Georgia. The lawsuit also raised claims on
behalf of a purported class. The plaintiffs seek compensatory and
punitive damages in an unspecified amount, as well as injunctive relief.
In August 2000, the lawsuit was amended to add four more plaintiffs.
Also, an additional subsidiary of Southern Company, Energy Solutions (now
Southern Management Development), was named a defendant.
In October 2001, the district court denied the plaintiffs' motion for
class certification. The plaintiffs filed a motion to reconsider the
order denying class certification, and the court denied the plaintiffs'
motion to reconsider. In December 2001, the plaintiffs filed a petition
in the United States Court of Appeals for the Eleventh Circuit seeking
permission to file an appeal of the October 2001 decision. In March 2002,
the Eleventh Circuit denied the plaintiffs' petition. After discovery was
completed on the claims raised by the seven named plaintiffs, the
defendants filed motions for summary judgment on all of the named
plaintiffs' claims. The parties await the court's ruling on the seven
motions for summary judgment. The final outcome of the case cannot now be
determined.
(4) Georgia Power Potentially Responsible Party
Georgia Power has been designated as a potentially responsible party at
sites governed by the Georgia Hazardous Site Response Act and/or by the
federal Comprehensive Environmental Response, Compensation and Liability
Act.
In addition, in 1995 the EPA designated Georgia Power and four other
unrelated entities as potentially responsible parties at a site in
Brunswick, Georgia that is listed on the federal National Priorities
List. Georgia Power has contributed to the removal and remedial
investigation and feasibility study costs for the site. Additional claims
for recovery of natural resource damages at the site are anticipated.
The final outcome of these matters cannot now be determined.
Reference is made to Note 3 to Southern Company's and Georgia Power's
financial statements in Item 8 herein under the headings "Georgia Power
Potentially Responsible Party Status" and "Other Environmental
Contingencies," respectively.
(5) In re: Mobile Energy Services Company, LLC; In re: Mobile Energy Services
Holdings, Inc.
(U.S. Bankruptcy Court for the Southern District of Alabama)
In August 2000, MESH filed a proposed plan of reorganization with the
U.S. Bankruptcy Court. The proposed plan of reorganization was most
recently amended on December 13, 2001. Southern Company expects that
I-29
Item 3. LEGAL PROCEEDINGS (Continued)
approval of a plan of reorganization would result in a termination of
Southern Company's ownership interest in MESH but would not affect
Southern Company's continuing guarantee obligations discussed earlier.
The final outcome of this matter cannot now be determined.
Reference is made to Note 3 to Southern Company's financial statements in
Item 8 herein under the heading "Mobile Energy Services' Petition for
Bankruptcy."
(6) Gordon v. Southern Company et al.
(United States District Court for the Southern District of California)
and
(7) Pier 23 Restaurant v. Southern Company et al.
(United States District Court for the Northern District of California)
Prior to the spin off of Mirant, Southern Company was named as a
defendant in two lawsuits filed in the superior courts of California
alleging that certain owners of electric generation facilities in
California, including Southern Company, engaged in various unlawful and
anticompetitive acts that served to manipulate wholesale power markets
and inflate wholesale electricity prices in California. One lawsuit
naming Southern Company, Mirant and other generators as defendants
alleged that, as a result of the defendants' conduct, customers paid
approximately $4 billion more for electricity than they otherwise would
have and sought an award of treble damages, as well as other injunctive
and equitable relief. The other suit likewise sought treble damages and
equitable relief. The allegations in the two lawsuits in which Southern
Company was named seemed to be directed to activities of subsidiaries of
Mirant. In the fall of 2001, the plaintiffs voluntarily dismissed
Southern Company without prejudice from the two lawsuits in which it had
been named as a defendant. Prior to being dismissed, Southern Company had
notified Mirant of its claim for indemnification for costs associated
with the lawsuits under the terms of the master separation agreement that
governs the spin off of Mirant. Mirant had undertaken the defense of the
lawsuits. Plaintiffs would not be barred by their own dismissal from
naming Southern Company in some future lawsuit, but management believes
that the likelihood of Southern Company having to pay damages in any such
lawsuit is remote.
(8) California Electricity Markets Investigation
Southern Company has received a subpoena to provide information to a
federal grand jury in the Northern District of California. The subpoena
covers a number of broad areas, including specific information regarding
electricity production and sales activities in California. Southern
Company's former subsidiary, Mirant, participated in energy marketing and
trading in California during the period relevant to the subpoena.
Southern Company has produced documents in response to the subpoena and
is fully cooperating in the investigation.
(9) In re: Mirant Corporation Securities Litigation
(United States District Court for the North District of Georgia)
In November 2002, Southern Company, along with certain former and current
senior officers of Southern Company and 12 underwriters of Mirant's
initial public offering, were added as defendants in a class action
lawsuit that several Mirant shareholders originally filed against Mirant
and certain Mirant officers in May 2002. The original lawsuit against
Mirant and its officers was based on allegations related to alleged
improper energy trading and marketing activities involving the California
energy market. Several other similar lawsuits filed subsequently were
consolidated into this litigation in the United States District Court
for the Northern District of Georgia. The November 2002 amended complaint
I-30
Item 3. LEGAL PROCEEDINGS (Continued)
is based on allegations related to alleged improper energy trading and
marketing activities involving the California energy market, alleged false
statements and omissions in Mirant's prospectus for its initial public
offering and in subsequent public statements by Mirant, and
accounting-related issues previously disclosed by Mirant. For more
information, see Note 11 to the financial statements of
Southern Company in Item 8 herein. The lawsuit purports to include persons
who acquired Mirant securities on the open market or pursuant to an
offering between September 26, 2000, and September 5, 2002. The amended
complaint does not allege any improper trading and marketing activity,
accounting errors, or material misstatements or omissions on the part of
Southern Company but seeks to impose liability on Southern Company based on
allegations that Southern Company was a "control person" as to Mirant. On
February 14, 2003, Southern Company filed a motion seeking to dismiss all
claims against Southern Company. However, the final outcome of this matter
cannot now be determined.
(10) Sierra Club, et al v. Georgia Power
(United States District Court for the Northern District of Georgia)
On December 30, 2002, the Sierra Club, Physicians for Social
Responsibility, Georgia ForestWatch, and one individual filed a civil suit
in U.S. District Court in Georgia against Georgia Power for alleged
violations of the Clean Air Act at Plant Wansley. The complaint alleges
Clean Air Act violations at both the existing coal-fired units and the new
combined cycle units. Specifically, the plaintiffs allege (1) opacity
violations at the coal-fired units, (2) violations of a permit provision
that requires the combined cycle units to operate above certain levels, (3)
violation of nitrogen oxide emission offset requirements, and (4) violation
of hazardous air pollutant requirements. The civil action requests
injunctive and declaratory relief, civil penalties, a supplemental
environmental project, and attorneys' fees. The Clean Air Act authorizes
civil penalties of up to $27,500 per day, per violation at each generating
unit. On January 27, 2003, Georgia Power filed a response to the complaint.
Georgia Power also filed a motion to dismiss the allegations regarding
emission offsets and hazardous air pollutants. While Georgia Power believes
that it has complied with applicable laws and regulations, an adverse
outcome could require payment of substantial penalties. The final outcome
of this matter cannot now be determined.
(11) Right of Way Litigation
In 2002, certain subsidiaries of Southern Company, including Georgia Power,
Gulf Power, Mississippi Power, Savannah Electric, and Southern Telecom
(collectively, defendants), were named as defendants in numerous lawsuits
brought by landowners regarding the installation and use of fiber optic
cable over defendants' rights of way located on the landowners' property.
The plaintiffs' lawsuits claim that defendants may not use or sublease to
third parties some or all of the fiber optic communications lines on the
rights of way that cross the plaintiffs' properties, and that such actions
by defendants exceed the easements or other property rights held by
defendants. The plaintiffs assert claims for, among other things, trespass
and unjust enrichment. The plaintiffs seek compensatory and punitive
damages and injunctive relief. Defendants believe that the plaintiffs'
claims are without merit. An adverse outcome in these matters could result
in substantial judgments; however, the final outcome of these matters
cannot now be determined.
(12) Jerry A. Carter v. Gulf Power
On January 28, 2003, a jury in Escambia County, Florida returned a verdict
of $3 million against Gulf Power arising out of an alleged electrical
injury sustained by the plaintiff in January 1999 while inside his
apartment. If the verdict is not overturned, the plaintiff will also be
I-31
Item 3. LEGAL PROCEEDINGS (Continued)
entitled to recover attorney's fees. Gulf Power intends to seek a new
trial; however, if it is not successful in obtaining a new trial, Gulf
Power intends to pursue an appeal. The ultimate outcome of this matter
cannot now be determined, but is not expected to have a material impact
on Gulf Power's financial statements.
Southern Company and its subsidiaries are subject to certain claims and legal
actions arising in the ordinary course of business. The business activities of
Southern Company and its subsidiaries are also subject to extensive governmental
regulation related to public health and the environment. Litigation over
environmental issues and claims of various types, including property damage,
personal injury and citizen enforcement of environmental requirements, has
increased generally throughout the United States. In particular, personal injury
claims for damages caused by alleged exposure to hazardous materials have become
more frequent.
The ultimate outcome of such litigation currently filed against Southern
Company and its subsidiaries cannot be predicted at this time; however, after
consultation with legal counsel, management does not anticipate that the
liabilities, if any, arising from such proceedings would have a material adverse
effect on the financial statements of Southern Company and its subsidiaries.
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.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
None.
I-32
EXECUTIVE OFFICERS OF
SOUTHERN COMPANY
(Identification of executive officers of Southern Company 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, 2002.
H. Allen Franklin
Chairman, President, Chief Executive Officer and Director
Age 58
Elected Director in 1988 and Chief Executive Officer effective March 1, 2001.
Previously served as President and Chief Operating Officer of Southern Company
from June 1999 to March 2001; and as President and Chief Executive Officer of
Georgia Power from January 1994 to June 1999.
Dwight H. Evans
Executive Vice President
Age 54
Elected in 2001. Previously served as President and Chief Executive Officer of
Mississippi Power from March 1995 to May 2001.
David M. Ratcliffe
Executive Vice President
Age 54
Elected in 1999. He also has served as President and Chief Executive Officer of
Georgia Power since June 1999. Previously served as Executive Vice President,
Treasurer and Chief Financial Officer of Georgia Power from March 1998 to June
1999; and Senior Vice President of Southern Company from March 1995 to March
1998.
Leonard J. Haynes
Executive Vice President and Chief Marketing Officer
Age 52
Elected in 2001. Previously served as Senior Vice President of Georgia Power
from October 1998 to May 2001; and Vice President of Georgia Power from October
1992 to October 1998.
G. Edison Holland, Jr.
Executive Vice President
Age 50
Elected in 2001. Previously served as President and Chief Executive Officer of
Savannah Electric from 1997 until 2001.
Gale E. Klappa
Executive Vice President, Chief Financial Officer and Treasurer
Age 52
Elected in 2001. Previously served as Financial Vice President, Chief Financial
Officer and Treasurer from March 2001 to May 2001; Senior Vice President and
Chief Strategic Officer of Southern Company from October 1999 to March 2001;
President of Mirant's North America Group and Senior Vice President of Mirant
from December 1998 to October 1999; and as President and Chief Executive Officer
of Western Power Distribution, a subsidiary of Mirant located in Bristol,
England, from September 1995 to December 1998.
Charles D. McCrary
Executive Vice President
Age 51
Elected in 1998. He also serves as President and Chief Executive Officer of
Alabama Power since October 2001 and Executive Vice President of Southern
Company since February 2002. Previously served as President and Chief Operating
Officer of Alabama Power from April 2001 to October 2001; Vice President of
Southern Company from February 1998 to April 2001; and as Executive Vice
President of Alabama Power from 1994 through February 1998.
W. Paul Bowers
Executive Vice President of SCS and President and Chief Executive Officer of
Southern Power since May 2001
Age 45
Elected in 2001. Previously served as Senior Vice President of SCS and Chief
Marketing Officer of Southern Company from March 2000 to May 2001; President
and Chief Executive Officer of Western Power Distribution, a subsidiary of
Mirant located in Bristol, England, from December 1998 to 2000; and Senior Vice
President of Retail Marketing for Georgia Power from 1995 to 1998.
W. G. Hairston, III
President and Chief Executive Officer of Southern Nuclear since 1993.
Age 58
The officers of Southern Company were elected for a term running from the
first meeting of the directors following the last annual meeting (May 22, 2002)
for one year until the first board meeting after the next annual meeting or
until their successors are elected and have qualified.
I-33
EXECUTIVE OFFICERS OF
ALABAMA POWER
(Identification of executive officers of Alabama Power 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, 2002.
Charles D. McCrary
President, Chief Executive Officer and Director
Age 51
Elected in 2001. Served as President and Chief Operating Officer of Alabama
Power from April 2001 to October 2001 and Vice President of Southern Company
from February 1998 to April 2001. Previously served as Executive Vice President
of External Affairs at Alabama Power from April 1994 through February 1998.
William B. Hutchins, III
Executive Vice President, Chief Financial Officer
and Treasurer
Age 59
Elected in 1991. Served as Treasurer since 1998 in addition to Executive Vice
President and Chief Financial Officer since 1994.
C. Alan Martin
Executive Vice President
Age 54
Elected in 1999. Served as Executive Vice President of External Affairs from
January 2000 to April 2001. Previously served as Executive Vice President and
Chief Marketing Officer for Southern Company from 1998 to 1999; and Vice
President of Human Resources for Southern Company from May 1995 to March 1998.
Steven R. Spencer
Executive Vice President
Age 47
Elected in 2001. Served as Senior Vice President of External Affairs from July
2000 to April 2001. Previously served as Vice President of Southern Company's
external affairs organization from 1998 to 2001.
Jerry L. Stewart
Senior Vice President
Age 53
Elected in 1999. Served as Senior Vice President of Fossil and Hydro Generation
since 1999. Previously served as Vice President of SCS from 1992 to 1999.
The officers of Alabama Power were elected for a term running from the last
annual meeting of the directors (April 26, 2002) for one year until the next
annual meeting or until their successors are elected and have qualified.
I-34
EXECUTIVE OFFICERS OF
GEORGIA POWER
(Identification of executive officers of Georgia Power 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, 2002.
David M. Ratcliffe
President, Chief Executive Officer and Director
Age 54
Elected as an Executive Officer in 1998 and as Director in 1999. Served as
President and Chief Executive Officer since June 1999. Previously served as
Executive Vice President, Treasurer and Chief Financial Officer of Georgia Power
from 1998 to 1999; and as Senior Vice President of Southern Company from March
1995 to March 1998.
William C. Archer, III
Executive Vice President
Age 54
Elected in 1995. Served as Executive Vice President of External Affairs
since 1995.
Allen L. Leverett
Executive Vice President, Treasurer and
Chief Financial Officer
Age 36
Elected in 2002. Previously served as Vice President and Treasurer of SCS and
Assistant Treasurer of Georgia Power from 2000 to 2002; and as Vice President,
Financial Planning & Analysis from 1997 to 2000.
Judy M. Anderson
Senior Vice President
Age 54
Elected in 2001. Served as Senior Vice President of Charitable Giving since
2001. Previously served as Vice President and Corporate Secretary of Georgia
Power from 1989 to 2001.
Ronnie L. Bates
Senior Vice President
Age 48
Elected in 2001. Served as Senior Vice President, Planning, Sales and Service
since 2001. Previously served as Vice President, Transmission from 2000 to 2001;
and as General Manager, Transmission and Construction from 1995 to 2000.
Mickey A. Brown
Senior Vice President
Age 55
Elected in 2001. Served as Senior Vice President of Distribution since 2001.
Previously served as Vice President, Distribution from 2000 to 2001; and as Vice
President, Northern Region from 1993 to 2000.
James K. Davis
Senior Vice President
Age 62
Elected in 1993. Served as Senior Vice President of Corporate Relations since
1993, with Employee Relations being added to his responsibilities in 2000.
Leslie R. Sibert
Vice President
Age 40
Elected in 2001. Served as Vice President, Transmission since 2001. Previously
served as Decatur Region Manager from 1999 to 2001; and as Assistant to Senior
Vice President, Southern Wholesale Energy from 1996 to 1999.
Christopher C. Womack
Senior Vice President
Age 44
Elected in 2001. Served as Senior Vice President of Fossil and Hydro since 2001.
Previously served as Vice President and Chief People Officer of Southern Company
from 1998 to 2001; and as Senior Vice President of Public Relations and
Corporate Services at Alabama Power from 1995 to 1998.
The officers of Georgia Power were elected for a term running from the last
annual meeting of the directors (May 15, 2002) for one year until the next
annual meeting or until their successors are elected and have qualified, except
for Mr. Leverett, whose election was effective May 25, 2002.
I-35
EXECUTIVE OFFICERS OF GULF POWER
(Identification of executive officers of Gulf Power 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, 2002.
Thomas A. Fanning
President, Chief Executive Officer and Director
Age 45
Elected in 2002. Previously served as Executive Vice President, Treasurer and
Chief Financial Officer of Georgia Power from 1999 to 2002; and as Senior Vice
President of SCS and Chief Information Officer for Southern Company from 1995 to
June 1999.
Francis M. Fisher, Jr.
Vice President
Age 54
Elected in 1989. Served as Vice President of Power Delivery and Customer
Operations since 1996.
John E. Hodges, Jr.
Vice President
Age 59
Elected in 1989. Served as Vice President of Marketing and Employee/External
Affairs since 1996.
Ronnie R. Labrato
Vice President, Chief Financial Officer and Comptroller
Age 49
Elected in 2000. Previously served as Comptroller and Chief Financial Officer
from 2000 to 2001 and Controller from 1992 to 2000.
Warren E. Tate
Vice President, Secretary/Treasurer and
Regional Chief Information Officer
Age 60
Elected in 2000. Served as Vice President since 2001, also serves as
Secretary/Treasurer and Regional Chief Information Officer since 1996.
Gene L. Ussery, Jr.
Vice President
Age 53
Elected in 2002. Served as Vice President of Power Generation since May 2002.
Also serves at Mississippi Power as Vice President of Power Generation and
Delivery from September 2000 to present. Previously served as Northern Cluster
Manager at Georgia Power for Plants Hammond, Bowen and McDonough-Atkinson from
July 2000 to September 2000; and Manager of Plant Bowen at Georgia Power from
1997 to 2000.
The officers of Gulf Power were elected for a term running from the last
annual meeting of the directors (May 17, 2002) for one year until the next
annual meeting or until their successors are elected and have qualified.
I-36
EXECUTIVE OFFICERS OF
MISSISSIPPI POWER
(Identification of executive officers of Mississippi Power 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, 2002.
Michael D. Garrett
President, Chief Executive Officer and Director
Age 53
Elected in 2001. Previously served as Executive Vice President - Customer
Service of Alabama Power from January 2000 to May 2001; Executive Vice President
of External Affairs of Alabama Power from March 1998 to January 2000; and Senior
Vice President of External Affairs of Alabama Power from February 1994 to March
1998.
H. E. Blakeslee
Vice President
Age 62
Elected in 1984. Served as Vice President of Customer Services and Retail
Marketing since 1984.
Don E. Mason
Vice President
Age 61
Elected in 1983. Served as Vice President of External Affairs and Corporate
Services since 1983.
Michael W. Southern
Vice President, Treasurer and
Chief Financial Officer
Age 50
Elected in 1995. Previously served as Vice President, Secretary, Treasurer and
Chief Financial Officer from 1995 to 2001.
Gene L. Ussery, Jr.
Vice President
Age 53
Elected in 2000. Served as Vice President of Power Generation and Delivery since
September 2000 and Vice President of Power Generation at Gulf Power since May
2002. Previously served as Northern Cluster Manager at Georgia Power for Plants
Hammond, Bowen and McDonough-Atkinson from July 2000 to September 2000; and
Manager of Plant Bowen at Georgia Power from 1997 to 2000.
The officers of Mississippi Power were elected for a term running from the
last annual meeting of the directors (April 24, 2002) for one year until the
next annual meeting or until their successors are elected and have qualified.
I-37
PART II
Item 5. MARKET FOR REGISTRANTS' COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
(a) The common stock of Southern Company 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
-------------- --------------
2002
First Quarter $26.78 $24.49
Second Quarter 28.39 25.65
Third Quarter 29.02 23.89
Fourth Quarter 30.85 25.17
2001
First Quarter $21.65 $16.15
Second Quarter 23.88 20.89
Third Quarter 26.00 22.05
Fourth Quarter 25.98 22.30
-------------------------------------------------------
There is no market for the other registrants' common stock, all of
which is owned by Southern Company. On February 28, 2003, the closing
price of Southern Company's common stock was $28.21.
(b) Number of Southern Company's common stockholders of record at
December 31, 2002:
141,784
Each of the other registrants have one common stockholder, Southern
Company.
(c) Dividends on each registrant's common stock are payable at the
discretion of their respective board of directors. The dividends on
common stock declared by Southern Company and the operating companies
to their stockholder(s) for the past two years were as follows:
---------------------------------------------------------
Registrant Quarter 2002 2001
---------------------------------------------------------
(in thousands)
Southern Company First $ 234,272 $ 228,320
Second 236,154 229,611
Third 242,850 231,192
Fourth 244,309 232,935
Alabama Power First 107,750 101,200
Second 107,750 97,600
Third 107,750 97,600
Fourth 107,750 97,500
Georgia Power First 135,725 134,500
Second 135,725 130,900
Third 135,725 130,900
Fourth 135,725 131,000
Gulf Power First 16,375 13,500
Second 16,375 13,300
Third 16,375 13,300
Fourth 16,375 13,175
Mississippi First 15,875 12,800
Power Second 15,875 12,500
Third 15,875 12,500
Fourth 15,875 12,400
Savannah First 5,675 5,500
Electric Second 5,675 5,400
Third 5,675 5,400
Fourth 5,675 5,400
---------------------------------------------------------
Southern Power did not pay a dividend in 2002 or 2001.
The dividend paid per share by Southern Company was 33.5(cent) for each
quarter of 2001 and the first two quarters of 2002 and 34.25(cent) for the two
remaining quarters in 2002. The dividend paid on Southern Company's common stock
for the first quarter of 2003 was 34.25(cent) per share.
II-1
The amount of dividends on their common stock that may be paid by the
subsidiary registrants (except Alabama Power, Georgia Power and Southern Power)
is restricted in accordance with their respective first mortgage bond indenture.
See Notes 7 of Southern Company and Mississippi Power, Note 8 of Gulf Power and
Note 6 of Savannah Electric to the financial statements in Item 8 herein for
additional information regarding these restrictions. The amounts of earnings
retained in the business and the amounts restricted against the payment of cash
dividends on common stock at December 31, 2002 were as follows:
----------------------------------------------------------
Retained Restricted
Earnings Amount
------------------ -------------
(in millions)
Alabama Power $ 1,250 $ -
Georgia Power 1,945 -
Gulf Power 162 127
Mississippi Power 196 118
Savannah Electric 110 68
Southern Power 62 -
Consolidated 4,875 313
----------------------------------------------------------
Item 6. SELECTED FINANCIAL DATA
Southern Company. Reference is made to information under the heading
"Selected Consolidated Financial and Operating Data," contained
herein at pages II-53 and II-54.
Alabama Power. Reference is made to information under the heading
"Selected Financial and Operating Data," contained herein at pages II-93 and
II-94.
Georgia Power. Reference is made to information under the heading "Selected
Financial and Operating Data," contained herein at pages II-134 and II-135.
Gulf Power. Reference is made to information under the heading "Selected
Financial and Operating Data," contained herein at pages II-171 and II-172.
Mississippi Power. Reference is made to information under the heading
"Selected Financial and Operating Data," contained herein at pages II-210 and
II-211.
Savannah Electric. Reference is made to information under the heading
"Selected Financial and Operating Data," contained herein at pages II-246
and II-247.
Southern Power. Reference is made to information under the heading "Selected
Financial and Operating Data," contained herein at page II-275.
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION
Southern Company. 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-9 through II-23.
Alabama Power. 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-58 through II-70.
Georgia Power. 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-98 through II-110.
Gulf Power. 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-139 through II-151.
Mississippi Power. 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-176 through II-188.
Savannah Electric. 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-215 through II-227.
Southern Power. 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-251 through II-259.
II-2
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Reference is made to information in Southern Company's "Management's Discussion
and Analysis - Market Price Risk" in Item 7 herein and to Notes 1 and 8 to
Southern Company's financial statements under the heading "Financial
Instruments" contained herein on pages II-17, II-35 and II-47, respectively.
Reference is also made to "Management's Discussion and Analysis - Exposure to
Market Risks" in Item 7 of Alabama Power, Georgia Power, Gulf Power, Savannah
Electric and Southern Power contained herein at pages II-64, II-104, II-144,
II-220, and II-257, respectively. Reference is also made to "Management's
Discussion and Analysis - Market Price Risk" in Item 7 of Mississippi Power
contained herein at page II-182. Further reference is made to Note 1 to the
financial statements in Item 8 herein for the operating companies and Southern
Power, also Note 7 to the financial statements of Alabama Power and Southern
Power and Note 9 to the financial statements of Georgia Power under the headings
"Financial Instruments."
II-3
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO 2002 FINANCIAL STATEMENTS
Page
The Southern Company and Subsidiary Companies:
Independent Auditors' Report............................................................................................ II-8
Report of Independent Public Accountants................................................................................ II-8
Consolidated Statements of Income for the Years Ended December 31, 2002, 2001 and 2000.................................. II-24
Consolidated Statements of Cash Flows for the Years Ended December 31, 2002, 2001 and 2000.............................. II-25
Consolidated Balance Sheets at December 31, 2002 and 2001............................................................... II-26
Consolidated Statements of Capitalization at December 31, 2002 and 2001................................................. II-28
Consolidated Statements of Common Stockholders' Equity for the Years Ended
December 31, 2002, 2001 and 2000............................................................................... II-30
Consolidated Statements of Comprehensive Income for the Years Ended
December 31, 2002, 2001 and 2000............................................................................... II-30
Notes to Financial Statements........................................................................................... II-31
Alabama Power:
Independent Auditors' Report............................................................................................ II-57
Report of Independent Public Accountants................................................................................ II-57
Statements of Income for the Years Ended December 31, 2002, 2001 and 2000............................................... II-71
Statements of Cash Flows for the Years Ended December 31, 2002, 2001 and 2000........................................... II-72
Balance Sheets at December 31, 2002 and 2001 ........................................................................... II-73
Statements of Capitalization at December 31, 2002 and 2001 ............................................................. II-75
Statements of Common Stockholder's Equity for the Years Ended
December 31, 2002, 2001 and 2000............................................................................... II-77
Statements of Comprehensive Income for the Years Ended
December 31, 2002, 2001 and 2000............................................................................... II-77
Notes to Financial Statements........................................................................................... II-78
Georgia Power:
Independent Auditors' Report............................................................................................ II-97
Report of Independent Public Accountants................................................................................ II-97
Statements of Income for the Years Ended December 31, 2002, 2001 and 2000............................................... II-111
Statements of Cash Flows for the Years Ended December 31, 2002, 2001 and 2000........................................... II-112
Balance Sheets at December 31, 2002 and 2001............................................................................ II-113
Statements of Capitalization at December 31, 2002 and 2001 ............................................................. II-115
Statements of Common Stockholder's Equity for the Years Ended
December 31, 2002, 2001 and 2000............................................................................... II-116
Statements of Comprehensive Income for the Years Ended
December 31, 2002, 2001 and 2000............................................................................... II-116
Notes to Financial Statements........................................................................................... II-117
Gulf Power:
Independent Auditors' Report............................................................................................ II-138
Report of Independent Public Accountants................................................................................ II-138
Statements of Income for the Years Ended December 31, 2002, 2001 and 2000............................................... II-152
Statements of Cash Flows for the Years Ended December 31, 2002, 2001 and 2000........................................... II-153
Balance Sheets at December 31, 2002 and 2001 ........................................................................... II-154
Statements of Capitalization at December 31, 2002 and 2001 ............................................................. II-156
Statements of Common Stockholder's Equity for the Years Ended
December 31, 2002, 2001 and 2000............................................................................... II-157
II-4
Page
Statements of Comprehensive Income for the Years Ended
December 31, 2002, 2001 and 2000............................................................................... II-157
Notes to Financial Statements........................................................................................... II-158
Mississippi Power:
Independent Auditors' Report............................................................................................ II-175
Report of Independent Public Accountants................................................................................ II-175
Statements of Income for the Years Ended December 31, 2002, 2001 and 2000............................................... II-189
Statements of Cash Flows for the Years Ended December 31, 2002, 2001 and 2000........................................... II-190
Balance Sheets at December 31, 2002 and 2001 ........................................................................... II-191
Statements of Capitalization at December 31, 2002 and 2001 ............................................................. II-193
Statements of Common Stockholder's Equity for the Years Ended
December 31, 2002, 2001 and 2000............................................................................... II-195
Statements of Comprehensive Income for the Years Ended
December 31, 2002, 2001 and 2000............................................................................... II-195
Notes to Financial Statements........................................................................................... II-196
Savannah Electric:
Independent Auditors' Report............................................................................................ II-214
Report of Independent Public Accountants................................................................................ II-214
Statements of Income for the Years Ended December 31, 2002, 2001 and 2000............................................... II-228
Statements of Cash Flows for the Years Ended December 31, 2002, 2001 and 2000........................................... II-229
Balance Sheets at December 31, 2002 and 2001 ........................................................................... II-230
Statements of Capitalization at December 31, 2002 and 2001 ............................................................. II-232
Statements of Common Stockholder's Equity for the Years Ended
December 31, 2002, 2001 and 2000............................................................................... II-233
Statements of Comprehensive Income for the Years Ended
December 31, 2002, 2001 and 2000............................................................................... II-233
Notes to Financial Statements........................................................................................... II-234
Southern Power:
Independent Auditors' Report............................................................................................ II-250
Statements of Income for the Year Ended December 31, 2002 and For the Period from
January 8, 2001 (Inception) to December 31, 2001 .............................................................. II-260
Statements of Cash Flows for the Year Ended December 31, 2002 and For the Period from
January 8, 2001 (Inception) to December 31, 2001............................................................... II-261
Balance Sheets at December 31, 2002 and 2001 ........................................................................... II-262
Statements of Common Stockholder's Equity for the Year Ended December 31, 2002 and
For the Period from January 8, 2001 (Inception) to December 31, 2001........................................... II-264
Statements of Comprehensive Income for the Year Ended December 31, 2002
and For the Period from January 8, 2001 (Inception) to December 31, 2001....................................... II-264
Notes to Financial Statements........................................................................................... II-265
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
Previously reported by each registrant, except for Southern Power, in
separate Current Reports on Form 8-K dated March 28, 2002.
II-5
THE SOUTHERN COMPANY
AND SUBSIDIARY COMPANIES
FINANCIAL SECTION
II-6
MANAGEMENT'S REPORT
Southern Company and Subsidiary Companies 2002 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 accounting principles
generally accepted in the United States 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 accounting 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 independent
directors, 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 accounting principles generally accepted in the United States.
/s/H. Allen Franklin
H. Allen Franklin
Chairman, President, and Chief Executive Officer
/s/Gale E. Klappa
Gale E. Klappa
Executive Vice President, Chief Financial Officer,
and Treasurer
February 17, 2003
II-7
INDEPENDENT AUDITORS' REPORT
To the Board of Directors and Stockholders of Southern Company
We have audited the accompanying consolidated balance sheet and consolidated
statement of capitalization of Southern Company and Subsidiary Companies as of
December 31, 2002, and the related consolidated statements of income,
comprehensive income, common stockholders' equity, and cash flows for the year
then ended. These financial statements are the responsibility of Southern
Company's management. Our responsibility is to express an opinion on these
financial statements based on our audit. The consolidated financial statements
of Southern Company and Subsidiary Companies as of December 31, 2001, and for
each of the two years then ended were audited by other auditors who have ceased
operations. Those auditors expressed an unqualified opinion on those
consolidated financial statements and included an explanatory paragraph that
described a change in the method of accounting for derivative instruments and
hedging activities in their report dated February 13, 2002.
We conducted our audit in accordance with auditing standards generally
accepted in the United States of America. 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 audit provides a
reasonable basis for our opinion.
In our opinion, the 2002 consolidated financial statements (pages II-24 to
II-52) present fairly, in all material respects, the financial position of
Southern Company and Subsidiary Companies at December 31, 2002, and the results
of their operations and their cash flows for the year then ended in conformity
with accounting principles generally accepted in the United States of America.
/s/Deloitte & Touche LLP
Atlanta, Georgia
February 17, 2003
THE FOLLOWING REPORT OF INDEPENDENT ACCOUNTANTS IS A COPY OF THE REPORT
PREVIOUSLY ISSUED IN CONNECTION WITH THE COMPANY'S 2001 ANNUAL REPORT
ON FORM 10-K AND HAS NOT BEEN REISSUED BY ARTHUR ANDERSEN LLP. SEE EXHIBIT
23(a)2 FOR ADDITIONAL INFORMATION.
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, 2001 and 2000, 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, 2001. 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-19 through
II-42) referred to above present fairly, in all material respects, the financial
position of Southern Company and subsidiary companies as of December 31, 2001
and 2000, and the results of their operations and their cash flows for each of
the three years in the period ended December 31, 2001, in conformity with
accounting principles generally accepted in the United States.
As explained in Note 1 to the financial statements, effective January 1,
2001, Southern Company changed its method of accounting for derivative
instruments and hedging activities.
/s/Arthur Andersen LLP
Atlanta, Georgia
February 13, 2002
II-8
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Southern Company and Subsidiary Companies 2002 Annual Report
RESULTS OF OPERATIONS
- ---------------------
Overview of Consolidated Earnings and Dividends
Earnings
Southern Company's financial performance in 2002 was very strong and one of the
best in the electric utility industry. This performance reflected our goal to
deliver solid results to stockholders and to provide low-cost energy to more
than 4 million customers. Net income of $1.3 billion increased 17.6 percent over
income from continuing operations reported in 2001. Net income from continuing
operations was $1.1 billion in 2001 and $994 million in 2000. This was a 12.7
percent and 8.6 percent increase in 2001 and 2000, respectively. Basic earnings
per share from continuing operations in 2002 were $1.86 per share, $1.62 in
2001, and $1.52 in 2000. Dilution -- which factors in additional shares related
to stock options -- decreased earnings per share by 1 cent in 2002 and 2001 and
had no impact in 2000.
In April 2000, Southern Company announced an initial public offering of up to
19.9 percent of Mirant Corporation (Mirant) and intentions to spin off its
remaining ownership of 272 million Mirant shares. On April 2, 2001, the tax-free
distribution of Mirant shares was completed. As a result of the spin off,
Southern Company's financial statements and related information reflect Mirant
as discontinued operations. Therefore, the focus of Management's Discussion and
Analysis is on Southern Company's continuing operations. The following chart
shows earnings from continuing and discontinued operations:
Basic Earnings
Per Share
--------------------------
2002 2001 2000
- --------------------------------------------------------------
Earnings from --
Continuing operations $1.86 $1.62 $1.52
Discontinued operations - 0.21 0.49
- --------------------------------------------------------------
Total earnings $1.86 $1.83 $2.01
==============================================================
Dividends
Southern Company has paid dividends on its common stock since 1948. Dividends
paid per share on common stock in 2002 were $1.355 and $1.34 in 2001 and 2000.
The quarterly dividend was increased in September 2002 to 341/4 cents per share
- -- or $1.37 annually -- from 331/2 cents. In January 2003, Southern Company
declared a quarterly dividend of 341/4 cents per share. This is the 221st
consecutive quarter that Southern Company has paid a dividend equal to or higher
than the previous quarter. Our goal for the dividend payout ratio is a range of
70 to 75 percent and the payout ratio was 72.8 percent for 2002.
Southern Company Business Activities
Discussion of the results of continuing operations is focused on Southern
Company's primary business of electricity sales by the operating companies --
Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Savannah
Electric -- and Southern Power. Southern Power is an electric wholesale
generation subsidiary with market-based rates. The remaining portion of Southern
Company's other business activities includes alternative fuels, energy-related
products and services, leveraged leasing activities, and the parent holding
company. A condensed income statement for the other businesses is shown later.
Electricity Businesses
Southern Company's electric utilities generate and sell electricity to retail
and wholesale customers in the Southeast. A condensed income statement for the
six companies that make up the regulated retail and wholesale and competitive
generation business is as follows:
Increase (Decrease)
Amount From Prior Year
-------- -----------------------
2002 2002 2001 2000
- --------------------------------------------------------------
(in millions)
Operating revenues $10,206 $ 300 $ 46 $735
- --------------------------------------------------------------
Fuel 2,786 209 13 236
Purchased power 449 (269) 41 268
Other operation
and maintenance 2,751 262 19 40
Depreciation
and amortization 989 (155) 9 89
Taxes other than
income taxes 555 22 1 11
- --------------------------------------------------------------
Total operating
expenses 7,530 69 83 644
- --------------------------------------------------------------
Operating income 2,676 231 (37) 91
Other income, net (17) (32) 51 2
Interest expenses
and other, net 585 (24) (25) 29
Income taxes 778 76 (1) 28
- --------------------------------------------------------------
Net income $ 1,296 $ 147 $ 40 $ 36
==============================================================
II-9
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2002 Annual Report
Revenues
Details of electric operating revenues are as follows:
2002 2001 2000
- --------------------------------------------------------------
(in millions)
Retail -- prior year $ 8,440 $8,600 $8,090
Change in --
Base rates 33 23 (36)
Sales growth 98 61 115
Weather 158 (177) 95
Fuel cost recovery
and other (1) (67) 336
- --------------------------------------------------------------
Total retail 8,728 8,440 8,600
- --------------------------------------------------------------
Sales for resale --
Within service area 389 338 377
Outside service area 779 836 600
- --------------------------------------------------------------
Total sales for resale 1,168 1,174 977
- --------------------------------------------------------------
Other electric
operating revenues 310 292 283
- --------------------------------------------------------------
Electric operating
revenues $10,206 $9,906 $9,860
==============================================================
Percent change 3.0% 0.5% 8.1%
- ---------------------------------------------------------------
Retail revenues increased $288 million in 2002, declined $160 million in
2001, and rose $510 million in 2000. The significant factors driving these
changes are shown in the table above.
Electric rates -- for the operating companies -- include provisions to adjust
billings for fluctuations in fuel costs, the energy component of purchased power
costs, and certain other costs. Under these 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 of $389 million for 2002
were near the same level as 2000, which reflected closer to normal
weather-adjusted sales. The same sales for resale category in 2001 was $338
million, down 10.2 percent from the prior year. This sharp decline resulted
primarily from the mild weather experienced in the Southeast during 2001, which
significantly reduced energy requirements from these customers. Sales for resale
within the service area for 2000 were up from the prior year as a result of
additional demand for electricity during the hot summer.
Revenues from energy sales for resale outside the service area were down 7.1
percent in 2002 after having increased 39 percent in 2001 and 27 percent in
2000. The decline in 2002 resulted from the expiration of certain short-term
energy sales contracts in effect in 2001. Revenues from outside the service area
have increased $306 million since 1999 as a result of growth driven by new
longer-term contracts. As Southern Company increases its competitive wholesale
generation business, sales for resale outside the service area should reflect
steady increases over the near term. Recent wholesale contracts with
market-based capacity and energy rates have shorter contract periods than the
traditional cost-based contracts entered into in the 1980s. The older contracts
are principally unit power sales to Florida utilities. Capacity revenues reflect
the recovery of fixed costs and a return on investment under the unit power
sales contracts, and energy is generally sold at variable cost. The capacity and
energy components of the unit power contracts and other long-term contracts were
as follows:
2002 2001 2000
- --------------------------------------------------------------
(in millions)
Unit power --
Capacity $175 $170 $177
Energy 198 201 178
Other long term --
Capacity 100 112 42
Energy 306 353 203
- --------------------------------------------------------------
Total $779 $836 $600
==============================================================
Capacity revenues for unit power contracts in 2002, 2001, and 2000 varied
slightly compared with the prior year as a result of adjustments and true-ups
related to contractual pricing. No significant declines in the amount of
capacity are scheduled until the termination of the contracts in 2010. See Note
5 to the financial statements for additional information.
Energy Sales
Changes in revenues are influenced heavily by the volume of energy sold each
year. Kilowatt-hour sales for 2002 and the percent change by year were as
follows:
Amount Percent Change
(billions of ------ ---------------------------
kilowatt-hours) 2002 2002 2001 2000
- --------------------------------------------------------------
Residential 48.8 9.5% (3.6)% 6.5%
Commercial 48.2 2.8 1.5 6.6
Industrial 53.9 1.8 (6.8) 1.0
Other 1.0 2.3 0.7 2.7
-----
Total retail 151.9 4.5 (3.2) 4.3
Sales for resale --
Within service area 10.6 12.9 (2.0) 1.5
Outside service area 21.9 2.7 24.4 33.0
----- -
Total 184.4 4.7 (0.5) 6.4
==============================================================
II-10
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2002 Annual Report
Residential energy sales in 2002 reflected a substantial increase compared
with 2001 as a result of weather and a 1.6 percent increase in new customers.
Commercial sales continued to show steady growth while industrial sales
increased somewhat over the depressed results of recent years. In 2001, retail
energy sales registered a 3.2 percent decline. This was the first decrease since
1982 and was driven by extremely mild weather and the sluggish economy, which
severely impacted industrial sales. In 2000, the rate of growth in total retail
energy sales was very strong. Residential energy sales reflected an increase as
a result of hotter-than-normal summer weather and an increase in customers
served. Also in 2000, commercial sales continued to reflect the strong economy
in the Southeast. Energy sales to retail customers are projected to increase at
an average annual rate of 1.9 percent during the period 2003 through 2013.
Sales to customers outside the service area under more recent long-term
contracts increased kilowatt-hour sales by 1.0 billion, 3.9 billion, and 2.2
billion in 2002, 2001, and 2000, respectively. These sales reflected the
expansion of the competitive wholesale generation business discussed earlier.
Unit power energy sales decreased 3.3 percent in 2002, increased 2.7 percent in
2001, and increased 21 percent in 2000. These changes are influenced by
fluctuations in prices for oil and natural gas. These are the primary fuel
sources for the unit power sales customers. However, these fluctuations in
energy sales under long-term contracts have minimal effect on earnings because
the energy is generally sold at variable cost.
Expenses
Electric operating expenses in 2002 were $7.5 billion, an increase of $69
million over 2001 expenses. Electricity production costs exceeded last year's
cost by $88 million as a result of increased electricity sales. Non-production
electricity operation and maintenance costs also increased in 2002 by $109
million. This increase was driven by additional maintenance projects in 2002 as
compared to 2001. Taxes other than income taxes increased $22 million in 2002.
Depreciation and amortization declined by $155 million in 2002 primarily as a
result of Georgia Power's 2001 rate order to reverse and amortize over three
years $333 million that had been previously expensed related to accelerated
depreciation under a previous rate order. This amortization reduced depreciation
expense in 2002 by $111 million. For more information regarding this rate
action, see Note 3 to the financial statements under "Georgia Power Retail Rate
Orders."
In 2001, electric operating expenses of $7.5 billion increased only $83
million compared with the prior year. The moderate increase reflected flat
energy sales and tighter cost containment measures, which included lower
staffing levels and reductions in certain non-critical expenses. The costs to
produce electricity in 2001 increased $96 million. However, non-production
operation and maintenance expenses declined by $23 million. In 2000, operating
expenses of $7.4 billion increased $644 million compared with the prior year.
The costs to produce electricity in 2000 increased by $498 million to meet
higher energy requirements. Non-production operation and maintenance expenses
increased $46 million in 2000. Depreciation and amortization expenses in 2000
increased $89 million, of which $50 million resulted from additional accelerated
amortization by Georgia Power.
Fuel costs constitute the single largest expense for the six electric
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 service
area -- were as follows:
2002 2001 2000
- --------------------------------------------------------------
Total generation
(billions of kilowatt-hours) 183 174 174
Sources of generation
(percent) --
Coal 69 72 78
Nuclear 16 16 16
Gas 12 9 4
Hydro 3 3 2
Average cost of fuel per net
kilowatt-hour generated
(cents) 1.61 1.56 1.51
- --------------------------------------------------------------
Fuel and purchased power costs to produce electricity were $3.24 billion in
2002, a decrease of $60 million or 1.8 percent below the prior year costs. An
II-11
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2002 Annual Report
additional 8.9 billion kilowatt-hours were generated in 2002, at a slightly
higher average cost; however, this lowered requirements to purchase more
expensive electricity from other utilities.
In 2001, fuel and purchased power costs of $3.3 billion increased $54
million. Continued efforts to control energy costs, combined with additional
efficient gas-fired generating units, helped to hold the increase in fuel
expense to $13 million in 2001. Total fuel and purchased power costs increased
$504 million in 2000 as a result of a 10.6 billion increase in kilowatt-hours
being sold compared with 1999. This increased demand was met by purchasing some
2.5 billion additional kilowatt-hours and using generation with higher unit fuel
cost than in 1999.
Total interest charges and other financing costs in 2002 declined by $24
million as a result of much lower interest rates on short-term debt and
continued refinancing of higher-cost long-term securities. Total interest
charges and other financing costs in 2001 decreased $25 million from amounts
reported in the previous year. The decline reflected substantially lower
short-term interest rates that offset new financing costs. Total interest
charges and other financing costs in 2000 increased $29 million, reflecting some
additional external financing for new generating units.
Other Business Activities
Southern Company's other business activities include the parent company -- which
does not allocate operating expenses to business units -- telecommunications,
energy services, leasing, alternative fuels, and natural gas marketing. These
businesses are classified in general categories and may comprise one or more of
the following subsidiaries. Southern LINC provides digital wireless
communications services to the integrated Southeast utilities and also markets
these services to the public within the Southeast; Southern Telecom provides
fiber optics services; and Southern Company Energy Solutions provides energy
services, including energy efficiency improvements, for large commercial and
industrial customers, municipalities, and government entities. Southern Company
GAS is a retail gas marketer serving Georgia. Southern Company Holdings invests
in alternative fuel projects and leveraged lease projects, which currently
receive tax benefits that contribute significantly to the economic results of
these investments.
A condensed income statement for Southern Company's other business activities
is shown below:
Increase (Decrease)
Amount From Prior Year
------- -----------------------
2002 2002 2001 2000
- --------------------------------------------------------------
(in millions)
Operating revenues $ 343 $ 94 $ 43 $ 14
- --------------------------------------------------------------
Operation and
maintenance 378 106 29 6
Depreciation and
amortization 58 29 (7) (57)
Taxes other than
income taxes 2 - (2) 2
- --------------------------------------------------------------
Total operating
expenses 438 135 20 (49)
- --------------------------------------------------------------
Operating income (95) (41) 23 63
Equity in losses of
unconsolidated
subsidiaries (92) (39) (31) (6)
Leveraged lease
income 58 (1) (2) 30
Other income, net - (10) 5 (3)
Interest expenses 99 (36) (62) 80
Income taxes (250) (106) (29) (39)
- --------------------------------------------------------------
Net income $ 22 $ 51 $ 86 $ 43
==============================================================
Operating revenues reflect Southern LINC's increased revenues of $32 million,
$12 million, and $32 million in 2002, 2001, and 2000, respectively, as a result
of increased wireless subscribers. Southern Company GAS began operations in
August 2002 and recorded revenues of $68 million for the year. Revenues for
2001 also increased $30 million from the operations of a subsidiary formed in
April 2001 that provides services related to alternative fuel products. The
increase in revenues for 2000 was partially offset by a $19 million decrease in
Southern Company Energy Solutions' revenues from the prior year, which included
the impact of several major contracts.
The $106 million increase in operating and maintenance expense in 2002 was
driven primarily by Southern Company GAS' natural gas purchases and other
operating expenses of $60 million, increases in expenses of $19 million at
Southern LINC as a result of their additional subscribers, and a $30 million
increase in expenses related to alternative fuel product services.
The changes in depreciation expense for all three periods were primarily a
result of asset write downs. The 2002 increase reflects a $16 million charge at
Southern Company Energy Solutions related to the impairment of assets under
contracts to certain customers, as well as the impact of property additions at
II-12
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2002 Annual Report
Southern LINC. The 2001 and 2000 decreases relate to investment write offs in
2000 and 1999, as discussed in Note 3 to the financial statements under "Mobile
Energy Services."
The increases in equity in losses of unconsolidated subsidiaries reflect the
results of additional investments in alternative fuel partnerships that produce
operating losses. These partnerships also claim federal income tax credits that
offset these operating losses and make the projects profitable. These credits
totaled $108 million in 2002, $71 million in 2001, and $23 million in 2000.
Interest expense changes from the prior year reflected lower interest rates
and lower amounts of debt outstanding for the parent company in 2002 and 2001.
The increase in 2000 was related to additional borrowings.
Effects of Inflation
The operating companies and Southern Power are subject to rate regulation and
long-term contracts, respectively, that are based on the recovery of historical
costs. In addition, the income tax laws are also based on 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 in the operating companies' approved
electric rates.
Future Earnings Potential
General
The results of continuing 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. A major factor is the
ability of the operating companies to maintain a stable regulatory environment
and to achieve energy sales growth while containing costs. Another major factor
is the profitability of the competitive market-based wholesale generating
business.
Future earnings for the electricity business in the near term will depend, in
part, 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
price elasticity of demand, and the rate of economic growth in the service area.
The operating companies operate as vertically integrated companies providing
electricity to customers within the 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.
Southern Power currently has general authorization from the Federal Energy
Regulatory Commission (FERC) to sell power to nonaffiliates at market-based
prices. Specific FERC approval must be obtained with respect to a market-based
contract with an affiliate. As with any seller that has been authorized to sell
at market-based rates, the FERC retains the authority to modify or withdraw
Southern Power's market-based rate authority if it determines that the
underlying conditions for having such authority are no longer applicable. In
that event, Southern Power would be required to obtain FERC approval of rates
based on cost of service, which may be lower than those in negotiated
market-based rates.
In accordance with Financial Accounting Standards Board (FASB) Statement No.
87, Employers' Accounting for Pensions, Southern Company recorded non-cash
pension income, before tax, of approximately $117 million in 2002. Future
pension income is dependent on several factors including trust earnings and
changes to the plan. Current estimates indicate a reversal of recording pension
income to recording pension expense by as early as 2005. Postretirement benefit
costs for Southern Company were $99 million in 2002 and are expected to continue
to trend upward. A portion of pension income and postretirement benefit costs is
capitalized based on construction-related labor charges. For the operating
companies, pension income and postretirement benefit costs are a component of
the regulated rates and do not have a significant effect on net income. For more
information regarding pension and postretirement benefits, see Note 2 to the
financial statements.
II-13
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2002 Annual Report
Southern Company currently receives tax benefits related to investments in
alternative fuel partnerships and leveraged lease agreements for energy
generation, distribution, and transportation assets that contribute
significantly to the economic results for these projects. Changes in Internal
Revenue Service interpretations of existing regulations or challenges to the
company's positions could result in reduced availability or changes in the
timing of such tax benefits. The net income impact of these investments totaled
$62 million, $52 million, and $28 million in 2002, 2001, and 2000, respectively.
See Note 1 to the financial statements under "Leveraged Leases" and Note 6 for
additional information and related income taxes.
Mississippi Power and Southern Power have capacity sales contracts with
subsidiaries of Dynegy Inc. (Dynegy). Dynegy is currently experiencing liquidity
problems, and its credit rating is now below investment grade. Minimum capacity
revenues under these contracts average approximately $13 million annually
through May 2005 for Southern Power and $21 million annually for Mississippi
Power through May 2011. Dynegy has provided letters of credit expiring in April
2003 totaling $20 million -- approximately 18 months of capacity payments -- to
Southern Power and $26 million -- approximately 15 months of capacity payments
- -- to Mississippi Power. In addition, two one-year letters of credit totaling
$50 million -- approximately 14 months of capacity payments -- were provided in
April 2002 as security for obligations of Dynegy affiliates under the Plant
Franklin Unit 3 purchase power agreement beginning in 2005. These letters of
credit can be drawn in the event of a default under the purchase power agreement
or the failure to renew the letters of credit prior to expiration. In the event
of such a default, and if Mississippi Power and Southern Power are unable to
resell that capacity into the market, future earnings could be affected. See
Note 5 to the financial statements for additional information. The outcome
cannot now be determined.
In November 2002, Mirant announced that it had identified accounting errors
in previously issued financial statements primarily related to its risk
management and marketing operations and that its net income for January 1999
through 2001 was overstated by $51 million. Although the impact on specific
quarters has not yet been determined, Mirant's new independent auditors are
reauditing 2001 and 2000 financial statements. This reaudit is not expected to
be completed until Mirant files its Form 10-K for the year ended December 31,
2002. If the reaudit of Mirant's financial statements results in adjustments
prior to Southern Company's spin off of Mirant, Southern Company's earnings from
discontinued operations for such periods could be affected. The impact of any
such adjustments would not affect Southern Company's 2002 or any future
financial statements. Based on the nature and amount of Mirant's announced
accounting errors, Southern Company's management does not currently anticipate
that a reaudit of its financial statements will be necessary.
Proposed nuclear security legislation is expected to be introduced in the
108th Congress. The Nuclear Regulatory Commission is also considering additional
security measures for licensees that could require immediate implementation. Any
such requirements could have a significant impact on Southern Company's nuclear
power plants and result in increased operation and maintenance expenses as well
as additional capital expenditures. The impact of any new requirements would
depend upon the development and implementation of the regulations.
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."
Industry Restructuring
The electric utility industry in the United States is continuing to evolve as a
result of regulatory and competitive factors. Among the early primary agents of
change was 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 enhanced the incentive for
IPPs to build power plants for a utility's large industrial and commercial
customers where retail access is allowed and to sell energy to other utilities.
Also, electricity sales for resale rates were affected by numerous new energy
suppliers, including power marketers and brokers.
This past year, merchant energy companies and traditional electric utilities
with significant energy marketing and trading activities came under severe
financial pressures. Many of these companies have completely exited or
drastically reduced all energy marketing and trading activities and sold foreign
II-14
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2002 Annual Report
and domestic electric infrastructure assets. Southern Company has not
experienced any material financial impact regarding its limited energy trading
operations and recent generating capacity additions. In general, Southern
Company only constructs new generating capacity after entering into long-term
capacity contracts for the new facilities or to meet requirements of Southern
Company's regulated retail markets, which are both supplemented by limited
energy trading activities.
Although the Energy Act does not provide for retail customer access, it was a
major catalyst for recent restructuring and consolidations that took place
within the utility industry. Numerous federal and state initiatives that promote
wholesale and retail competition are in varying stages. Among other things,
these initiatives allow retail customers in some states to choose their
electricity provider. 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 discussed in
Alabama, Florida, Georgia, and Mississippi, none have been enacted. Enactment
could require numerous issues to be resolved, including significant ones
relating to recovery of any stranded investments, full cost recovery of energy
produced, and other issues related to the energy crisis that occurred in
California. As a result of that crisis, many states, including those in Southern
Company's retail service area, have either discontinued or delayed consideration
of initiatives involving retail deregulation.
Continuing to be a low-cost producer could provide opportunities to increase
market share and profitability in markets that evolve with changing regulation
and competition. Conversely, if Southern Company's electric utilities do not
remain low-cost producers and provide quality service, then energy sales growth
could be limited, and this could significantly erode earnings.
To adapt to a less regulated, more competitive environment, Southern Company
continues to evaluate and consider a wide array of potential business
strategies. These strategies may include business combinations, acquisitions
involving other utility or non-utility businesses or properties, internal
restructuring, disposition of certain assets, or some combination thereof.
Furthermore, Southern Company may engage in new business ventures that arise
from competitive and regulatory changes in the utility industry. Pursuit of any
of the above strategies, or any combination thereof, may significantly affect
the business operations and financial condition of Southern Company.
The Energy Act amended the Public Utility Holding Company Act of 1935 (PUHCA)
to facilitate acquisitions of interests in exempt wholesale generators, which
sell electricity exclusively for resale. Southern Company is working to maintain
and expand its share of wholesale energy sales in the Southeast. In January
2001, Southern Company formed a new subsidiary -- Southern Power Company. This
subsidiary constructs, owns, and manages wholesale generating assets in the
Southeast. Southern Power is the primary growth engine for Southern Company's
competitive wholesale market-based energy business. By the end of 2005, Southern
Power plans to have approximately 6,600 megawatts of available generating
capacity in commercial operation. At December 31, 2002, 2,400 megawatts were in
commercial operation.
FERC Matters
In December 1999, the FERC issued its final rule on Regional Transmission
Organizations (RTOs). The order encouraged utilities owning transmission systems
to form RTOs on a voluntary basis. Southern Company has submitted a series of
status reports informing the FERC of progress toward the development of a
Southeastern RTO. In these status reports, Southern Company explained that it is
developing a for-profit RTO known as SeTrans with a number of non-jurisdictional
cooperative and public power entities. In 2001, Entergy Corporation and Cleco
Power joined the SeTrans development process. In 2002, the sponsors of SeTrans
established a Stakeholder Advisory Committee, which will participate in the
development of the RTO, and held public meetings to discuss the SeTrans
proposal. On October 10, 2002, the FERC granted Southern Company's and other
SeTrans' sponsors petition for a declaratory order regarding the governance
structure and the selection process for the Independent System Administrator
(ISA) of the SeTrans RTO. The FERC also provided guidance on other issues
identified in the petition. The SeTrans sponsors announced the selection of ESB
International, Ltd. (ESBI) to be the preferred ISA candidate. Should
negotiations with this candidate successfully conclude with final agreement
among the parties, the SeTrans sponsors intend to seek any state and federal
regulatory or other approvals necessary for formation of the SeTrans RTO and the
approval of ESBI to serve in the capacity of the SeTrans ISA. The creation of
SeTrans is not expected to have a material impact on Southern Company's
financial statements; however, the outcome of this matter cannot now be
determined.
II-15
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2002 Annual Report
In July 2002, the FERC issued a notice of proposed rulemaking regarding open
access transmission service and standard electricity market design. The
proposal, if adopted, would among other things: (1) require transmission assets
of jurisdictional utilities to be operated by an independent entity; (2)
establish a standard market design; (3) establish a single type of transmission
service that applies to all customers; (4) assert jurisdiction over the
transmission component of bundled retail service; (5) establish a generation
reserve margin; (6) establish bid caps for day ahead and spot energy markets;
and (7) revise the FERC policy on the pricing of transmission expansions.
Comments on certain aspects of the proposal have been submitted by Southern
Company. Any impact of this proposal on Southern Company and its subsidiaries
will depend on the form in which final rules may be ultimately adopted; however,
Southern Company's revenues, expenses, assets, and liabilities could be
adversely affected by changes in the transmission regulatory structure in its
regional power market.
Accounting Policies
Critical Policy
Southern Company's significant accounting policies are described in Note 1 to
the financial statements. The company's only critical accounting policy involves
rate regulation. The operating companies are subject to the provisions of FASB
Statement No. 71, Accounting for the Effects of Certain Types of Regulation. In
the event that a portion of a company's operations is no longer subject to these
provisions, the company would be required to write off related regulatory assets
and liabilities that are not specifically recoverable and determine if any other
assets have been impaired. See Note 1 to the financial statements under
"Regulatory Assets and Liabilities" for additional information.
New Accounting Standards
Derivatives
- -----------
Effective January 2001, Southern Company adopted FASB Statement No. 133,
Accounting for Derivative Instruments and Hedging Activities, as amended. In
October 2002, the Emerging Issues Task Force (EITF) of the FASB announced
accounting changes related to energy trading contracts in Issue No. 02-03. In
October 2002, Southern Company prospectively adopted the EITF's requirements to
reflect the impact of certain energy trading contracts on a net basis. This
change had no material impact on the company's income statement. Another change
also required certain energy trading contracts to be accounted for on an accrual
basis effective January 2003. This change had no impact on Southern Company's
current accounting treatment.
Asset Retirement Obligations
- ----------------------------
Prior to January 2003, Southern Company accrued for the ultimate cost of
retiring most long-lived assets over the life of the related asset through
depreciation expense. FASB Statement No. 143, Accounting for Asset Retirement
Obligations establishes new accounting and reporting standards for legal
obligations associated with the ultimate cost of retiring long-lived assets. The
present value of the ultimate costs for an asset's future retirement must be
recorded in the period in which the liability is incurred. The cost must be
capitalized as part of the related long-lived asset and depreciated over the
asset's useful life. Additionally, Statement No. 143 does not permit
non-regulated companies to continue accruing future retirement costs for
long-lived assets that they do not have a legal obligation to retire. For more
information regarding the impact of adopting this standard effective January 1,
2003, see Note 1 to the financial statements under "Regulatory Assets and
Liabilities" and "Depreciation and Decommissioning."
Guarantees
- ----------
In 2002, the FASB issued Interpretation No. 45, Accounting and Disclosure
Requirements for Guarantees. This interpretation requires disclosure of certain
direct and indirect guarantees as reflected in Note 9 to the financial
statements under "Guarantees." Also, the interpretation requires recognition of
a liability at inception for certain new or modified guarantees issued after
December 31, 2002. The adoption of Interpretation No. 45 in January 2003 did not
have a material impact on the consolidated financial statements.
FINANCIAL CONDITION
- -------------------
Overview
Southern Company's financial condition continues to remain strong. At December
31, 2002, each of the operating companies were within their allowed range of
return on equity after receiving base rate increases during the year. Also,
earnings from the competitive generation business and the other business
activities made a solid contribution.
II-16
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2002 Annual Report
Gross property additions to utility plant from continuing operations were
$2.7 billion in 2002. The majority of funds needed for gross property additions
since 1999 has been provided from operating activities. The Consolidated
Statements of Cash Flows provide additional details.
Off-Balance Sheet Financing Arrangements
At December 31, 2002, Southern Company has one financing arrangement that was
not required to be recorded on the balance sheet. In May 2001, Mississippi Power
began the initial 10-year term of an operating lease agreement signed in 1999
with Escatawpa Funding, Limited Partnership, a special purpose entity, to use a
combined-cycle generating facility located at Mississippi Power's Plant Daniel.
The facility cost approximately $370 million. The lease provides for a residual
value guarantee -- approximately 71 percent of the completion cost -- by
Mississippi Power that is due upon termination of the lease in certain
circumstances.
Recently, the FASB issued Interpretation No. 46, Consolidation of Variable
Interest Entities. If the Escatawpa financing arrangement is not restructured,
this interpretation would require Mississippi Power to consolidate the assets
and liabilities associated with Escatawpa by July 2003 and to record a
cumulative adjustment to income that is not expected to be material. See Note 9
to the financial statements under "Operating Leases" for additional information
regarding this lease.
Credit Rating Risk
Southern Company and its subsidiaries do not have any credit agreements that
would require material changes in payment schedules or terminations as a result
of a credit rating downgrade. There are contracts that could require collateral
- -- but not accelerated payment -- in the event of a credit rating change to
below investment grade. These contracts are primarily for physical electricity
sales, fixed-price physical gas purchases, and agreements covering interest rate
swaps and currency swaps. At December 31, 2002, the maximum potential collateral
requirements under the electricity sale contracts were approximately $422
million. Generally, collateral may be provided for by a Southern Company
guaranty, a letter of credit, or cash. At December 31, 2002, there were no
material collateral requirements for the gas purchase contracts or other
financial instrument agreements.
Market Price Risk
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. Company policy is
that derivatives are to be used primarily for hedging purposes. Derivative
positions are monitored using techniques that include market valuation and
sensitivity analysis.
The weighted average rate on variable long-term debt outstanding at December
31, 2002, was 1.9 percent. If Southern Company sustained a 100 basis point
change in interest rates for all variable rate long-term debt, the change would
affect annualized interest expense by approximately $29 million at December 31,
2002. To further mitigate exposure to interest rates, the company has entered
into interest rate swaps that have been designated as cash flow hedges. The
company is not aware of any facts or circumstances that would significantly
affect such exposures in the near term. For further information, see notes 1 and
8 to the financial statements under "Financial Instruments."
Due to cost-based rate regulations, the operating companies have limited
exposure to market volatility in interest rates, commodity fuel prices, and
prices of electricity. In addition, Southern Power's exposure to market
volatility in commodity fuel prices and prices of electricity is limited because
its long-term sales contracts shift substantially all fuel cost responsibility
to the purchaser. To mitigate residual risks relative to movements in
electricity prices, the operating companies and Southern Power enter into fixed
price contracts for the purchase and sale of electricity through the wholesale
electricity market and, to a lesser extent, into similar contracts for gas
purchases. Southern Company GAS also enters into fixed price contracts for gas
purchases to mitigate its exposure to price volatility. Also, the operating
companies have implemented fuel-hedging programs at the instruction of their
respective public service commissions. Georgia Power's program became effective
in January 2003.
II-17
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2002 Annual Report
The fair value of changes in derivative energy contracts and year-end valuations
were as follows at December 31:
Changes in Fair Value
- --------------------------------------------------------------
2002 2001
- --------------------------------------------------------------
(in millions)
Contracts beginning of year $ 1.3 $ 1.7
Contracts realized or settled (32.2) (1.4)
New contracts at inception - -
Changes in valuation techniques - -
Current period changes 78.2 1.0
- --------------------------------------------------------------
Contracts end of year $ 47.3 $ 1.3
==============================================================
Source of Year-End Valuation Prices
- --------------------------------------------------------------
Maturity
Total ---------------------
Fair Value Year 1 1-3 Years
- --------------------------------------------------------------
(in millions)
Actively quoted $47.3 $53.5 $(6.2)
External sources - - -
Models and other
methods - - -
- -------------------------------------------------------------
Contracts end of year $47.3 $53.5 $(6.2)
=============================================================
Unrealized gains and losses from mark to market adjustments on contracts
related to fuel hedging programs are recorded as regulatory assets and
liabilities. Realized gains and losses from these programs are included in fuel
expense and are recovered through the operating companies' fuel cost recovery
clauses. In addition, unrealized gains and losses on electric and gas contracts
used to hedge anticipated purchases and sales are deferred in other
comprehensive income. Gains and losses on contracts that do not represent hedges
are recognized in the income statement as incurred. At December 31, 2002, the
fair value of derivative energy contracts was reflected in the financial
statements as follows:
Amounts
- --------------------------------------------------------------
(in millions)
Regulatory liabilities, net $37.1
Other comprehensive income 8.7
Net income 1.5
- --------------------------------------------------------------
Total fair value $47.3
==============================================================
A $5 million loss and $9 million gain were recognized in income in 2002 and
2001, respectively. Southern Company is exposed to market price risk in the
event of nonperformance by parties to the derivative energy contracts. Southern
Company's policy is to enter into agreements with counterparties that have
investment grade credit ratings by Moody's and Standard & Poor's or with
counterparties who have posted collateral to cover potential credit exposure.
Therefore, Southern Company does not anticipate market risk exposure from
nonperformance by the counterparties. For additional information, see notes 1
and 8 to the financial statements under "Financial Instruments."
Capital Structure
During 2002, Southern Company issued $2.7 billion of senior notes and $1.3
billion in trust preferred securities. The issuances were used to refund $1.4
billion of long-term debt and $1.2 billion of trust preferred securities and to
finance $575 million of Southern Power's new generating facilities. The
remainder was used to reduce short-term debt and fund Southern Company's ongoing
construction program. Southern Company also issued 16 million new shares through
the company's stock plans and 2 million treasury shares of common stock in 2002.
Proceeds of $451 million were used to reduce short-term debt and for capital
contributions.
At the close of 2002, the market value of Southern Company's common stock was
$28.39 per share, compared with book value of $12.16 per share. The
market-to-book value ratio was 233 percent at the end of 2002, compared with 222
percent at year-end 2001.
Capital Requirements for Construction
The construction program of Southern Company is currently estimated to be $2.1
billion for 2003, $2.3 billion for 2004, and $2.4 billion for 2005. Actual
construction costs may vary from this estimate because of changes in such
factors as: business conditions; environmental regulations; nuclear plant
regulations; FERC rules and transmission 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.
Southern Company has approximately 4,100 megawatts of new generating capacity
scheduled to be placed in service by 2005. The additional new capacity will be
dedicated to the wholesale market and owned by Southern Power. Significant
construction of transmission and distribution facilities and upgrading of
generating plants will also be continuing.
Other Capital Requirements
In addition to the funds needed for the construction program, approximately $2.8
billion will be required by the end of 2005 for 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.
II-18
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2002 Annual Report
As a result of requirements by the Nuclear Regulatory Commission, Alabama
Power and Georgia Power have established external trust funds for nuclear
decommissioning costs. For additional information, see Note 1 to the financial
statements under "Depreciation and Nuclear Decommissioning." As discussed in
Note 2 to the financial statements, Southern Company provides postretirement
benefits to substantially all employees and funds trusts to the extent required
by the subsidiaries' respective regulatory commissions.
The capital requirements, lease obligations, purchase commitments, and trust
requirements -- discussed in the financial statements -- are as follows:
2003 2004 2005
- -------------------------------------------------------------
(in millions)
Senior and other notes $1,639 $ 692 $ 432
Leases --
Capital 11 9 7
Operating 125 114 99
Purchase commitments --
Fuel 2,211 1,735 1,296
Purchased power 116 136 171
Long-term service
agreements 50 45 43
Trusts --
Nuclear decommissioning 29 29 29
Postretirement benefits 15 16 34
- -------------------------------------------------------------
Environmental Matters
New Source Review Enforcement Actions
In November 1999, the Environmental Protection Agency (EPA) brought a civil
action in the U.S. District Court in Georgia against Alabama Power, Georgia
Power, and the system service company. The complaint alleges violations of the
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 operating companies 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 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 U.S. District Court in Georgia granted Alabama Power's motion to dismiss
for lack of jurisdiction in Georgia and granted the system service company's
motion to dismiss on the grounds that it neither owned nor operated the
generating units involved in the proceedings. The court granted the EPA's motion
to add Savannah Electric as a defendant, but it denied the motion to add Gulf
Power and Mississippi Power based on lack of jurisdiction over those companies.
As directed by the court, the EPA refiled its amended complaint limiting claims
to those brought against Georgia Power and Savannah Electric. Also, the EPA
refiled its claims against Alabama Power in the U.S. District Court in Alabama.
It has not refiled against Gulf Power, Mississippi Power, or the system service
company. The Alabama Power, Georgia Power, and Savannah Electric cases have been
stayed since the spring of 2001, pending a ruling by the U.S. Court of Appeals
for the Eleventh Circuit in the appeal of a very similar New Source Review
enforcement action against the Tennessee Valley Authority (TVA). The TVA appeal
involves many of the same legal issues raised by the actions against Alabama
Power, Georgia Power, and Savannah Electric. Because the outcome of the TVA
appeal could have a significant adverse impact on Alabama Power and Georgia
Power, both companies have been parties to that case as well. In February 2003,
the U.S. District Court in Alabama extended the stay of the EPA litigation
proceeding in Alabama until the earlier of May 6, 2003 or a ruling by the U.S.
Court of Appeals for the Eleventh Circuit in the related litigation involving
TVA. On August 21, 2002, the U.S. District Court in Georgia denied the EPA's
motion to reopen the Georgia case. The denial was without prejudice to the EPA
to refile the motion at a later date, which the EPA has not done at this time.
Southern Company believes that its operating companies 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 in any
one of these cases could require substantial capital expenditures that cannot be
determined at this time and could 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-19
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2002 Annual Report
Environmental Statutes and Regulations
Southern Company's operations are subject to extensive regulation by state and
federal environmental agencies under a variety of statutes and regulations
governing environmental media, including air, water, and land resources.
Compliance with these environmental requirements will involve significant costs,
a major portion of which is expected to be recovered through existing ratemaking
provisions. There is no assurance, however, that all such costs will, in fact,
be recovered.
Compliance with the federal Clean Air Act and resulting regulations has been
and will continue to be, a significant focus for the company. The Title IV acid
rain provisions of the Clean Air Act, for example, required significant
reductions in sulfur dioxide and nitrogen oxide emissions. Compliance was
required in two phases -- Phase I, effective in 1995 and Phase II, effective in
2000. Construction expenditures associated with Phase I and Phase II compliance
totaled approximately $400 million.
Some of the expenditures required to comply with the Phase II acid rain
requirements also assisted the company in complying with nitrogen oxide emission
reduction requirements under Title I of the Clean Air Act, which were designed
to address one-hour ozone nonattainment problems in Atlanta, Georgia and
Birmingham, Alabama. The states of Alabama and Georgia have adopted regulations
that will require additional nitrogen oxide emission reductions from plants in
and/or near those nonattainment areas, beginning in May 2003. Seven generating
plants in the Atlanta area and two plants in the Birmingham area will be
affected. Construction expenditures for compliance with these new rules are
currently estimated at approximately $980 million, of which $140 million remains
to be spent.
To help bring the remaining nonattainment areas into compliance with the
one-hour ozone standard, the EPA issued regional nitrogen oxide reduction rules
in 1998. Those rules required 21 states, including Alabama and Georgia, to
reduce and cap nitrogen oxide emissions from power plants and other large
industrial sources. Affected sources, including five of the company's coal-fired
plants in Alabama, must comply with the reduction requirements by May 31, 2004.
However, for Georgia, the EPA must complete a separate rulemaking before the
requirements will apply. The EPA proposed a rule for Georgia in 2002 and expects
to issue a final rule in 2003. The proposed rule requires compliance by May 1,
2005. Additional construction expenditures for compliance with these new rules
are currently estimated at approximately $305 million, of which $295 million
remains to be spent.
In July 1997, the EPA revised the national ambient air quality standards for
ozone and particulate matter. These revisions made the standards significantly
more stringent. In the subsequent litigation of these standards, the U.S.
Supreme Court found the EPA's implementation program for the new ozone standard
unlawful and remanded it to the EPA for further rulemaking. The EPA is expected
to propose implementation rules designed to address the court's concerns in 2003
and issue final implementation rules in 2004. The remaining legal challenges to
the new standards, which were pending before the U.S. Court of Appeals, District
of Columbia Circuit, have been resolved.
The EPA plans to designate areas as attainment or nonattainment with the new
eight-hour ozone standard by April 2004, based on air quality data for 2001
through 2003. Several areas within the Southern Company's service area are
likely to be designated nonattainment under the new ozone standard. State
implementation plans, including new emission control regulations necessary to
bring those areas into attainment, could be required as early as 2007. Those
state plans could require further reductions in nitrogen oxide emissions from
power plants. If so, reductions could be required sometime after 2007. The
impact of any new standards will depend on the development and implementation of
applicable regulations.
The EPA currently plans to designate areas as attainment or nonattainment
with the new fine particulate matter standard by the end of 2004. Those area
designations will be based on air quality data collected during 2001 through
2003. Several areas within the company's service area will likely be designated
nonattainment under the new particulate matter standard. State implementation
plans, including new emission control regulations necessary to bring those areas
into attainment, could be required as early as the end of 2007. Those state
plans will likely require reductions in sulfur dioxide emissions from power
plants. If so, the reductions could be required sometime after 2007. Any
additional emission reductions and costs associated with the new fine
particulate matter standard cannot be determined at this time.
II-20
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2002 Annual Report
The EPA has also announced plans to issue a proposed Regional Transport Rule
for the fine particulate matter standard by the end of 2003 and to finalize the
rule in 2005. This rule would likely require year-round sulfur dioxide and
nitrogen oxide emission reductions from power plants as early as 2010. If
issued, this rule would likely modify other state implementation plan
requirements for attainment of the fine particulate matter standard and the
eight-hour ozone standard. It is not possible at this time to determine the
effect such a rule would have on the company.
Further reductions in sulfur dioxide could also be required under the EPA's
Regional Haze rules. The Regional Haze rules require states to establish Best
Available Retrofit Technology (BART) standards for certain sources that
contribute to regional haze. The company has a number of plants that could be
subject to these rules. The EPA's Regional Haze program calls for states to
submit State Implementation Plans in 2007 and 2008 that contain emission
reduction strategies for achieving progress toward the visibility improvement
goal. In 2002, however, the U.S. Court of Appeals, District of Columbia Circuit,
vacated and remanded the BART provisions of the federal Regional Haze rules to
the EPA for further rulemaking. Because new BART rules have not been developed
and state visibility assessments are only beginning, it is not possible to
determine the effect of these rules on the company at this time.
The EPA's Compliance Assurance Monitoring (CAM) regulations under Title V of
the Clean Air Act require that monitoring be performed to ensure compliance with
emissions limitations on an ongoing basis. The regulations require certain
facilities with Title V operating permits to develop and submit a CAM plan to
the appropriate permitting authority upon applying for renewal of the facility's
Title V operating permit. Four of Southern Company's operating companies --
Georgia Power, Gulf Power, Mississippi Power, and Savannah Electric -- will be
applying for renewal of their Title V operating permits between 2003 and 2005,
and a number of the plants will likely be subject to CAM requirements for at
least one pollutant, in most cases particulate matter. The company is in the
process of developing CAM plans, which could indicate a need for improved
particulate matter controls at affected facilities. Because the plans are still
in the early stages of development, the company cannot determine the extent to
which improved controls could be required or the costs associated with any
necessary improvements. Actual ongoing monitoring costs are expensed as incurred
and are not material for any period presented.
In December 2000, having completed its utility studies for mercury and other
hazardous air pollutants (HAPS), the EPA issued a determination that an emission
control program for mercury and, perhaps, other HAPS is warranted. The program
is being developed under the Maximum Achievable Control Technology provisions of
the Clean Air Act. The EPA currently plans to issue proposed rules regulating
mercury emissions from electric utility boilers by the end of 2003, and those
regulations are scheduled to be finalized by the end of 2004. Compliance could
be required as early as 2007. Because the rules have not yet been proposed, the
costs associated with compliance cannot be determined at this time.
In December 2002, the EPA issued final and proposed revisions to the New
Source Review program under the Clean Air Act. In February 2003, several
northeastern states petitioned the D.C. Circuit Court for a stay of the final
rules. The proposed rules are open to public comment and may be revised before
being finalized by the EPA. If fully implemented, these proposed and final
regulations could affect the applicability of the New Source Review provisions
to activities at the company's facilities. In any event, any final regulations
must be adopted by the states in the company's service area in order to apply to
the company's facilities. The effect of these proposed and final rules cannot be
determined at this time.
Several major bills to amend the Clean Air Act to impose more stringent
emissions limitations have been proposed. Three of these, the Bush
Administration's Clear Skies Act, the Clean Power Act of 2002, and the Clean Air
Planning Act of 2002, proposed to further limit power plant emissions of sulfur
dioxide, nitrogen oxides, and mercury. The latter two bills also proposed to
limit emissions of carbon dioxide. None of these bills were enacted into law in
the last Congress. Similar bills have been, and are anticipated to be,
introduced this year. The Bush Administration's Clear Skies Act was recently
reintroduced, and President Bush has stated that it will be a high priority for
the administration. Other bills already introduced include the Climate
Stewardship Act of 2003, which proposes capping greenhouse gas emissions. The
cost impacts of such legislation would depend upon the specific requirements
enacted.
Domestic efforts to limit greenhouse gas emissions have been spurred by
international discussions surrounding the Framework Convention on Climate Change
and specifically the Kyoto Protocol, which proposes international constraints on
the emissions of greenhouse gases. The Bush Administration does not support U.S.
II-21
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2002 Annual Report
ratification of the Kyoto Protocol or other mandatory carbon dioxide reduction
legislation and has instead announced a new voluntary climate initiative which
seeks an 18 percent reduction by 2012 in the rate of greenhouse gas emissions
relative to the dollar value of the U.S. economy. Southern Company is involved
in a voluntary electric utility industry sector climate change initiative in
partnership with the government. Because this initiative is still under
development, it is not possible to determine the effect on the company at this
time.
Southern Company must comply with other environmental laws and regulations
that cover the handling and disposal of hazardous waste and releases of
hazardous substances. 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 and have recognized in
their respective financial statements the costs to clean up known sites.
Southern Company expensed $4 million, $1 million, and $4 million in 2002, 2001,
and 2000, respectively. The subsidiaries may be liable for a portion or all
required cleanup costs for additional sites that may require environmental
remediation. See Note 3 to the financial statements for information regarding
Georgia Power's potentially responsible party status at sites in Georgia.
Under the Clean Water Act, the EPA is developing new rules aimed at reducing
impingement and entrainment of fish and fish larvae at cooling water intake
structures that will require numerous biological studies and, perhaps, retrofits
to some intake structures at existing power plants. The new rule was proposed in
February 2002 and will be finalized by August 2004. The impact of any new
standards will depend on the development and implementation of applicable
regulations.
Also, under the Clean Water Act, the EPA and state environmental regulatory
agencies are developing total maximum daily loads (TMDLs) for certain impaired
waters. Establishment of maximum loads by the EPA or state agencies may result
in lowering permit limits for various pollutants and a requirement to take
additional measures to control non-point source pollution (e.g., storm water
runoff) at facilities discharging into waters for which TMDLs are established.
Because the effect on Southern Company will depend on the actual TMDLs and
permit limitations established by the implementing agency, it is not possible to
determine the effect on the company at this time.
The EPA and state environmental regulatory agencies are reviewing and
evaluating various other matters including limits on pollutant discharges to
impaired waters, hazardous waste disposal requirements, and other regulatory
matters. The impact of any new standards will depend on the development and
implementation of applicable regulations.
Several major pieces of environmental legislation are periodically 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; the Emergency Planning & Community Right-to-Know Act; and the
Endangered Species Act.
Compliance with possible additional federal or state legislation related to
global climate change, electromagnetic fields, and other environmental and
health concerns could also significantly affect Southern Company. The impact of
any new legislation, or changes to existing legislation, could affect many areas
of Southern Company's operations. The full impact of any such changes cannot,
however, be determined at this time.
Sources of Capital
Southern Company intends to meet its future capital needs through internal cash
flow and externally through the issuance of debt, preferred securities, and
equity. The amount and timing of additional equity capital to be raised in 2003
- -- as well as in subsequent years -- will be contingent on Southern Company's
investment opportunities. The company does not currently anticipate any equity
offerings in 2003. Equity capital can be provided from any combination of the
company's stock plans, private placements, or public offerings.
The operating companies plan to obtain the funds required for construction
and other purposes from sources similar to those used in the past, which were
primarily from internal sources. However, the type and timing of any financings
- -- if needed -- will depend on market conditions and regulatory approval. In
recent years, financings primarily have utilized unsecured debt and trust
preferred securities.
Southern Power will use both external funds and equity capital from Southern
Company to finance its construction program. External funds are expected to be
obtained from the issuance of unsecured senior debt and commercial paper or
through existing credit arrangements from banks.
II-22
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2002 Annual Report
Southern Company's current liabilities exceed current assets because of the
continued use of short-term debt as a funding source to meet cash needs as well
as scheduled maturities of long-term debt. Subsequent to December 31, 2002, the
operating companies have issued $545 million of new securities with the proceeds
being used primarily to retire current maturities and to reduce short-term debt.
An additional $414 million of securities has been issued to retire long-term
debt and for other corporate purposes.
To meet short-term cash needs and contingencies, Southern Company has various
internal and external sources of liquidity. At the beginning of 2003, Southern
Company and its subsidiaries had approximately $273 million of cash and cash
equivalents and $3.9 billion of unused credit arrangements with banks, as shown
in the following table. In addition, Southern Company has substantial cash flow
from operating activities and access to the capital markets to meet liquidity
needs. Cash flows from operating activities were $2.8 billion in 2002 and $2.4
billion in both 2001 and 2000.
Bank credit arrangements are as follows:
Expires
----------------------------
2004
Total Unused 2003 & Beyond
- --------------------------------------------------------------
(in millions)
$4,261 $3,856 $2,981 $875
- --------------------------------------------------------------
Approximately $2.6 billion of the credit facilities expiring in 2003 allow
for the execution of term loans for an additional two-year period.
See Note 8 to the financial statements under "Bank Credit Arrangements" for
additional information.
Cautionary Statement Regarding
Forward-Looking Information
Southern Company's 2002 Annual Report includes forward-looking statements in
addition to historical information. Forward-looking information includes, among
other things, statements concerning the strategic goals for Southern Company's
wholesale business, estimated construction expenditures and Southern Company's
projections for energy sales and its goals for future generating capacity,
dividend payout ratio, equity ratio, earnings per share, and earnings growth. In
some cases, forward-looking statements can be identified by terminology such as
"may," "will," "could," "should," "expects," "plans," "anticipates," "believes,"
"estimates," "projects," "predicts," "potential," or "continue" or the negative
of these terms or other comparable terminology. Southern Company cautions that
there are various important factors that could cause actual results to differ
materially from those indicated in the forward-looking statements; accordingly,
there can be no assurance that such indicated results will be realized. These
factors include the impact of recent and future federal and state regulatory
change, including legislative and regulatory initiatives regarding deregulation
and restructuring of the electric utility industry, and also changes in
environmental and other laws and regulations to which Southern Company and its
subsidiaries are subject, as well as changes in application of existing laws and
regulations; current and future litigation, including the pending EPA civil
actions against certain Southern Company subsidiaries; the effects, extent, and
timing of the entry of additional competition in the markets in which Southern
Company's subsidiaries operate; the impact of fluctuations in commodity prices,
interest rates, and customer demand; state and federal rate regulations;
political, legal, and economic conditions and developments in the United States;
the performance of projects undertaken by the non-traditional business and the
success of efforts to invest in and develop new opportunities; internal
restructuring or other restructuring options that may be pursued; potential
business strategies, including acquisitions or dispositions of assets or
businesses, which cannot be assured to be completed or beneficial to Southern
Company or its subsidiaries; the ability of counterparties of Southern Company
and its subsidiaries to make payments as and when due; the effects of, and
changes in, economic conditions in the areas in which Southern Company's
subsidiaries operate, including the current soft economy; the direct or indirect
effects on Southern Company's business resulting from the terrorist incidents on
September 11, 2001, or any similar such incidents or responses to such
incidents; financial market conditions and the results of financing efforts; the
timing and acceptance of Southern Company's new product and service offerings;
the ability of Southern Company to obtain additional generating capacity at
competitive prices; weather and other natural phenomena; and other factors
discussed elsewhere herein and in other reports (including the Form 10-K) filed
from time to time by Southern Company with the Securities and Exchange
Commission.
II-23
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2002, 2001, and 2000
Southern Company and Subsidiary Companies 2002 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------------
2002 2001 2000
- ----------------------------------------------------------------------------------------------------------------------------------
(in millions)
Operating Revenues:
Retail sales $ 8,728 $ 8,440 $ 8,600
Sales for resale 1,168 1,174 977
Other electric revenues 310 292 283
Other revenues 343 249 206
- -----------------------------------------------------------------------------------------------------------------------------------
Total operating revenues 10,549 10,155 10,066
- -----------------------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Fuel 2,831 2,577 2,564
Purchased power 449 718 677
Other operations 2,123 1,899 1,861
Maintenance 961 862 852
Depreciation and amortization 1,047 1,173 1,171
Taxes other than income taxes 557 535 536
- -----------------------------------------------------------------------------------------------------------------------------------
Total operating expenses 7,968 7,764 7,661
- -----------------------------------------------------------------------------------------------------------------------------------
Operating Income 2,581 2,391 2,405
Other Income and (Expense):
Allowance for equity funds used during construction 22 22 27
Interest income 22 27 29
Equity in losses of unconsolidated subsidiaries (91) (52) (21)
Leveraged lease income 58 59 59
Interest expense, net of amounts capitalized (492) (557) (643)
Distributions on capital and preferred securities of subsidiaries (175) (169) (169)
Preferred dividends of subsidiaries (17) (18) (19)
Other income (expense), net (62) (26) (86)
- -----------------------------------------------------------------------------------------------------------------------------------
Total other income and (expense) (735) (714) (823)
- -----------------------------------------------------------------------------------------------------------------------------------
Earnings From Continuing Operations Before Income Taxes 1,846 1,677 1,582
Income taxes 528 558 588
- -----------------------------------------------------------------------------------------------------------------------------------
Earnings From Continuing Operations Before
Cumulative Effect of Accounting Change 1,318 1,119 994
Cumulative effect of accounting change --
less income taxes of less than $1 - 1 -
- -----------------------------------------------------------------------------------------------------------------------------------
Earnings From Continuing Operations 1,318 1,120 994
Earnings from discontinued operations, net of income taxes
of $93 and $86 for 2001 and 2000, respectively - 142 319
- -----------------------------------------------------------------------------------------------------------------------------------
Consolidated Net Income $ 1,318 $ 1,262 $ 1,313
===================================================================================================================================
Common Stock Data:
Earnings per share from continuing operations -
Basic $1.86 $1.62 $1.52
Diluted 1.85 1.61 1.52
Earnings per share including discontinued operations -
Basic $1.86 $1.83 $2.01
Diluted 1.85 1.82 2.01
- ----------------------------------------------------------------------------------------------------------------------------------
Average number of shares of common stock outstanding - (in millions)
Basic 708 689 653
Diluted 714 694 654
- -----------------------------------------------------------------------------------------------------------------------------------
Cash dividends paid per share of common stock $1.355 $1.34 $1.34
- -----------------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
II-24
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2002, 2001, and 2000
Southern Company and Subsidiary Companies 2002 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------------
2002 2001 2000
- -----------------------------------------------------------------------------------------------------------------------------------
(in millions)
Operating Activities:
Consolidated net income $ 1,318 $ 1,262 $ 1,313
Adjustments to reconcile consolidated net income
to net cash provided from operating activities --
Less earnings from discontinued operations - 142 319
Depreciation and amortization 1,158 1,358 1,337
Deferred income taxes and investment tax credits 172 (22) 97
Equity in losses of unconsolidated subsidiaries 91 52 21
Leveraged lease income (58) (59) (61)
Pension, postretirement, and other employee benefits (78) (101) (114)
Other, net 4 (98) 172
Changes in certain current assets and liabilities --
Receivables, net (119) 327 (363)
Fossil fuel stock 105 (199) 78
Materials and supplies 8 (43) (15)
Other current assets (59) (12) (42)
Accounts payable 118 (51) 180
Taxes accrued (49) 91 40
Other current liabilities 220 21 52
- -----------------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities of continuing operations 2,831 2,384 2,376
- -----------------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (2,717) (2,617) (2,225)
Investment in unconsolidated subsidiaries - (50) (6)
Cost of removal net of salvage (109) (99) (45)
Other (135) 30 (30)
- -----------------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities of continuing operations (2,961) (2,736) (2,306)
- -----------------------------------------------------------------------------------------------------------------------------------
Financing Activities:
Increase (decrease) in notes payable, net (968) 223 (275)
Proceeds --
Long-term senior notes 2,655 1,242 650
Other long-term debt 259 757 93
Capital and preferred securities 1,315 30 -
Common stock 451 395 910
Redemptions --
First mortgage bonds (376) (616) (211)
Long-term senior notes (857) (25) (8)
Other long-term debt (137) (544) (196)
Capital and preferred securities (1,171) - -
Preferred stock (70) - -
Common stock repurchased - - (415)
Payment of common stock dividends (958) (922) (873)
Other (94) (33) (54)
- -----------------------------------------------------------------------------------------------------------------------------------
Net cash provided from (used for)
financing activities of continuing operations 49 507 (379)
- -----------------------------------------------------------------------------------------------------------------------------------
Cash provided from (used for) discontinued operations - - 354
- -----------------------------------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents (81) 155 45
Cash and Cash Equivalents at Beginning of Year 354 199 154
- -----------------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 273 $ 354 $ 199
===================================================================================================================================
The accompanying notes are an integral part of these financial statements.
II-25
CONSOLIDATED BALANCE SHEETS
At December 31, 2002 and 2001
Southern Company and Subsidiary Companies 2002 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------------
Assets 2002 2001
- -----------------------------------------------------------------------------------------------------------------------------------
(in millions)
Current Assets:
Cash and cash equivalents $ 273 $ 354
Receivables --
Customer accounts receivable 711 594
Unbilled revenues 277 237
Under recovered regulatory clause revenues 174 296
Other accounts and notes receivable 370 324
Accumulated provision for uncollectible accounts (26) (24)
Fossil fuel stock, at average cost 299 394
Materials and supplies, at average cost 539 550
Other 350 231
- -----------------------------------------------------------------------------------------------------------------------------------
Total current assets 2,967 2,956
- -----------------------------------------------------------------------------------------------------------------------------------
Property, Plant, and Equipment:
In service 37,486 35,813
Less accumulated depreciation 15,449 15,020
- -----------------------------------------------------------------------------------------------------------------------------------
22,037 20,793
Nuclear fuel, at amortized cost 223 202
Construction work in progress 2,382 2,089
- -----------------------------------------------------------------------------------------------------------------------------------
Total property, plant, and equipment 24,642 23,084
- -----------------------------------------------------------------------------------------------------------------------------------
Other Property and Investments:
Nuclear decommissioning trusts, at fair value 639 682
Leveraged leases 791 655
Other 243 193
- -----------------------------------------------------------------------------------------------------------------------------------
Total other property and investments 1,673 1,530
- -----------------------------------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets:
Deferred charges related to income taxes 898 924
Prepaid pension costs 786 641
Unamortized debt issuance expense 109 103
Unamortized premium on reacquired debt 313 280
Other 411 379
- -----------------------------------------------------------------------------------------------------------------------------------
Total deferred charges and other assets 2,517 2,327
- -----------------------------------------------------------------------------------------------------------------------------------
Total Assets $31,799 $29,897
===================================================================================================================================
The accompanying notes are an integral part of these financial statements.
II-26
CONSOLIDATED BALANCE SHEETS (continued)
At December 31, 2002 and 2001
Southern Company and Subsidiary Companies 2002 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------------
Liabilities and Stockholders' Equity 2002 2001
- -----------------------------------------------------------------------------------------------------------------------------------
(in millions)
Current Liabilities:
Securities due within one year $ 1,639 $ 429
Notes payable 1,007 1,902
Accounts payable 986 823
Customer deposits 169 153
Taxes accrued --
Income taxes 113 160
Other 219 193
Interest accrued 158 118
Vacation pay accrued 130 125
Other 593 473
- -----------------------------------------------------------------------------------------------------------------------------------
Total current liabilities 5,014 4,376
- -----------------------------------------------------------------------------------------------------------------------------------
Long-term debt (See accompanying statements) 8,658 8,297
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 4,214 4,097
Deferred credits related to income taxes 450 500
Accumulated deferred investment tax credits 607 634
Employee benefits provisions 614 533
Deferred capacity revenues 37 42
Other 777 790
- -----------------------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 6,699 6,596
- -----------------------------------------------------------------------------------------------------------------------------------
Company or subsidiary obligated mandatorily redeemable
capital and preferred securities (See accompanying statements) 2,420 2,276
- -----------------------------------------------------------------------------------------------------------------------------------
Cumulative preferred stock of subsidiaries (See accompanying statements) 298 368
- -----------------------------------------------------------------------------------------------------------------------------------
Common stockholders' equity (See accompanying statements) 8,710 7,984
- -----------------------------------------------------------------------------------------------------------------------------------
Total Liabilities and Stockholders' Equity $31,799 $29,897
===================================================================================================================================
Commitments and Contingent Matters (See notes)
- -----------------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
II-27
CONSOLIDATED STATEMENTS OF CAPITALIZATION
At December 31, 2002 and 2001
Southern Company and Subsidiary Companies 2002 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------------
2002 2001 2002 2001
- -----------------------------------------------------------------------------------------------------------------------------------
(in millions) (percent of total)
Long-Term Debt of Subsidiaries:
First mortgage bonds --
Maturity Interest Rates
-------- --------------
2005 6.07% $ - $ 2
2006 6.50% to 6.90% 45 45
2023 through 2026 6.88% to 7.75% 93 467
- -----------------------------------------------------------------------------------------------------------------------------------
Total first mortgage bonds 138 514
- -----------------------------------------------------------------------------------------------------------------------------------
Long-term senior notes and debt --
Maturity Interest Rates
-------- --------------
2002 9.75% - 7
2003 4.69% to 7.85% 841 871
2004 4.88% to 7.13% 575 575
2005 5.49% to 7.25% 380 381
2006 6.20% 150 150
2007 4.88% to 7.13% 902 200
2008 through 2048 4.70% to 8.12% 3,420 2,367
Adjustable rates:
2002 1.98% to 2.13% - 382
2003 1.52% to 1.53% 517 167
2004 1.51% to 2.93% 512 336
2005 2.12% to 2.69% 211 193
2007 2.82% 50 -
- -----------------------------------------------------------------------------------------------------------------------------------
Total long-term senior notes and debt 7,558 5,629
- -----------------------------------------------------------------------------------------------------------------------------------
Other long-term debt --
Pollution control revenue bonds --
Maturity Interest Rates
-------- --------------
Collateralized:
2006 5.25% 12 12
2007 5.80% 1 1
2018 through 2026 5.50% to 6.30% 86 155
Variable rates (at 1/1/03)
2015 through 2017 1.56% to 1.80% 90 90
Non-collateralized:
2012 through 2034 1.75% to 5.45% 789 726
Variable rates (at 1/1/03)
2011 through 2037 1.30% to 2.50% 1,564 1,566
- -----------------------------------------------------------------------------------------------------------------------------------
Total other long-term debt 2,542 2,550
- -----------------------------------------------------------------------------------------------------------------------------------
Capitalized lease obligations 106 92
- -----------------------------------------------------------------------------------------------------------------------------------
Unamortized debt (discount), net (47) (59)
- -----------------------------------------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
requirement -- $499 million) 10,297 8,726
Less amount due within one year 1,639 429
- -----------------------------------------------------------------------------------------------------------------------------------
Long-term debt excluding amount due within one year 8,658 8,297 43.1% 43.9%
- -----------------------------------------------------------------------------------------------------------------------------------
II-28
CONSOLIDATED STATEMENTS OF CAPITALIZATION (continued)
At December 31, 2002 and 2001
Southern Company and Subsidiary Companies 2002 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------------
2002 2001 2002 2001
- ----------------------------------------------------------------------------------------------------------------------------------
(in millions) (percent of total)
Company or Subsidiary Obligated Mandatorily
Redeemable Capital and Preferred Securities:
$25 liquidation value --
4.75% to 5.60% 640 -
6.85% to 7.00% 435 435
7.13% 840 200
7.20% to 8.19% 505 1,591
Auction rate (3.60% at 1/1/02) - 50
- -----------------------------------------------------------------------------------------------------------------------------------
Total company or subsidiary obligated mandatorily
redeemable capital and preferred securities (annual
distribution requirement -- $163 million) 2,420 2,276 12.0 12.0
- -----------------------------------------------------------------------------------------------------------------------------------
Cumulative Preferred Stock of Subsidiaries:
$100 par or stated value --
4.20% to 7.00% 98 98
$25 par or stated value --
5.20% to 5.83% 200 200
Adjustable and auction rates -- at 1/1/02:
3.10% to 3.56% - 70
- -----------------------------------------------------------------------------------------------------------------------------------
Total cumulative preferred stock of subsidiaries
(annual dividend requirement -- $18 million) 298 368 1.5 1.9
- -----------------------------------------------------------------------------------------------------------------------------------
Common Stockholders' Equity:
Common stock, par value $5 per share --
Authorized -- 1 billion shares
Issued -- 2002: 717 million shares
-- 2001: 701 million shares
Treasury -- 2002: 0.1 million shares
-- 2001: 2 million shares
Par value 3,583 3,503
Paid-in capital 338 14
Treasury, at cost (3) (57)
Retained earnings 4,874 4,517
Accumulated other comprehensive income (loss) (82) 7
- -----------------------------------------------------------------------------------------------------------------------------------
Total common stockholders' equity 8,710 7,984 43.4 42.2
- -----------------------------------------------------------------------------------------------------------------------------------
Total Capitalization $20,086 $18,925 100.0% 100.0%
===================================================================================================================================
The accompanying notes are an integral part of these financial statements.
II-29
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY
For the Years Ended December 31, 2002, 2001, and 2000
Southern Company and Subsidiary Companies 2002 Annual Report
Accumulated
Other Comprehensive
Common Stock Income (Loss) From
------------------------ ----------------------------------------
Par Paid-In Retained Continuing Discontinued
Value Capital Treasury Earnings Operations Operations Total
- -----------------------------------------------------------------------------------------------------------------------------------
(in millions)
Balance at December 31, 1999 $3,503 $ 2,480 $(919) $4,232 $ - $ (92) $ 9,204
Net income - - - 1,313 - - 1,313
Other comprehensive income (loss) - - - - - (1) (1)
Stock issued - 121 789 - - - 910
Stock repurchased, at cost - - (414) - - - (414)
Cash dividends - - - (873) - - (873)
Mirant initial public offering - 560 - - - - 560
Other - (8) (1) - - - (9)
- -----------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2000 3,503 3,153 (545) 4,672 - (93) 10,690
Net income - - - 1,262 - - 1,262
Other comprehensive income (loss) - - - - 7 (315) (308)
Stock issued - - 488 (93) - - 395
Mirant spin off distribution - (3,168) - (391) - 408 (3,151)
Cash dividends - - - (922) - - (922)
Other - 29 - (11) - - 18
- -----------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2001 3,503 14 (57) 4,517 7 - 7,984
Net income - - - 1,318 - - 1,318
Other comprehensive income (loss) - - - - (89) - (89)
Stock issued 80 322 55 (6) - - 451
Cash dividends - - - (958) - - (958)
Other - 2 (1) 3 - - 4
- -----------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2002 $3,583 $ 338 $ (3) $4,874 $(82) $ - $ 8,710
===================================================================================================================================
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2002, 2001, and 2000
Southern Company and Subsidiary Companies 2002 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------------
2002 2001 2000
- -----------------------------------------------------------------------------------------------------------------------------------
(in millions)
Consolidated Net Income $1,318 $1,262 $1,313
- -----------------------------------------------------------------------------------------------------------------------------------
Other comprehensive income (loss) -- continuing operations:
Change in additional minimum pension liability, net of tax of $(18) (31) - -
Changes in fair value of qualifying hedges, net of tax of $(44) and $4, respectively (59) 7 -
Less: Reclassification adjustment for amounts included in net income, net of tax 1 - -
- -----------------------------------------------------------------------------------------------------------------------------------
Total other comprehensive income (loss) -- continuing operations (89) 7 -
- -----------------------------------------------------------------------------------------------------------------------------------
Other comprehensive income (loss) -- discontinued operations:
Cumulative effect of accounting change for qualifying hedges, net of tax of $(121) - (249) -
Changes in fair value of qualifying hedges, net of tax of $(51) - (104) -
Less reclassification adjustment for amounts included in net income, net of tax of $29 - 60 -
Foreign currency translation adjustments, net of tax of $(22) and $(1) respectively - (22) (1)
- -----------------------------------------------------------------------------------------------------------------------------------
Total other comprehensive income (loss) -- discontinued operations - (315) (1)
- -----------------------------------------------------------------------------------------------------------------------------------
Consolidated Comprehensive Income $1,229 $ 954 $1,312
===================================================================================================================================
The accompanying notes are an integral part of these financial statements.
II-30
NOTES TO FINANCIAL STATEMENTS
Southern Company and Subsidiary Companies 2002 Annual Report
1. SUMMARRY OF SIGNIFICANT ACCOUNTING
POLICIES
General
Southern Company is the parent company of five operating companies, Southern
Power Company (Southern Power), a system service company, Southern
Communications Services (Southern LINC), Southern Company Gas (Southern
Company GAS), Southern Company Holdings (Southern Holdings), Southern Nuclear
Operating Company (Southern Nuclear), Southern Telecom, and other direct and
indirect subsidiaries. The operating companies -- Alabama Power, Georgia Power,
Gulf Power, Mississippi Power, and Savannah Electric -- provide electric service
in four southeastern states. Southern Power constructs, owns, and manages
Southern Company's competitive generation assets and sells electricity at
market-based rates in the wholesale market. Contracts among the operating
companies and Southern Power -- related to jointly owned generating facilities,
interconnecting transmission lines, or the exchange of electric power -- are
regulated by the Federal Energy Regulatory Commission (FERC) and/or the
Securities and Exchange Commission. The system service company provides, at
cost, specialized services to Southern Company and subsidiary companies.
Southern LINC provides digital wireless communications services to the operating
companies and also markets these services to the public within the Southeast.
Southern Telecom provides fiber cable services within the Southeast. Southern
Company GAS, which began operation in August 2002, is a competitive retail
natural gas marketer serving communities in Georgia. Southern Holdings is an
intermediate holding subsidiary for Southern Company's investments in leveraged
leases, alternative fuel products, and an energy services business. Southern
Nuclear provides services to Southern Company's nuclear power plants.
On April 2, 2001, the spin off of Mirant Corporation (Mirant) was completed.
As a result of the spin off, Southern Company's financial statements and related
information reflect Mirant as discontinued operations. For additional
information, see Note 11.
The financial statements reflect Southern Company's investments in the
subsidiaries on a consolidated basis. All material intercompany items have been
eliminated in consolidation. Certain prior years' data presented in the
consolidated financial statements have been reclassified to conform with the
current year presentation.
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. In addition, the operating
companies and Southern Power are subject to regulation by the FERC, and the
operating companies are also subject to regulation by their respective state
public service commissions. The companies follow accounting principles generally
accepted in the United States and comply with the accounting policies and
practices prescribed by their respective commissions. The preparation of
financial statements in conformity with accounting principles generally accepted
in the United States requires the use of estimates, and the actual results may
differ from those estimates.
Regulatory Assets and Liabilities
The operating companies are subject to the provisions of Financial Accounting
Standards Board (FASB) Statement No. 71, Accounting for the Effects of Certain
Types of Regulation. Regulatory assets represent probable future revenues
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:
2002 2001
- --------------------------------------------------------------
(in millions)
Deferred income tax charges $ 898 $ 924
Premium on reacquired debt 313 280
Department of Energy assessments 33 39
Vacation pay 99 95
Postretirement benefits 25 28
Deferred income tax credits (450) (500)
Accelerated cost recovery (229) (344)
Storm damage reserves (38) (34)
Fuel-hedging assets - 9
Fuel-hedging liabilities (38) (2)
Other assets 188 164
Other liabilities (91) (13)
- --------------------------------------------------------------
Total $ 710 $ 646
==============================================================
See "Depreciation and Nuclear Decommissioning" in this note for information
regarding significant regulatory assets and liabilities created as a result of
the January 1, 2003, adoption of FASB Statement No. 143, Accounting for Asset
Retirement Obligations.
In the event that a portion of an operating company's operations is no longer
subject to the provisions of FASB Statement No. 71, the company would be
II-31
NOTES (continued)
Southern Company and Subsidiary Companies 2002 Annual Report
required to write off related regulatory assets and liabilities that are not
specifically recoverable through regulated rates. In addition, the operating
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.
All regulatory assets and liabilities are reflected in rates.
Revenues and Fuel Costs
Energy revenues are recognized as services are rendered. Capacity revenues are
generally recognized on a levelized basis over the appropriate contract periods.
Other revenues are recognized as services are provided. Unbilled revenues are
accrued at the end of each fiscal period. Fuel costs are expensed as the fuel is
used. Electric rates for the operating companies include provisions to adjust
billings for fluctuations in fuel costs, fuel hedging, 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 $134
million in 2002, $133 million in 2001, and $136 million in 2000. 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 nuclear fuel in January 1998 as required by the
contracts, and the companies are pursuing legal remedies against the government
for breach of contract. Sufficient pool storage capacity for spent fuel is
available at Plant Farley to maintain full-core discharge capability until the
refueling outages scheduled for 2006 and 2008 for units 1 and 2, respectively.
Sufficient pool storage capacity for spent fuel is available at Plant Vogtle to
maintain full-core discharge capability for both units into 2014. At Plant
Hatch, an on-site dry storage facility became operational in 2000. Sufficient
dry storage capacity is believed to be available to continue dry storage
operations at Plant Hatch through the life of the plant. Procurement of on-site
dry storage capacity at Plant Farley is in progress, with the intent to place
the capacity in operation in 2005. Procurement of on-site dry storage capacity
at Plant Vogtle will begin in sufficient time to maintain pool full-core
discharge capability.
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, 2002, under this law to be approximately $17 million and $13
million. These obligations are recorded in other deferred credits 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 3.2 percent in 2002 and
3.4 percent a year in 2001 and 2000. When property subject to depreciation is
retired or otherwise disposed of in the normal course of business, its original
cost -- together with the cost of removal, less salvage -- is charged to
accumulated depreciation. Minor items of property included in the original cost
of the plant are retired when the related property unit is retired. Depreciation
expense includes an amount for the expected costs of decommissioning nuclear
facilities and removal of other facilities. In accordance with regulatory
requirements, prior to January 2003, Southern Company followed the industry
practice of accruing for the ultimate cost of retiring most long-lived assets
over the life of the related asset as part of the annual depreciation expense
provision.
In January 2003, Southern Company adopted FASB Statement No. 143, Accounting
for Asset Retirement Obligations. Statement No. 143 establishes new accounting
and reporting standards for legal obligations associated with the ultimate cost
of retiring long-lived assets. The present value of the ultimate costs for an
asset's future retirement must be recorded in the period in which the liability
is incurred. The cost must be capitalized as part of the related long-lived
asset and depreciated over the asset's useful life.
The cumulative effect adjustment to net income resulting from the adoption of
Statement No. 143 was immaterial. The operating companies expect to receive
II-32
NOTES (continued)
Southern Company and Subsidiary Companies 2002 Annual Report
accounting orders from their respective public service commissions to defer the
transition adjustment; therefore, Southern Company recorded a related regulatory
liability of $47 million to reflect the operating companies' regulatory
treatment of these costs under Statement No. 71. The initial Statement No. 143
liability Southern Company recognized was $778 million, of which $644 million
was removed from the accumulated depreciation reserve. The amount capitalized to
property, plant, and equipment was $181 million.
The liability recognized to retire long-lived assets primarily relates to the
company's nuclear facilities, which include Alabama Power's Plant Farley and
Georgia Power's ownership interests in plants Hatch and Vogtle. In addition, the
operating companies have retirement obligations related to various landfill
sites, ash ponds, and underground storage tanks. Southern Company has also
identified retirement obligations related to certain transmission and
distribution facilities. However, a liability for the removal of these
transmission and distribution assets will not be recorded because no reasonable
estimate can be made regarding the timing of any related retirements. The
operating companies will continue to recognize in the income statement their
ultimate removal costs in accordance with each company's respective regulatory
treatment. Any difference between costs recognized under Statement No. 143 and
those reflected in rates will be recognized as either a regulatory asset or
liability. It is estimated that this annual difference will be approximately $27
million. Management believes actual asset removal costs will be recoverable in
rates over time.
Statement No. 143 does not permit non-regulated companies to continue
accruing future retirement costs for long-lived assets that they do not have a
legal obligation to retire. However, in accordance with the regulatory treatment
of these costs, the operating companies will continue to recognize the removal
costs for these other obligations in their depreciation rates. As of January 1,
2003, the amount included in the accumulated depreciation reserve that
represents a regulatory liability for these costs was $1.23 billion.
Georgia Power recorded accelerated depreciation and amortization amounting to
$91 million in 2001 and $135 million in 2000. Effective January 2002, Georgia
Power discontinued recording accelerated depreciation and amortization in
accordance with a new retail rate order. Also, Georgia Power was ordered to
amortize $333 million -- the cumulative balance previously expensed -- equally
over three years as a credit to depreciation and amortization expense beginning
January 2002. See Note 3 under "Georgia Power Retail Rate Orders" for additional
information.
The Nuclear Regulatory Commission (NRC) requires all licensees operating
commercial nuclear power reactors to establish a plan for providing, with
reasonable assurance, funds for decommissioning. Alabama Power and Georgia Power
have external trust funds to comply with the NRC's regulations. Amounts
previously recorded in internal reserves are being transferred into the external
trust funds over periods approved by the respective state public service
commissions. The NRC's minimum external funding requirements are based on a
generic estimate of the cost to decommission the radioactive portions of a
nuclear unit based on the size and type of reactor. Alabama Power and Georgia
Power have filed plans with the NRC to ensure that -- over time -- the deposits
and earnings of the external trust funds will provide the minimum funding
amounts prescribed by the NRC.
Site study cost is the estimate to decommission a specific facility as of the
site study year, and ultimate cost is the estimate to decommission a specific
facility as of its retirement date. The estimated costs of decommissioning --
both site study costs and ultimate costs -- based on the most current study as
of December 31, 2002 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 year 1998 2000 2000
Decommissioning periods:
Beginning year 2017 2014 2027
Completion year 2031 2042 2045
- --------------------------------------------------------------
(in millions)
Site study costs:
Radiated structures $629 $486 $420
Non-radiated structures 60 37 48
- --------------------------------------------------------------
Total $689 $523 $468
==============================================================
(in millions)
Ultimate costs:
Radiated structures $1,868 $1,004 $1,468
Non-radiated structures 178 79 166
- --------------------------------------------------------------
Total $2,046 $1,083 $1,634
==============================================================
Significant assumptions:
Inflation rate 4.5% 4.7% 4.7%
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
II-33
NOTES (continued)
Southern Company and Subsidiary Companies 2002 Annual Report
from the above estimates because of changes in the assumed date of
decommissioning, changes in NRC requirements, or changes in the assumptions used
in making these estimates.
Annual provisions for nuclear decommissioning are based on an annuity method
as approved by the respective state public service commissions. The amount
expensed in 2002 and fund balances were as follows:
Plant Plant Plant
Farley Hatch Vogtle
- --------------------------------------------------------------
(in millions)
Amount expensed in 2002 $ 18 $ 7 $ 2
Accumulated provisions:
External trust funds,
at fair value $292 $219 $128
Internal reserves 34 7 4
- --------------------------------------------------------------
Total $326 $226 $132
==============================================================
Alabama Power's decommissioning costs for ratemaking are based on the site
study. Effective January 1, 2002, the Georgia Public Service Commission (GPSC)
decreased Georgia Power's annual provision for decommissioning expenses to $9
million. This amount is based on the NRC generic estimate to decommission the
radioactive portion of the facilities as of 2000. The estimates are $383 million
and $282 million for plants Hatch and Vogtle, respectively. The ultimate costs
associated with the 2000 NRC minimum funding requirements are $823 million and
$1.03 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.
In January 2002, Georgia Power received NRC approval for a 20-year extension
of the license at Plant Hatch, which would permit the operation of units 1 and 2
until 2034 and 2038, respectively. Decommissioning costs will not reflect the
license extension until a new site study is complete in 2003 and the GPSC issues
a new rate order, which is not expected until December 2004. Alabama Power has
notified the NRC that it plans to submit an application in September 2003 to
extend the operating license for Plant Farley for an additional 20 years.
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.
Allowance for Funds Used During Construction
(AFUDC) and Interest Capitalized
In accordance with regulatory treatment, the operating companies record AFUDC.
AFUDC represents the estimated debt and equity costs of capital funds that are
necessary to finance the construction of new regulated 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. Interest related to the construction of new facilities not
included in the operating companies' retail rates is capitalized in accordance
with standard interest capitalization requirements.
Cash payments for interest totaled $544 million, $624 million, and $802
million in 2002, 2001, and 2000, respectively, net of amounts capitalized of $59
million, $57 million, and $44 million, respectively.
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 interest capitalized
and/or cost of funds used during construction.
The cost of replacements of property -- exclusive of minor items of property
- -- is capitalized. The cost of maintenance, repairs, and replacement of minor
items of property is charged to maintenance expense as incurred or performed
with the exception of nuclear refueling costs, which are recorded in accordance
with specific public service commission orders. Alabama Power accrues estimated
refueling costs in advance of the unit's next refueling outage. Georgia Power
defers and amortizes refueling costs over the unit's operating cycle before the
next refueling. The refueling cycles for Alabama Power and Georgia Power range
from 18 to 24 months for each unit. In accordance with recent retail accounting
orders, both Georgia Power and Savannah Electric will defer the costs of certain
significant inspection costs for the combustion turbines at Plant McIntosh and
amortize such costs over 10 years, which approximates the expected maintenance
cycle.
II-34
NOTES (continued)
Southern Company and Subsidiary Companies 2002 Annual Report
Leveraged Leases
Southern Company has several leveraged lease agreements -- ranging up to 45
years -- that relate to international and domestic energy generation,
distribution, and transportation assets. Southern Company receives federal
income tax deductions for depreciation and amortization and for interest on
long-term debt related to these investments.
Southern Company's net investment in leveraged leases consists of the
following at December 31:
2002 2001
- --------------------------------------------------------------
(in millions)
Net rentals receivable $1,507 $1,430
Unearned income (716) (775)
- --------------------------------------------------------------
Investment in leveraged leases 791 655
Deferred taxes arising
from leveraged leases (260) (193)
- --------------------------------------------------------------
Net investment in leveraged leases $ 531 $ 462
==============================================================
A summary of the components of income from leveraged leases
is as follows:
2002 2001 2000
- --------------------------------------------------------------
(in millions)
Pretax leveraged lease income $58 $59 $61
Income tax expense 21 21 21
- ---------------------------------------------------------------
Net leveraged lease income $37 $38 $40
===============================================================
Impairment of Long-Lived Assets and Intangibles
Southern Company evaluates long-lived assets for impairment 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 either a specific regulatory disallowance or an estimate of undiscounted
future cash flows attributable to the assets, as compared with 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
the 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 average 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.
Stock Options
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 because the exercise price of all options granted
equaled the fair-market value on the date of grant.
Comprehensive Income
Comprehensive income -- consisting of net income and changes in the fair value
of qualifying cash flow hedges and changes in additional minimum pension
liability, less income taxes and reclassifications for amounts included in net
income -- is presented in the consolidated financial statements. Comprehensive
income from discontinued operations also includes foreign currency translation
adjustments, net of income taxes. The objective of comprehensive income is to
report a measure of all changes in common stock equity of an enterprise that
result from transactions and other economic events of the period other than
transactions with owners.
Financial Instruments
Southern Company uses derivative financial instruments to limit exposure to
fluctuations in interest rates, foreign currency exchange rates, the prices of
certain fuel purchases, and electricity purchases and sales. All derivative
financial instruments are recognized as either assets or liabilities and are
measured at fair value. Substantially all of Southern Company's bulk energy
purchases and sales contracts are derivatives. However, in many cases, these
II-35
NOTES (continued)
Southern Company and Subsidiary Companies 2002 Annual Report
contracts qualify as normal purchases and sales and are accounted for under the
accrual method. Other contracts qualify as cash flow hedges of anticipated
transactions. This results in the deferral of related gains and losses in other
comprehensive income or regulatory assets or liabilities as appropriate until
the hedged transactions occur. Any ineffectiveness is recognized currently in
net income. Contracts that do not qualify for the normal purchase and sale
exception and that do not meet the hedge requirements are marked to market
through current period income and are recorded on a net basis in the
Consolidated Statements of Income.
Southern 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.
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, 2002 $10,191 $10,475
At December 31, 2001 8,634 8,693
Capital and preferred securities:
At December 31, 2002 2,420 2,498
At December 31, 2001 2,276 2,282
- --------------------------------------------------------------
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.
2. RETIREMENT BENEFITS
Southern Company has a defined benefit, trusteed, pension plan that covers
substantially all employees. Southern Company also provides certain
non-qualified benefit plans for a selected group of management and highly
compensated employees. Also, Southern Company provides certain medical care and
life insurance benefits for retired employees. The operating companies fund
trusts to the extent required by their respective regulatory commissions. In
late 2000, as well as in 2002, Southern Company adopted several pension and
postretirement benefit plan changes that had the effect of increasing benefits
to both current and future retirees.
Plan assets consist primarily of domestic and international equities, global
fixed income securities, real estate, and private equity investments. 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
-------------------
2002 2001
- --------------------------------------------------------------
(in millions)
Balance at beginning of year $3,760 $3,397
Service cost 109 104
Interest cost 277 260
Benefits paid (184) (176)
Plan amendments 88 173
Actuarial (gain) loss 44 2
- --------------------------------------------------------------
Balance at end of year $4,094 $3,760
==============================================================
Plan Assets
-----------------
2002 2001
- --------------------------------------------------------------
(in millions)
Balance at beginning of year $5,109 $6,157
Actual return on plan assets (343) (889)
Benefits paid (166) (159)
- --------------------------------------------------------------
Balance at end of year $4,600 $5,109
==============================================================
The accrued pension costs recognized in the Consolidated
Balance Sheets were as follows:
2002 2001
- --------------------------------------------------------------
(in millions)
Funded status $ 506 $ 1,349
Unrecognized transition obligation (39) (51)
Unrecognized prior service cost 334 269
Unrecognized net gain (loss) (115) (1,020)
- --------------------------------------------------------------
Prepaid asset, net 686 547
Portion included in
benefit obligations 100 94
- --------------------------------------------------------------
Total prepaid assets recognized in
the Consolidated Balance Sheets $ 786 $ 641
==============================================================
In 2002 and 2001, amounts recognized in the Consolidated Balance Sheets for
accumulated other comprehensive income and intangible assets were $49 million
and $35 million and $0 million and $33 million, respectively.
II-36
NOTES (continued)
Southern Company and Subsidiary Companies 2002 Annual Report
Components of the pension plan's net periodic cost were as follows:
2002 2001 2000
- -------------------------------------------------------------
(in millions)
Service cost $ 109 $ 104 $ 96
Interest cost 277 260 239
Expected return on
plan assets (449) (423) (384)
Recognized net gain (65) (73) (62)
Net amortization 11 8 -
- -------------------------------------------------------------
Net pension cost (income) $(117) $ (124) $(111)
=============================================================
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
-------------------
2002 2001
- --------------------------------------------------------------
(in millions)
Balance at beginning of year $1,239 $1,052
Service cost 21 22
Interest cost 91 88
Benefits paid (62) (54)
Plan amendments - 186
Actuarial (gain) loss 172 (55)
- --------------------------------------------------------------
Balance at end of year $1,461 $1,239
==============================================================
Plan Assets
------------------
2002 2001
- --------------------------------------------------------------
(in millions)
Balance at beginning of year $425 $459
Actual return on plan assets (34) (59)
Employer contributions 88 79
Benefits paid (62) (54)
- --------------------------------------------------------------
Balance at end of year $417 $425
==============================================================
The accrued postretirement costs recognized in the Consolidated
Balance Sheets were as follows:
2002 2001
- --------------------------------------------------------------
(in millions)
Funded status $(1,043) $(814)
Unrecognized transition obligation 159 174
Unrecognized prior service cost 225 239
Unrecognized net loss (gain) 239 (9)
Fourth quarter contributions 51 41
- --------------------------------------------------------------
Accrued liability recognized in the
Consolidated Balance Sheets $ (369) $(369)
==============================================================
Components of the postretirement plan's net periodic cost were
as follows:
2002 2001 2000
- -------------------------------------------------------------
(in millions)
Service cost $ 21 $ 22 $ 18
Interest cost 91 88 76
Expected return on
plan assets (42) (40) (34)
Net amortization 29 26 18
- -------------------------------------------------------------
Net postretirement cost $ 99 $ 96 $ 78
=============================================================
The weighted average rates assumed in the actuarial calculations
for both the pension plan and postretirement benefits plan were:
2002 2001 2000
- --------------------------------------------------------------
Discount 6.5% 7.5% 7.5%
Annual salary increase 4.0 5.0 5.0
Long-term return
on plan assets 8.5 8.5 8.5
- --------------------------------------------------------------
An additional assumption used in measuring the accumulated postretirement
benefit obligation was a weighted average medical care cost trend rate of 8.75
percent for 2002, decreasing gradually to 5.25 percent through the year 2010 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,
2002, as follows:
1 Percent 1 Percent
Increase Decrease
- --------------------------------------------------------------
(in millions)
Benefit obligation $122 $108
Service and interest costs 10 8
- --------------------------------------------------------------
Employee Savings Plan
Southern Company also sponsors a 401(k) defined contribution plan covering
substantially all employees. The company provides a 75 percent matching
contribution up to 6 percent of an employee's base salary. Total matching
contributions made to the plan for the years 2002, 2001, and 2000 were $53
million, $51 million, and $49 million, respectively.
II-37
NOTES (continued)
Southern Company and Subsidiary Companies 2002 Annual Report
3. CONTINGENCIES AND REGULATORY
MATTERS
General Litigation Matters
Southern Company is subject to certain claims and legal actions arising in the
ordinary course of business. Southern Company's business activities are also
subject to extensive governmental regulation related to public health and the
environment. Litigation over environmental issues and claims of various types,
including property damage, personal injury, and citizen enforcement of
environmental requirements, has increased generally throughout the United
States. In particular, personal injury claims for damages caused by alleged
exposure to hazardous materials have become more frequent.
The ultimate outcome of such litigation currently filed against Southern
Company and its subsidiaries cannot be predicted at this time; however, after
consultation with legal counsel, management does not anticipate that the
liabilities, if any, arising from such proceedings would have a material adverse
effect on Southern Company's financial statements.
Georgia Power Potentially Responsible Party Status
Georgia Power has been designated as a potentially responsible party at sites
governed by the Georgia Hazardous Site Response Act and/or by the federal
Comprehensive Environmental Response, Compensation and Liability Act. Georgia
Power has recognized $34 million in cumulative expenses through December 31,
2002, for the assessment and anticipated cleanup of sites on the Georgia
Hazardous Sites Inventory. In addition, in 1995 the EPA designated Georgia Power
and four other unrelated entities as potentially responsible parties at a site
in Brunswick, Georgia, that is listed on the federal National Priorities List.
Georgia Power has contributed to the removal and remedial investigation and
feasibility study costs for the site. Additional claims for recovery of natural
resource damages at the site are anticipated. As of December 31, 2002, Georgia
Power had recorded approximately $6 million in cumulative expenses associated
with Georgia Power's agreed-upon share of the removal and remedial investigation
and feasibility study costs for the Brunswick site.
The final outcome of each of these matters cannot now be determined. However,
based on the currently known conditions at these sites and the nature and extent
of Georgia Power's activities relating to these sites, management does not
believe that the company's additional liability, if any, at these sites would be
material to the financial statements.
New Source Review Enforcement Actions
In November 1999, the EPA brought a civil action in U.S. District Court in
Georgia against Alabama Power, Georgia Power, and the system service company.
The complaint alleges violations of the 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 operating companies 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 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 U.S. District Court in Georgia granted Alabama Power's motion to
dismiss for lack of jurisdiction in Georgia and granted the system service
company's motion to dismiss on the grounds that it neither owned nor operated
the generating units involved in the proceedings. The court granted the EPA's
motion to add Savannah Electric as a defendant, but it denied the motion to add
Gulf Power and Mississippi Power based on lack of jurisdiction over those
companies. As directed by the court, the EPA refiled its amended complaint
limiting claims to those brought against Georgia Power and Savannah Electric.
Also, the EPA refiled its claims against Alabama Power in the U.S. District
Court in Alabama. It has not refiled against Gulf Power, Mississippi Power, or
the system service company.
The Alabama Power, Georgia Power, and Savannah Electric cases have been
stayed since the spring of 2001, pending a ruling by the U.S. Court of Appeals
for the Eleventh Circuit in the appeal of a very similar New Source Review
enforcement action against the Tennessee Valley Authority (TVA). The TVA appeal
involves many of the same legal issues raised by the actions against Alabama
II-38
NOTES (continued)
Southern Company and Subsidiary Companies 2002 Annual Report
Power, Georgia Power, and Savannah Electric. Because the outcome of the TVA
appeal could have a significant adverse impact on Alabama Power and Georgia
Power, both companies have been parties to that case as well. In February 2003,
the U.S. District Court in Alabama extended the stay of the EPA litigation
proceeding in Alabama until the earlier of May 6, 2003, or a ruling by the U.S.
Court of Appeals for the Eleventh Circuit in the related litigation involving
TVA. On August 21, 2002, the U.S. District Court in Georgia denied the EPA's
motion to reopen the Georgia case. The denial was without prejudice to the EPA
to refile the motion at a later date, which the EPA has not done at this time.
Southern Company believes that its operating companies 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 in any one of these
cases could require substantial capital expenditures that cannot be determined
at this time and could 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.
Plant Wansley Environmental Litigation
On December 30, 2002, the Sierra Club, Physicians for Social Responsibility,
Georgia ForestWatch, and one individual filed a civil suit in U.S. District
Court in Georgia against Georgia Power for alleged violations of the Clean Air
Act at Plant Wansley. The complaint alleges Clean Air Act violations at both the
existing coal-fired units and the new combined cycle units. Specifically, the
plaintiffs allege (1) opacity violations at the coal-fired units, (2) violations
of a permit provision that requires the combined cycle units to operate above
certain levels, (3) violation of nitrogen oxide emission offset requirements,
and (4) violation of hazardous air pollutant requirements. The civil action
requests injunctive and declaratory relief, civil penalties, a supplemental
environmental project, and attorneys' fees. The Clean Air Act authorizes civil
penalties of up to $27,500 per day, per violation at each generating unit.
On January 27, 2003, Georgia Power filed a response to the complaint. Georgia
Power also filed a motion to dismiss the allegations regarding emission offsets
and hazardous air pollutants. While Georgia Power believes that it has complied
with applicable laws and regulations, an adverse outcome could require payment
of substantial penalties. The final outcome of this matter cannot now be
determined.
Mobile Energy Services' Petition for Bankruptcy
Mobile Energy Services Holdings (MESH), a subsidiary of Southern Company, 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.
In January 1999, MESH filed a petition for Chapter 11 bankruptcy relief in the
U.S. Bankruptcy Court. This action was in response to Kimberly-Clark Tissue
Company's announcement in May 1998 of plans to close its pulp mill, which had
historically provided 50 percent of MESH's revenues.
As a result of the bankruptcy filing, Southern Company has written off its
entire investment in MESH, including a $10 million after-tax write down in 2000.
At December 31, 2002, MESH had senior debt outstanding of $139 million of first
mortgage bonds and $53 million related to tax-exempt bonds. In connection with
the bond financings, in lieu of funding debt service and maintenance reserve
accounts, Southern Company provided and has subsequently paid certain limited
guarantees totaling $41 million. Southern Company continues to have a guarantee
outstanding of certain potential environmental obligations of MESH and an
obligation under certain circumstances to fund a maintenance reserve account for
the benefit of the owners of the pulp and paper complex that together represent
a maximum contingent liability of $19 million at December 31, 2002. Mirant,
formerly a subsidiary of Southern Company, agreed to indemnify Southern Company
for any amounts required to be paid under such guarantees.
In August 2000, MESH filed a proposed plan of reorganization with the U.S.
Bankruptcy Court. The proposed plan of reorganization was most recently amended
on December 13, 2001. Southern Company expects that approval of a plan of
reorganization would result in a termination of Southern Company's ownership
interest in MESH but would not affect Southern Company's continuing guarantee
obligations discussed earlier. The final outcome of this matter cannot now be
determined.
California Electricity Markets Litigation
Prior to the spin off of Mirant, Southern Company was named as a defendant in
two lawsuits filed in the superior courts of California alleging that certain
owners of electric generation facilities in California, including Southern
Company, engaged in various unlawful and anticompetitive acts that served to
manipulate wholesale power markets and inflate wholesale electricity prices in
California with the result, as alleged in one lawsuit, that customers paid
II-39
NOTES (continued)
Southern Company and Subsidiary Companies 2002 Annual Report
approximately $4 billion more for electricity than they otherwise would have.
Both lawsuits sought an award of treble damages, as well as other injunctive and
equitable relief. In the fall of 2001, the plaintiffs voluntarily dismissed
Southern Company without prejudice from the two lawsuits in which it had been
named as a defendant. Prior to being dismissed, Southern Company had notified
Mirant of its claim for indemnification for costs associated with the lawsuits
under the terms of the master separation agreement that governs the spin off of
Mirant. Mirant had undertaken the defense of the lawsuits. Plaintiffs would not
be barred by their own dismissal from naming Southern Company in some future
lawsuit, but management believes that the likelihood of Southern Company having
to pay damages in any such lawsuit is remote.
California Electricity Markets Investigation
Southern Company has received a subpoena to provide information to a federal
grand jury in the Northern District of California. The subpoena covers a number
of broad areas, including specific information regarding electricity production
and sales activities in California. Southern Company's former subsidiary,
Mirant, participated in energy marketing and trading in California during the
period relevant to the subpoena. Southern Company has produced documents in
response to the subpoena and is fully cooperating in the investigation.
Mirant Securities Litigation
In November 2002, Southern Company, along with certain former and current senior
officers of Southern Company and 12 underwriters of Mirant's initial public
offering, were added as defendants in a class action lawsuit that several Mirant
shareholders originally filed against Mirant and certain Mirant officers in May
2002. The original lawsuit against Mirant and its officers was based on
allegations related to alleged improper energy trading and marketing activities
involving the California energy market. Several other similar lawsuits filed
subsequently were consolidated into this litigation in the U.S. District Court
for the Northern District of Georgia. The November 2002 amended complaint is
based on allegations related to alleged improper energy trading and marketing
activities involving the California energy market, alleged false statements and
omissions in Mirant's prospectus for its initial public offering and in
subsequent public statements by Mirant, and accounting-related issues previously
disclosed by Mirant. For more information, see Note 11. The lawsuit purports to
include persons who acquired Mirant securities on the open market or pursuant to
an offering between September 26, 2000 and September 5, 2002. The amended
complaint does not allege any improper trading and marketing activity,
accounting errors, or material misstatements or omissions on the part of
Southern Company but seeks to impose liability on Southern Company based on
allegations that Southern Company was a "control person" as to Mirant. On
February 14, 2003, Southern Company filed a motion seeking to dismiss all claims
against the company. However, the final outcome of this matter cannot now be
determined.
Race Discrimination Litigation
In July 2000, a lawsuit alleging race discrimination was filed by three Georgia
Power employees against Georgia Power, Southern Company, and the system service
company in the Superior Court of Fulton County, Georgia. Shortly thereafter, the
lawsuit was removed to the U.S. District Court for the Northern District of
Georgia. The lawsuit also raised claims on behalf of a purported class. The
plaintiffs seek compensatory and punitive damages in an unspecified amount, as
well as injunctive relief. In August 2000, the lawsuit was amended to add four
more plaintiffs. Also, an additional subsidiary of Southern Company, Southern
Company Energy Solutions, was named a defendant.
In October 2001, the district court denied the plaintiffs' motion for class
certification. The plaintiffs filed a motion to reconsider the order denying
class certification, and the court denied the plaintiffs' motion to reconsider.
In December 2001, the plaintiffs filed a petition in the U.S. Court of Appeals
for the Eleventh Circuit seeking permission to file an appeal of the October
2001 decision, and this petition was denied. After discovery was completed on
the claims raised by the seven named plaintiffs, the defendants filed motions
for summary judgment on all of the named plaintiffs' claims. The parties await
the district court's ruling on the seven motions for summary judgment. The final
outcome of the case cannot now be determined.
Right of Way Litigation
In 2002, certain subsidiaries of Southern Company, including Georgia Power, Gulf
Power, Mississippi Power, Savannah Electric, and Southern Telecom (collectively,
defendants), were named as defendants in numerous lawsuits brought by landowners
regarding the installation and use of fiber optic cable over defendants' rights
of way located on the landowners' property. The plaintiffs' lawsuits claim that
defendants may not use or sublease to third parties some or all of the fiber
optic communications lines on the rights of way that cross the plaintiffs'
properties and that such actions by defendants exceed the easements or other
II-40
NOTES (continued)
Southern Company and Subsidiary Companies 2002 Annual Report
property rights held by defendants. The plaintiffs assert claims for, among
other things, trespass and unjust enrichment. The plaintiffs seek compensatory
and punitive damages and injunctive relief. Defendants believe that the
plaintiffs' claims are without merit. An adverse outcome in these matters could
result in substantial judgments; however, the final outcome of these matters
cannot now be determined.
Alabama Power Retail 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. In accordance with the Rate Stabilization Equalization plan, a 2 percent
increase in retail rates was effective in both April 2002 and October 2001,
amounting to an annual increase of $55 million and $58 million, respectively.
The rate adjustment procedures were revised by the APSC on March 5, 2002. The
new procedures provide for periodic rate adjustments annually rather than
quarterly and limit any annual adjustment to 3 percent. The return on common
equity range of 13 percent to 14.5 percent remained unchanged.
The ratemaking procedures will remain in effect until the APSC votes to
modify or discontinue them.
Georgia Power Retail Rate Orders
In December 2001, the GPSC approved a three-year retail rate order for Georgia
Power ending December 31, 2004. Under the terms of the order, earnings will be
evaluated against a retail return on common equity range of 10 percent to 12.95
percent. Two-thirds of any earnings above the 12.95 percent return will be
applied to rate refunds, with the remaining one-third retained by Georgia Power.
Retail rates were decreased by $118 million effective January 1, 2002.
Under a previous three-year order ending December 2001, Georgia Power's
earnings were evaluated against a retail return on common equity range of 10
percent to 12.5 percent. The order further provided 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 additional earnings above the 12.5 percent
return were applied to rate refunds, with the remaining one-third retained by
Georgia Power. Pursuant to the order, Georgia Power recorded $333 million of
accelerated amortization and interest thereon, which has been credited to a
regulatory liability account as mandated by the GPSC.
Under the rate order, the accumulated accelerated amortization and the
interest will be amortized equally over three years as a credit to expense
beginning in 2002. Effective January 1, 2002, Georgia Power discontinued
recording accelerated depreciation and amortization. Georgia Power may 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, 2004, in response to which the GPSC would be expected to
determine whether the rate order should be continued, modified, or discontinued.
In 2000 and 1999, Georgia Power recorded $44 million and $79 million,
respectively, of revenue subject to refund for estimated earnings above 12.5
percent retail return on common equity. Those refunds were made to customers in
2001 and 2000, respectively.
4. 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 Oglethorpe Power Corporation (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 facilities and with Florida Power Corporation (FPC) for a combustion
turbine unit at Intercession City, Florida.
Southern Power owns an undivided interest in Stanton Unit A and related
facilities jointly with the Orlando Utilities Commission, Kissimmee Utility
Authority, and Florida Municipal Power Agency. The unit is scheduled to go into
commercial operation in October 2003.
II-41
NOTES (continued)
Southern Company and Subsidiary Companies 2002 Annual Report
At December 31, 2002, Alabama Power's, Georgia Power's, and Southern 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% $3,267 $1,779
Plant Hatch
(nuclear) 50.1 884 665
Plant Miller
(coal)
Units 1 and 2 91.8 760 341
Plant Scherer
(coal)
Units 1 and 2 8.4 113 58
Plant Wansley
(coal) 53.5 305 156
Rocky Mountain
(pumped storage) 25.4 169 82
Intercession City
(combustion turbine) 33.3 12 1
Plant Stanton
(combined cycle)
Unit A 65.0 128 -
- --------------------------------------------------------------
Alabama Power, Georgia Power, and Southern 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.
5. LONG-TERM POWER SALES AGREEMENTS
The operating companies have long-term contractual agreements for the sale of
capacity to certain non-affiliated utilities located outside the system's
service area. These agreements are firm and are related to specific generating
units. Because the energy is generally provided at cost under these agreements,
profitability is primarily affected by capacity revenues.
Unit power from specific generating plants is currently being sold to FP&L,
FPC, and JEA. Under these agreements, approximately 1,500 megawatts of capacity
is scheduled to be sold annually unless reduced by FP&L, FPC, and JEA for the
periods after 2002 with a minimum of three years' notice -- until the expiration
of the contracts in 2010. Capacity revenues from unit power sales amounted to
$175 million in 2002, $170 million in 2001, and $177 million in 2000.
Southern Power and Mississippi Power have contractual agreements with
non-affiliated companies for the sale of capacity from certain generating units.
These capacity revenues amounted to $65 million in 2002, $53 million in 2001,
and $20 million in 2000. These amounts are included in sales for resale in the
income statement. Future capacity revenues as of December 31, 2002, are as
follows:
Year Amounts
- ---- ------------
(in millions)
2003 $ 73
2004 96
2005 148
2006 178
2007 177
2008 and thereafter 1,396
- --------------------------------------------------------------
Total $2,068
==============================================================
Included in the amounts above are capacity revenues related to contracts with
Dynegy Inc. (Dynegy) of approximately $34 million through May 2005, $64 million
from June 2005 through May 2011, and $42 million from June 2011 through May
2030. As a result of Dynegy's liquidity problems, it has provided letters of
credit totaling $96 million that can be drawn in the event of a default under
the purchase power agreements or the failure to renew the letters of credit
prior to expiration in April 2003.
6. INCOME TAXES
At December 31, 2002, the tax-related regulatory assets and liabilities were
$898 million and $450 million, respectively. These assets are attributable to
tax benefits flowed through to customers in prior years and to taxes applicable
to capitalized interest. These liabilities are attributable to deferred taxes
previously recognized at rates higher than the current enacted tax law and to
unamortized investment tax credits. The following tables and disclosures exclude
discontinued operations.
II-42
NOTES (continued)
Southern Company and Subsidiary Companies 2002 Annual Report
Details of income tax provisions are as follows:
2002 2001 2000
- --------------------------------------------------------------
(in millions)
Total provision for income taxes:
Federal --
Current $284 $477 $421
Deferred 167 (10) 95
- --------------------------------------------------------------
451 467 516
- --------------------------------------------------------------
State --
Current 64 103 71
Deferred 13 (12) 1
- --------------------------------------------------------------
77 91 72
- --------------------------------------------------------------
Total $528 $558 $588
==============================================================
Net cash payments for income taxes related to continuing operations in 2002,
2001, and 2000 were $372 million, $558 million, and $581 million, respectively.
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:
2002 2001
- --------------------------------------------------------------
(in millions)
Deferred tax liabilities:
Accelerated depreciation $3,364 $3,222
Property basis differences 1,011 1,059
Other 840 739
- --------------------------------------------------------------
Total 5,215 5,020
- --------------------------------------------------------------
Deferred tax assets:
Federal effect of state deferred taxes 111 116
Other property basis differences 185 178
Deferred costs 188 234
Pension and other benefits 146 123
Other 384 304
- --------------------------------------------------------------
Total 1,014 955
- --------------------------------------------------------------
Total deferred tax liabilities, net 4,201 4,065
Portion included in current assets
(liabilities), net 1 23
Deferred state tax assets 12 9
- --------------------------------------------------------------
Accumulated deferred income taxes
in the Consolidated Balance Sheets $4,214 $4,097
==============================================================
In addition, at December 31, 2002, Southern Company had available state of
Georgia net operating loss carryforward deductions totaling $779 million, which
could result in net state income tax benefits of $30 million, if utilized. Less
than $1 million of such deductions will expire by 2007; the remainder will
expire between 2008 and 2022. During 2002, Southern Company realized $14 million
in such state income tax benefits. Beginning in 2002, the state of Georgia
allows the filing of a combined return, which should substantially reduce any
additional net operating loss carryforwards.
In accordance with regulatory requirements, 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 $27 million
in 2002 and $30 million a year in 2001 and 2000. At December 31, 2002, all
investment tax credits available to reduce federal income taxes payable had been
utilized.
The provision for income taxes differs from the amount of income taxes
determined by applying the applicable U.S. Federal statutory rate to earnings
before income taxes and preferred dividends of subsidiaries, as a result of the
following:
2002 2001 2000
- --------------------------------------------------------------
Federal statutory rate 35.0% 35.0% 35.0%
State income tax,
net of federal deduction 2.7 3.7 3.4
Alternative fuel tax credits (5.8) (4.2) (1.3)
Employee stock plans
dividend deduction (2.9) - -
Non-deductible book
depreciation 1.3 1.7 1.7
Difference in prior years'
deferred and current tax rate (1.0) (1.1) (1.3)
Other (0.9) (2.2) (0.8)
- --------------------------------------------------------------
Effective income tax rate 28.4% 32.9% 36.7%
==============================================================
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. In accordance with Internal
Revenue Service regulations, each company is jointly and severally liable for
the tax liability.
Mirant was included in the consolidated federal tax return through April 2,
2001. Under the terms of the separation agreement, Mirant will indemnify
Southern Company for subsequent assessment of any additional taxes related to
its transactions prior to the spin off.
II-43
NOTES (continued)
Southern Company and Subsidiary Companies 2002 Annual Report
7. COMMON STOCK
Stock Issued and Repurchased
In 2002, Southern Company raised $378 million from the issuance of 16 million
new common shares under the company's various stock plans. Southern Company
issued 2 million, 17 million, and 5 million treasury shares of common stock in
2002, 2001, and 2000, respectively, through various company stock plans.
Proceeds from the issuance of treasury stock were $56 million in 2002, $395
million in 2001, and $140 million in 2000.
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. Under this
program, 50 million shares were repurchased by February 2000 at an average price
of $25.53 per share.
Shares Reserved
At December 31, 2002, a total of 42 million shares was reserved for issuance
pursuant to the Southern Investment Plan, the Employee Savings Plan, the Outside
Directors Stock Plan, and the Omnibus Incentive Compensation Plan (stock option
plan).
Stock Option Plan
Southern Company provides non-qualified stock options to a large segment of its
employees ranging from line management to executives. As of December 31, 2002,
5,878 current and former employees participated in the stock option plan. The
maximum number of shares of common stock that may be issued under this plan may
not exceed 55 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 data for the plan has been adjusted to
reflect the Mirant spin off. Activity in 2001 and 2002 for the plan is
summarized below:
Shares Average
Subject Option Price
To Option Per Share
- --------------------------------------------------------------
Balance at December 31, 1999 13,419,978 $14.97
Options granted 11,042,626 14.67
Options canceled (335,282) 14.87
Options exercised (1,560,695) 13.65
- --------------------------------------------------------------
Balance at December 31, 2000 22,566,627 $14.92
Options granted 13,623,210 20.31
Options canceled (3,397,152) 15.39
Options exercised (3,161,800) 13.83
- --------------------------------------------------------------
Balance at December 31, 2001 29,630,885 17.46
Options granted 8,040,495 25.28
Options canceled (103,295) 19.64
Options exercised (4,892,354) 15.16
- --------------------------------------------------------------
Balance at December 31, 2002 32,675,731 $19.72
==============================================================
Shares reserved for future grants:
At December 31, 2000 43,955,368
At December 31, 2001 54,795,653
At December 31, 2002 46,788,994
- --------------------------------------------------------------
Options exercisable:
At December 31, 2000 9,354,705
At December 31, 2001 11,965,858
At December 31, 2002 15,463,414
- --------------------------------------------------------------
The following table summarizes information about options
outstanding at December 31, 2002:
Dollar Price
Range of Options
- --------------------------------------------------------------
11-15 15-20 20-25
- --------------------------------------------------------------
Outstanding:
Shares (in thousands) 8,149 11,635 12,892
Average remaining
life (in years) 6.1 6.5 8.4
Average exercise price $14.53 $18.40 $24.20
Exerciseable:
Shares (in thousands) 5,830 7,186 2,448
Average exercise price $14.47 $17.99 $22.88
- --------------------------------------------------------------
II-44
NOTES (continued)
Southern Company and Subsidiary Companies 2002 Annual Report
The estimated fair values of stock options granted in 2002, 2001, and 2000
were derived using the Black-Scholes stock option pricing model. The following
table shows the assumptions and the weighted average fair values of stock
options:
2002 2001 2000
- ---------------------------------------------------------------
Interest rate 2.8% 4.8% 6.7%
Average expected life of
stock options (in years) 4.3 4.3 4.0
Expected volatility of
common stock 26.3% 25.4% 20.9%
Expected annual dividends
on common stock $1.37 $1.34 $1.34
Weighted average fair value
of stock options granted $3.37 $2.82 $3.36
- ---------------------------------------------------------------
The pro forma impact of fair-value accounting for options
granted on earnings from continuing operations is as follows:
As Pro
Reported Forma
- --------------------------------------------------------------
2002
Net income (in millions) $1,318 $1,299
Earnings per share (dollars):
Basic $1.86 $1.83
Diluted $1.85 $1.82
2001
Net income (in millions) $1,119 $1,102
Earnings per share (dollars):
Basic $1.62 $1.60
Diluted $1.61 $1.59
2000
Net income (in millions) $994 $984
Earnings per share (dollars):
Basic $1.52 $1.51
Diluted $1.52 $1.51
- --------------------------------------------------------------
Diluted Earnings Per Share
For Southern Company, the only difference in computing basic and diluted
earnings per share is attributable to outstanding options under the stock option
plan. The effect of the stock options was determined using the treasury stock
method. Shares used to compute diluted earnings per share are as follows:
Average Common Stock Shares
-------------------------------
2002 2001 2000
- --------------------------------------------------------------
(in thousands)
As reported shares 708,161 689,352 653,087
Effect of options 5,409 4,191 1,018
- --------------------------------------------------------------
Diluted shares 713,570 693,543 654,105
==============================================================
Common Stock Dividend Restrictions
The income of Southern Company is derived primarily from equity in earnings of
its subsidiaries. At December 31, 2002, consolidated retained earnings included
$3.6 billion of undistributed retained earnings of the subsidiaries. Of this
amount, $313 million was restricted against the payment by the subsidiary
companies of cash dividends on common stock under terms of bond indentures.
8. FINANCING
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, 2002, capital securities of
$400 million and preferred securities of $2.0 billion were outstanding and
recognized in the Consolidated Balance Sheets. Southern Company guarantees the
notes related to $950 million of capital or preferred securities issued on its
behalf.
Long-Term Debt Due Within One Year
A summary of scheduled maturities and redemptions of long-term debt due within
one year at December 31 is as follows:
2002 2001
- --------------------------------------------------------------
(in millions)
First mortgage bond maturities
and redemptions $ 33 $ 7
Pollution control bonds 1 8
Capitalized leases 11 4
Senior notes 1,552 380
Other long-term debt 42 30
- --------------------------------------------------------------
Total $1,639 $429
==============================================================
Debt redemptions and/or serial maturities through 2007 applicable to total
long-term debt are as follows: $1.6 billion in 2003; $692 million in 2004; $432
million in 2005; $228 million in 2006; and $519 million in 2007.
II-45
NOTES (continued)
Southern Company and Subsidiary Companies 2002 Annual Report
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
operating companies, constitute a direct first lien on substantially all of the
operating companies' respective fixed property and franchises. Georgia Power
discharged its mortgage in early 2002 and the lien was removed. 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.
Bank Credit Arrangements
At the beginning of 2003, unused credit arrangements with banks totaled $3.9
billion, of which $3.0 billion expires during 2003, $860 million expires during
2004, and $15 million expires during 2005. The following table outlines the
credit arrangements by company:
Amount of Credit
--------------------------------------
Expires
----------------
2004 &
Company Total Unused 2003 beyond
- ------- --------------------------------------
(in millions)
Alabama Power $ 923 $ 923 $ 533 $390
Georgia Power 1,175 1,175 1,175 -
Gulf Power 66 66 66 -
Mississippi Power 97 97 97 -
Savannah Electric 80 55 40 15
Southern Company 1,000 1,000 1,000 -
Southern Power 850 470 - 470
Other 70 70 70 -
- --------------------------------------------------------------
Total $4,261 $3,856 $2,981 $875
==============================================================
Approximately $2.6 billion of the credit facilities expiring in 2003 allow
the execution of term loans for an additional two-year period. Most of these
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. Commitment fees are less than 1/8 of 1 percent for
Southern Company and the operating companies and less than 3/8 of 1 percent for
Southern Power. Compensating balances are not legally restricted from
withdrawal. Included in the total $3.9 billion of unused credit arrangements is
$3.4 billion of syndicated credit arrangements that require the payment of agent
fees.
Most of Southern Company's and the operating companies' credit arrangements
with banks have covenants that limit debt levels to 65 percent of total
capitalization. For Southern Power, the debt level is 60 percent, excluding
intercompany loans. Exceeding these debt levels would result in a default under
the credit arrangements. In addition, the credit arrangements typically contain
cross default provisions that would be triggered if the borrower defaulted on
other indebtedness above a specified threshold. Under the credit arrangements
for Southern Company and the operating companies, the cross default provisions
are restricted only to the indebtedness, including any guarantee obligations, of
the company that has the credit arrangement with the bank. For Southern Power's
bank credit arrangements, there is a cross default to Southern Company's
indebtedness, which if triggered would require prepayment of debt related to
projects financed under the credit arrangement that are not complete. Southern
Company and its subsidiaries are currently in compliance with all such
covenants. Borrowings under certain operating companies' unused credit
arrangements totaling $159 million would be prohibited if the borrower
experiences a material adverse change, as defined in such agreements. Initial
borrowings for new projects under Southern Power's credit facility would be
prohibited if Southern Power or Southern Company experiences a material adverse
change, as defined in that credit facility.
A portion of the $3.9 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, 2002 was $941 million.
II-46
NOTES (continued)
Southern Company and Subsidiary Companies 2002 Annual Report
Southern Company, the operating companies, and Southern Power borrow through
commercial paper programs that have the liquidity support of committed bank
credit arrangements. In addition, the companies from time to time borrow under
uncommitted lines of credit with banks and through extendible commercial note
programs. As of December 31, 2002, the amount outstanding was $20 million under
these lines and $31 million in extendible commercial notes. The amount of
commercial paper outstanding at December 31, 2002 and December 31, 2001, was
$858 million and $1.8 billion, respectively. Commercial paper is included in
notes payable on the Consolidated Balance Sheets.
Financial Instruments
Southern Company has firm purchase commitments for equipment that require
payment in euros. As a hedge against fluctuations in the exchange rate for
euros, the company entered into forward currency swaps. The total notional
amount is 6 million euros maturing in 2003. At December 31, 2002, the unrealized
gain on these swaps was $1 million.
Southern Company and certain subsidiaries enter into interest rate swaps to
hedge exposure to interest rate changes. Swaps related to fixed rate securities
are accounted for as fair value hedges. Swaps related to variable rate
securities or forecasted transactions are accounted for as cash flow hedges. The
swaps are generally structured to mirror the terms of the hedged debt
instruments; therefore, no material ineffectiveness has been recorded in
earnings. The gain or loss in fair value for cash flow hedges is recorded in
other comprehensive income and will be recognized in earnings over the life of
the hedged items.
At December 31, 2002, Southern Company had $2.8 billion notional amount of
interest rate swaps outstanding with net deferred losses of $52 million as
follows:
Fair Value Hedges
Fixed Variable Fair
Rate Rate Notional Value
Company Maturity Received Paid Amount Gain
- ------------------------------------------ -----------------
(in millions)
Southern
Company 2007 5.30% 1.53% $400 $39
- --------------------------------------------------------------
Cash Flow Hedges
Weighted Average
--------------------
Variable Fixed Fair
Rate Rate Notional Value
Company Maturity Received Paid Amount (Loss)
- ------------------------------------------ ----------------
(in millions)
Southern
Company 2003 1.74% 3.20% $200 $ (2)
2004 1.74 3.20 200 (4)
Alabama
Power 2003 1.95 3.02 350 (5)
Alabama
Power 2004 1.43 1.63 486 (2)
Alabama
Power 2003 * 3.05 167 (2)
Alabama
Power 2003 * 3.96 250 (6)
Georgia
Power 2003 * 4.76 250 (7)
Southern
Power 2013 * 6.23 350 (50)
Southern
Power 2008 * 5.48 150 (13)
- --------------------------------------------------------------
*Rate has not been set.
For the year 2002, approximately $1 million was reclassified from other
comprehensive income to interest expense. For the year 2003, approximately $2
million is expected to be reclassified.
9. COMMITMENTS
Construction Program
Southern Company is engaged in continuous construction programs, currently
estimated to total $2.1 billion in 2003, $2.3 billion in 2004, and $2.4 billion
in 2005. 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, 2002, significant purchase
commitments were outstanding in connection with the construction program.
Southern Company has approximately 4,100 megawatts of additional generating
capacity scheduled to be placed in service by 2005.
II-47
NOTES (continued)
Southern Company and Subsidiary Companies 2002 Annual Report
Long-Term Service Agreements
The operating companies and Southern Power have entered into several Long-Term
Service Agreements (LTSAs) with General Electric (GE) for the purpose of
securing maintenance support for the combined cycle and combustion turbine
generating facilities owned by the subsidiaries. In summary, the LTSAs stipulate
that GE will perform all planned inspections on the covered equipment, which
includes the cost of all labor and materials. GE is also obligated to cover the
costs of unplanned maintenance on the covered equipment subject to a limit
specified in each contract.
In general, except for Southern Power's Plant Dahlberg, these LTSAs are in
effect through two major inspection cycles per unit. The Dahlberg agreement is
in effect through the first major inspection of each unit. Scheduled payments to
GE are made at various intervals based on actual operating hours of the
respective units. Total payments to GE under these agreements for facilities
owned are currently estimated at $1.2 billion over the life of the agreements,
which may range up to 30 years. However, the LTSAs contain various cancellation
provisions at the option of the purchasers.
Payments made to GE prior to the performance of any planned inspections are
recorded as a prepayment in the Consolidated Balance Sheets. Inspection costs
are capitalized or charged to expense based on the nature of the work performed.
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.
Natural gas purchases are based on various indices at the time of delivery;
therefore, only the volume commitments are firm and disclosed in the following
chart. Also, Southern Company has entered into various long-term commitments for
the purchase of electricity. Total estimated minimum long-term obligations at
December 31, 2002 were as follows:
Natural
Gas Purchased
Year MMBtu Fuel Power
- ---- ----------- ---------------------
(in millions) (in millions)
2003 199,635 $2,211 $ 116
2004 121,020 1,735 136
2005 58,465 1,296 171
2006 38,960 1,130 178
2007 13,590 1,038 180
2008 and thereafter - 2,347 1,090
- --------------------------------------------------------------
Total commitments 431,670 $9,757 $1,871
==============================================================
Additional commitments for fuel will be required to supply Southern Company's
future needs.
Operating Leases
In May 2001, Mississippi Power began the initial 10-year term of a lease
agreement signed in 1999 for a combined cycle generating facility built at Plant
Daniel. The facility cost approximately $370 million. The lease provides for a
residual value guarantee -- approximately 71 percent of the completion cost --
by Mississippi Power that is due upon termination of the lease in certain
circumstances. The lease also includes purchase and renewal options. Upon
termination of the lease, Mississippi Power may either exercise its purchase
option of the facility or allow it to be sold to a third party. Mississippi
Power expects the fair market value of the leased facility to substantially
reduce or eliminate its payment under the residual value guarantee. The amount
of future minimum operating lease payments exclusive of any payment related to
this guarantee will be approximately $25 million annually during the initial
term.
Southern Company has other operating lease agreements with various terms and
expiration dates. Total operating lease expenses were $171 million, $64 million,
and $42 million for 2002, 2001, and 2000, respectively. At December 31, 2002,
II-48
NOTES (continued)
Southern Company and Subsidiary Companies 2002 Annual Report
estimated minimum rental commitments for noncancelable operating leases were as
follows:
Rail
Year Cars Other Total
- ---- -----------------------------
(in millions)
2003 $ 37 $ 88 $125
2004 36 78 114
2005 33 66 99
2006 28 56 84
2007 20 43 63
2008 and thereafter 125 152 277
- ---------------------------------------------------------------
Total minimum payments $279 $483 $762
===============================================================
For the operating companies, the rail car lease expenses are recoverable
through fuel cost recovery provisions. In addition to the above rental
commitments, Alabama Power and Georgia Power have obligations upon expiration of
certain rail car leases with respect to the residual value of the leased
property. These leases expire in 2004, 2006, and 2010, and the maximum
obligations are $39 million, $66 million, and $40 million, respectively. At the
termination of the leases, the lessee may either exercise its purchase option or
the property can be sold to a third party. Alabama Power and Georgia Power
expect that the fair market value of the leased property would substantially
reduce or eliminate the payments under the residual value obligations.
Guarantees
Southern Company has made separate guarantees to certain counterparties
regarding performance of contractual commitments by Mirant's trading and
marketing subsidiaries. At December 31, 2002, the total notional amount of
guarantees was $42 million, all of which will expire by 2007. The estimated fair
value of these net contractual commitments outstanding was approximately $19
million at December 31, 2002. Under the terms of the separation agreement,
Mirant may not enter into any new commitments under these guarantees after the
spin off date. Southern Company's potential exposure under these contractual
commitments is not expected to materially differ from the estimated fair value.
Subsequent to the spin off, Mirant began paying Southern Company a fee of 1
percent annually on the average aggregate maximum principal amount of all
guarantees outstanding until they are replaced or expire. Mirant must use
reasonable efforts to release Southern Company from all such support
arrangements and will indemnify Southern Company for any obligations incurred.
Prior to 1999, a subsidiary of Southern Company originated loans to
residential customers of the operating companies for heat pump purchases. These
loans were sold to Fannie Mae with recourse for any loan with payments
outstanding over 120 days. The individual operating companies are responsible
for the repurchase of their respective customers' delinquent loans. As of
December 31, 2002, the outstanding loans guaranteed by the operating companies
were $18 million, and loan loss reserves of $4 million have been recorded.
Southern Company has executed a keep-well agreement with a subsidiary of
Southern Holdings -- a direct subsidiary -- to make capital contributions in the
event of any shortfall in payments due under a participation agreement with an
entity in which the subsidiary holds a 30 percent investment. The maximum
aggregate amount of Southern Company's liability under this keep-well agreement
is $50 million.
As discussed earlier in this note under Operating Leases, Mississippi Power,
Georgia Power, and Alabama Power have entered into certain residual value
guarantees. Southern Company has also guaranteed certain contingent liabilities
of MESH discussed in Note 3.
10. 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
$300 million by American Nuclear Insurers (ANI), 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.
II-49
NOTES (continued)
Southern Company and Subsidiary Companies 2002 Annual Report
Alabama Power and Georgia Power are members of Nuclear Electric Insurance
Limited (NEIL), a mutual insurer established to provide property damage
insurance in an amount up to $500 million for members' nuclear generating
facilities.
Additionally, both companies have policies that currently provide
decontamination, excess property insurance, and premature decommissioning
coverage up to $2.25 billion for losses in excess of the $500 million primary
coverage. This excess insurance is also provided by NEIL.
NEIL also covers the additional costs that would be incurred in obtaining
replacement power during a prolonged accidental outage at a member's nuclear
plant. Members can purchase this coverage, subject to a deductible waiting
period of between 8 to 26 weeks, with a maximum per occurrence per unit limit of
$490 million. After this deductible period, weekly indemnity payments would be
received until either the unit is operational or until the limit is exhausted in
approximately three years. Alabama Power and Georgia Power each purchase the
maximum limit allowed by NEIl subject to ownership limitations. Each facility
has elected a 12 week waiting period.
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 NEIL policies would be $36 million and $40 million,
respectively.
Following the terrorist attacks of September 2001, both ANI and NEIL
confirmed that terrorist acts against commercial nuclear power plants would be
covered under their insurance. However, both companies revised their policy
terms on a prospective basis to include an industry aggregate for all terrorist
acts. The NEIL aggregate, which applies to all claims stemming from terrorism
within a 12-month duration, is $3.24 billion plus any amounts that would be
available through reinsurance or indemnity from an outside source. The ANI cap
is a $300 million shared industry aggregate.
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.
11. DISCONTINUED OPERATIONS
Mirant Spin Off
In April 2000, Southern Company announced an initial public offering of up to
19.9 percent of Mirant and its intention to spin off the remaining ownership of
Mirant to Southern Company stockholders within 12 months of the initial stock
offering. On October 2, 2000, Mirant completed its initial public offering of
66.7 million shares of common stock priced at $22 per share. This represented
19.7 percent of the 338.7 million shares outstanding. As a result of the stock
offering, Southern Company recorded a $560 million increase in paid-in capital
with no gain or loss being recognized.
On February 19, 2001, the Southern Company Board of Directors approved the
spin off of its remaining ownership of 272 million Mirant shares. On April 2,
2001, the tax-free distribution of Mirant shares was completed at a ratio of
approximately 0.4 for every share of Southern Company common stock held at
record date.
The distribution resulted in charges of approximately $3.2 billion and $0.4
billion to Southern Company's paid-in capital and retained earnings,
respectively. The distribution was treated as a non-cash transaction for
purposes of the statement of cash flows.
As a result of the spin off, Southern Company's financial statements reflect
Mirant's results of operations, balance sheets, and cash flows as discontinued
operations.
Potential Mirant Restatement
In November 2002, Mirant announced that it had identified accounting errors in
previously issued financial statements, primarily related to its risk management
and marketing operations. As a result of these accounting errors, Mirant
reported that its net income for January 1999 through December 2001 was
overstated by $51 million. Mirant has stated that the specific periods to which
II-50
NOTES (continued)
Southern Company and Subsidiary Companies 2002 Annual Report
these overstatements apply have not been determined. Mirant further announced
that it had requested its independent auditors to reaudit Mirant's 2001 and 2000
financial statements and stated that it did not expect that its reaudit could be
completed until it files its Form 10-K for the year ended December 31, 2002. If
the reaudit of Mirant's 2001 and 2000 financial statements results in
adjustments that relate to periods prior to Southern Company's spin off of
Mirant, Southern Company's earnings from discontinued operations for such
periods could be affected. The impact of any such adjustments would not affect
Southern Company's 2002 or any future financial statements.
12. SEGMENT AND RELATED INFORMATION
Southern Company's reportable business segment is the sale of electricity in the
Southeast by the five operating companies and Southern Power. Net income and
total assets for discontinued operations are included in the reconciling
eliminations column. The all other column 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 alternative fuel investments, energy-related
products and services, and leasing and financing services. Intersegment revenues
are not material. Financial data for business segments and products and services
are as follows:
Business Segments
Electric All Reconciling
Year Utilities Other Eliminations Consolidated
- ---- ----------------------------------------------------------------------------------
(in millions)
2002
- ----
Operating revenues $10,206 $ 365 $ (22) $10,549
Depreciation and amortization 988 59 - 1,047
Interest income 19 10 (7) 22
Interest expense 586 105 (7) 684
Income taxes 777 (249) - 528
Segment net income (loss) 1,296 23 (1) 1,318
Total assets 30,409 1,881 (491) 31,799
Gross property additions 2,598 119 - 2,717
- ---------------------------------------------------------------------------------------------------------------------------
Electric All Reconciling
Year Utilities Other Eliminations Consolidated
- --- -----------------------------------------------------------------------------------
(in millions)
2001
- ----
Operating revenues $ 9,906 $ 267 $ (18) $10,155
Depreciation and amortization 1,144 29 - 1,173
Interest income 21 8 (2) 27
Interest expense 591 137 (2) 726
Income taxes 702 (144) - 558
Segment net income (loss) 1,149 (30) 143 1,262
Total assets 29,479 2,420 (2,002) 29,897
Gross property additions 2,565 52 - 2,617
- ---------------------------------------------------------------------------------------------------------------------------
II-51
NOTES (continued)
Southern Company and Subsidiary Companies 2002 Annual Report
Electric All Reconciling
Year Utilities Other Eliminations Consolidated
- ---- ----------------------------------------------------------------------------------
(in millions)
2000
- ----
Operating revenues $ 9,860 $ 246 $ (40) $10,066
Depreciation and amortization 1,135 36 - 1,171
Interest income 21 7 1 29
Interest expense 615 197 - 812
Income taxes 703 (115) - 588
Segment net income (loss) 1,109 (115) 319 1,313
Total assets 26,922 2,200 2,240 31,362
Gross property additions 2,199 26 - 2,225
- ---------------------------------------------------------------------------------------------------------------------------
Products and Services
Electric Utilities Revenues
--------------------------------------------------------------------------------------
Year Retail Wholesale Other Total
- ---- --------------------------------------------------------------------------------------
(in millions)
2002 $8,728 $1,168 $310 $10,206
2001 8,440 1,174 292 9,906
2000 8,600 977 283 9,860
- --------------------------------------------------------------------------------------------------------------------------
13. QUARTERLY FINANCIAL INFORMATION FOR CONTINUING OPERATIONS (UNUADITED)
Summarized quarterly financial data for 2002 and 2001 are as follows:
Per Common Share (Note)
------------------------------------------------
Operating Operating Consolidated Basic Price Range
Quarter Ended Revenues Income Net Income Earnings Dividends High Low
- -------------- --------- ---------------------------------------------------------------------------------
(in millions)
March 2002 $2,214 $ 512 $224 $0.32 $0.3350 $26.78 $24.49
June 2002 2,630 659 332 0.47 0.3350 28.39 25.65
September 2002 3,248 1,070 595 0.84 0.3425 29.02 23.89
December 2002 2,457 340 167 0.23 0.3425 30.85 25.17
March 2001 $2,270 $475 $180 $0.26 $0.3350 $21.65 $16.15
June 2001 2,561 585 270 0.40 0.3350 23.88 20.89
September 2001 3,165 998 554 0.80 0.3350 26.00 22.05
December 2001 2,159 333 116 0.16 0.3350 25.98 22.30
- ----------------------------------------------------------------------------------------------------------------------------------
Southern Company's business is influenced by seasonal weather conditions.
II-52
SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA 1998-2002
Southern Company and Subsidiary Companies 2002 Annual Report
- ---------------------------------------------------------------------------------------------------------------------------
2002 2001 2000 1999 1998
- ---------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in millions) $10,549 $10,155 $10,066 $9,317 $9,499
Total Assets (in millions) $31,799 $29,897 $31,362 $29,291 $28,723
Gross Property Additions (in millions) $2,717 $2,617 $2,225 $1,881 $1,356
Return on Average Common Equity (percent) 15.79 13.51 13.20 13.43 10.04
Cash Dividends Paid Per Share of Common Stock $1.355 $1.34 $1.34 $1.34 $1.34
- ---------------------------------------------------------------------------------------------------------------------------
Consolidated Net Income (in millions):
Continuing operations $1,318 $1,120 $ 994 $ 915 $986
Discontinued operations - 142 319 361 (9)
- ---------------------------------------------------------------------------------------------------------------------------
Total $1,318 $1,262 $1,313 $1,276 $977
===========================================================================================================================
Earnings Per Share From Continuing Operations --
Basic $1.86 $1.62 $1.52 $1.33 $1.41
Diluted 1.85 1.61 1.52 1.33 1.41
Earnings Per Share Including Discontinued Operations --
Basic $1.86 $1.83 $2.01 $1.86 $1.40
Diluted 1.85 1.82 2.01 1.86 1.40
- ---------------------------------------------------------------------------------------------------------------------------
Capitalization (in millions):
Common stock equity $ 8,710 $ 7,984 $10,690 $ 9,204 $ 9,797
Preferred stock and securities 2,718 2,644 2,614 2,615 2,465
Long-term debt 8,658 8,297 7,843 7,251 6,505
- ---------------------------------------------------------------------------------------------------------------------------
Total excluding amounts due within one year $20,086 $18,925 $21,147 $19,070 $18,767
===========================================================================================================================
Capitalization Ratios (percent):
Common stock equity 43.4 42.2 50.6 48.3 52.2
Preferred stock and securities 13.5 13.9 12.3 13.7 13.1
Long-term debt 43.1 43.9 37.1 38.0 34.7
- ---------------------------------------------------------------------------------------------------------------------------
Total excluding amounts due within one year 100.0 100.0 100.0 100.0 100.0
===========================================================================================================================
Other Common Stock Data (Note):
Book value per share (year-end) $12.16 $11.43 $15.69 $13.82 $14.04
Market price per share (dollars):
High $30.850 $26.000 $35.000 $29.625 $31.563
Low 23.890 16.152 20.375 22.063 23.938
Close 28.390 25.350 33.250 23.500 29.063
Market-to-book ratio (year-end) (percent) 233.5 221.8 211.9 170.0 207.0
Price-earnings ratio (year-end) (times) 15.3 15.6 16.5 12.6 20.8
Dividends paid (in millions) $958 $922 $873 $921 $933
Dividend yield (year-end) (percent) 4.8 5.3 4.0 5.7 4.6
Dividend payout ratio (percent) 72.8 82.4 66.5 72.2 95.6
Shares outstanding (in thousands):
Average 708,161 689,352 653,087 685,163 696,944
Year-end 716,402 698,344 681,158 665,796 697,747
Stockholders of record (year-end) 141,784 150,242 160,116 174,179 187,053
- ---------------------------------------------------------------------------------------------------------------------------
Customers (year-end) (in thousands):
Residential 3,496 3,441 3,398 3,339 3,277
Commercial 553 539 527 513 497
Industrial 14 14 14 15 15
Other 5 4 5 4 5
- ---------------------------------------------------------------------------------------------------------------------------
Total 4,068 3,998 3,944 3,871 3,794
===========================================================================================================================
Employees (year-end) 26,178 26,122 26,021 26,269 25,206
- ---------------------------------------------------------------------------------------------------------------------------
Note: Common stock data in 2001 declined as a result of the Mirant spin off.
II-53
SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA 1998-2002 (continued)
Southern Company and Subsidiary Companies 2002 Annual Report
- ---------------------------------------------------------------------------------------------------------------------------
2002 2001 2000 1999 1998
- ---------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in millions):
Residential $ 3,556 $ 3,247 $ 3,361 $3,107 $3,167
Commercial 3,007 2,966 2,918 2,745 2,766
Industrial 2,078 2,144 2,289 2,238 2,268
Other 87 83 32 - 79
- ---------------------------------------------------------------------------------------------------------------------------
Total retail 8,728 8,440 8,600 8,090 8,280
Sales for resale within service area 389 338 377 350 374
Sales for resale outside service area 779 836 600 473 522
- ---------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 9,896 9,614 9,577 8,913 9,176
Other revenues 653 541 489 404 323
- ---------------------------------------------------------------------------------------------------------------------------
Total $10,549 $10,155 $10,066 $9,317 $9,499
===========================================================================================================================
Kilowatt-Hour Sales (in millions):
Residential 48,784 44,538 46,213 43,402 43,503
Commercial 48,250 46,939 46,249 43,387 41,737
Industrial 53,851 52,891 56,746 56,210 55,331
Other 1,000 977 970 945 929
- ---------------------------------------------------------------------------------------------------------------------------
Total retail 151,885 145,345 150,178 143,944 141,500
Sales for resale within service area 10,597 9,388 9,579 9,440 9,847
Sales for resale outside service area 21,954 21,380 17,190 12,929 12,988
- ---------------------------------------------------------------------------------------------------------------------------
Total 184,436 176,113 176,947 166,313 164,335
===========================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 7.29 7.29 7.27 7.16 7.28
Commercial 6.23 6.32 6.31 6.33 6.63
Industrial 3.86 4.05 4.03 3.98 4.10
Total retail 5.75 5.81 5.73 5.62 5.85
Sales for resale 3.59 3.82 3.65 3.68 3.92
Total sales 5.37 5.46 5.41 5.36 5.58
Average Annual Kilowatt-Hour
Use Per Residential Customer 14,036 13,014 13,702 13,107 13,379
Average Annual Revenue Per Residential Customer $1,023.18 $948.83 $996.44 $938.39 $973.94
Plant Nameplate Capacity Owned (year-end) (megawatts) 36,353 34,579 32,807 31,425 31,161
Maximum Peak-Hour Demand (megawatts):
Winter 25,939 26,272 26,370 25,203 21,108
Summer 32,355 29,700 31,359 30,578 28,934
System Reserve Margin (at peak) (percent) 13.3 19.3 8.1 8.5 12.8
Annual Load Factor (percent) 51.1 62.0 60.2 59.2 60.0
Plant Availability (percent):
Fossil-steam 84.8 88.1 86.8 83.3 85.2
Nuclear 90.3 90.8 90.5 89.9 87.8
- ---------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 65.7 67.5 72.3 73.1 72.8
Nuclear 14.7 15.2 15.1 15.7 15.4
Hydro 2.6 2.6 1.5 2.3 3.9
Gas 11.4 8.4 4.0 2.8 3.3
Purchased power 5.6 6.3 7.1 6.1 4.6
- ---------------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0 100.0 100.0
===========================================================================================================================
II-54
ALABAMA POWER COMPANY
FINANCIAL SECTION
II-55
MANAGEMENT'S REPORT
Alabama Power Company 2002 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 accounting principles
generally accepted in the United States 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 accounting 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 Southern Company audit committee of its board of directors, composed of
five independent directors, provides a broad overview of management's financial
reporting and control functions. Additionally, a committee of Alabama Power's
board of directors, composed of three outside directors, meets periodically with
management, the internal auditors and the independent public accountants to
discuss auditing, internal controls, and compliance matters. The internal
auditors and independent public accountants have access to the members of these
committees 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 accounting principles generally
accepted in the United States.
/s/Charles D. McCrary
Charles D. McCrary
President
and Chief Executive Officer
/s/William B. Hutchins, III
William B. Hutchins, III
Executive Vice President,
Chief Financial Officer, and Treasurer
February 17, 2003
II-56
INDEPENDENT AUDITORS' REPORT
Alabama Power Company:
We have audited the accompanying balance sheet and statement of capitalization
of Alabama Power Company (a wholly owned subsidiary of Southern Company) as of
December 31, 2002, and the related statements of income, comprehensive income,
common stockholder's equity, and cash flows for the year then ended. These
financial statements are the responsibility of Alabama Power Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audit. The financial statements of Alabama Power Company
as of December 31, 2001, and for each of the two years then ended were audited
by other auditors who have ceased operations. Those auditors expressed an
unqualified opinion on those financial statements and included an explanatory
paragraph that described a change in the method of accounting for derivative
instruments and hedging activities in their report dated February 13, 2002.
We conducted our audit in accordance with auditing standards generally
accepted in the United States of America. 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 audit provides a
reasonable basis for our opinion.
In our opinion, the 2002 financial statements (pages II-71 to II-92) present
fairly, in all material respects, the financial position of Alabama Power
Company at December 31, 2002, and the results of its operations and its cash
flows for the year then ended in conformity with accounting principles generally
accepted in the United States of America.
/s/Deloitte & Touche LLP
Birmingham, Alabama
February 17, 2003
THE FOLLOWING REPORT OF INDEPENDENT ACCOUNTANTS IS A COPY OF THE REPORT
PREVIOUSLY ISSUED IN CONNECTION WITH THE COMPANY'S 2001 ANNUAL REPORT
ON FORM 10-K AND HAS NOT BEEN REISSUED BY ARTHUR ANDERSEN LLP. SEE EXHIBIT
23(b)2 FOR ADDITIONAL INFORMATION.
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, 2001 and 2000, 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, 2001. 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-58 through II-76)
referred to above present fairly, in all material respects, the financial
position of Alabama Power Company as of December 31, 2001 and 2000, and the
results of its operations and its cash flows for each of the three years in the
period ended December 31, 2001, in conformity with accounting principles
generally accepted in the United States.
As explained in Note 1 to the financial statements, effective January 1,
2001, Alabama Power Company changed its method of accounting for derivative
instruments and hedging activities.
/s/ Arthur Andersen LLP
Birmingham, Alabama
February 13, 2002
II-57
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Alabama Power Company 2002 Annual Report
RESULTS OF OPERATIONS
Earnings
Alabama Power Company's 2002 net income after dividends on preferred stock was
$461 million, representing a $74 million (19.3 percent) increase from the prior
year. This improvement is primarily attributable to increased territorial energy
sales and higher retail rates when compared to the prior year. More favorable
weather conditions in 2002 as compared to the unusually mild weather experienced
in 2001 contributed to the increases in territorial sales. The increases in
revenues were partially offset by increased non-fuel operating expenses.
In 2001 earnings were $387 million, representing a 7.9 percent decrease from
the prior year. This decline was primarily attributable to a decrease in
territorial energy sales as a result of an economic downturn and milder
temperatures. Earnings in the year 2000 were $420 million, representing a 5
percent increase from the prior year. This improvement was primarily
attributable to an increase in territorial sales partially offset by increased
non-fuel operating expenses.
The return on average common equity for 2002 was 13.80 percent compared to
11.89 percent in 2001 and 13.58 percent in 2000. A condensed income statement is
as follows:
Increase (Decrease)
Amount From Prior Year
- --------------------------------------------------------------
2002 2002 2001 2000
- --------------------------------------------------------------
(in millions)
Operating revenues $3,710 $124 $(81) $282
- --------------------------------------------------------------
Fuel 970 (31) 38 108
Purchased power 249 (44) (56) 75
Other operation
and maintenance 854 71 (56) 30
Depreciation
and amortization 398 15 19 17
Taxes other than
income taxes 217 2 5 5
- --------------------------------------------------------------
Total operating
expenses 2,688 13 (50) 235
-------------------------------------------------------------
Operating income 1,022 111 (31) 47
Other income
(expense), net (269) 7 (15) (8)
Less --
Income taxes 292 44 (13) 19
- --------------------------------------------------------------
Net Income $ 461 $ 74 $(33) $ 20
==============================================================
Revenues
Operating revenues for 2002 were $3.7 billion, reflecting a $124 million
increase from 2001. The following table summarizes the principal factors that
have affected operating revenues for the past three years:
Amount
----------------------------------------
2002 2001 2000
- -----------------------------------------------------------------
(in thousands)
Retail - prior year $2,747,673 $2,952,707 $2,811,117
Change in -
Base rates 76,326 22,918 -
Sales growth 70,050 (36,197) 58,347
Weather 60,089 (61,846) 21,917
Fuel cost recovery
and other (2,921) (129,909) 61,326
- -----------------------------------------------------------------
Total retail 2,951,217 2,747,673 2,952,707
- -----------------------------------------------------------------
Sales for resale --
Non-affiliates 474,291 485,974 461,730
Affiliates 188,163 245,189 166,219
- -----------------------------------------------------------------
Total sales for resale 662,453 731,163 627,949
- -----------------------------------------------------------------
Other operating
revenues 96,862 107,554 86,805
- -----------------------------------------------------------------
Total operating
revenues $3,710,533 $3,586,390 $3,667,461
=================================================================
Percent change 3.5% (2.2)% 8.3%
- ------------------------------------------------------------------
Retail revenues of $3.0 billion in 2002 increased $204 million (7.4 percent)
from the prior year, decreased $205 million (6.9 percent) in 2001, and increased
$142 million (5 percent) in 2000. The primary contributors to the increase in
revenues in 2002, shown in the table above, were the positive effect of
favorable weather conditions on energy sales and increases in retail base rates
(0.6 percent increase in July 2001, and 2 percent increases in October 2001 and
April 2002). The Company mitigated these increases to the customer with a
decrease to the energy cost recovery factor in April 2002.
Fuel rates billed to customers are designed to fully recover fluctuating
fuel costs over a period of time. Lower natural gas prices and increased hydro
production combined with decreased costs of purchased power have resulted in an
$83 million reduction in under-recovered fuel costs. At December 31, 2002, the
Company had completely recovered its previously under-recovered fuel cost. Fuel
revenues have no effect on net income because they represent the recording of
revenues to offset fuel expenses.
II-58
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2002 Annual Report
Energy sales for resale outside the service area are predominantly unit
power sales under long-term contracts to Florida utilities. Economy energy and
energy sold under short-term contracts are also sold for resale outside the
service area. Revenues from power sales 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 and other
outside the service area contracts with non-affiliates, were as follows:
2002 2001 2000
------------------------------------
(in thousands)
Unit power -
Capacity $119,193 $124,720 $127,445
Energy 134,051 134,006 127,911
Other power contracts -
Capacity 14,613 13,324 11,546
Energy 61,925 91,608 43,964
---------------------------------------------------------------
Total $329,782 $363,658 $310,866
===============================================================
Capacity revenues from non-affiliates were relatively unchanged over the
past three years. There are no significant scheduled declines in capacity until
the termination of the unit power sales contracts in 2010.
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.
Other operating revenues in 2002 decreased $11 million (9.9 percent) from
2001 due to a decrease in revenues from gas-fueled co-generation steam
facilities primarily from lower gas prices and lower demand. Since co-generation
steam revenues are generally offset by fuel expenses, these revenues did not
have a significant impact on earnings.
The $21 million (23.9 percent) increase in other operating revenues in 2001
and $20 million (30.5 percent) increase in 2000 were primarily attributed to
increased steam sales in conjunction with the operation of the Company's
co-generation facilities, fuel sales, and rent from electric property.
Kilowatt-hour (KWH) sales for 2002 and the percent change by year were as
follows:
KWH Percent Change
-----------------------------------
2002 2002 2001 2000
-----------------------------------
(millions)
Residential 17,403 9.6% (5.3)% 6.8%
Commercial 13,363 4.4 (1.5) 5.5
Industrial 21,103 3.1 (7.4) 0.7
Other 204 3.7 (3.9) 2.3
--------
Total retail 52,073 5.5 (5.2) 3.8
Sales for resale -
Non-affiliates 15,554 1.8 2.9 19.4
Affiliates 8,844 - 64.7 6.7
--------
Total 76,471 4.1 1.6 6.9
- ------------------------------------------------------------
Residential energy sales for 2002 experienced a 9.6 percent increase over
the prior year and total retail energy sales grew by 5.5 percent primarily as a
result of warmer summer temperatures and colder winter weather conditions
compared to the previous year.
Although retail sales to industrial customers increased 3.1 percent in 2002,
overall sales to industrial customers remain depressed due to the continuing
effect of sluggish economic conditions.
Retail energy sales in 2001 decreased by 5.2 percent due to milder
temperatures and an economic downturn in the Company's service area. This was
offset by an increase in sales for resale to affiliates. Increased operation of
the Company's combined cycle facilities due to lower natural gas prices and an
increase in the Company's combined cycle capacity contributed to the increase in
sales for resale.
The increase in 2000 retail energy sales was primarily due to the strength
of business and economic conditions in the Company's service area. Residential
energy sales experienced a 6.8 percent increase over the prior year primarily as
a result of warmer summer temperatures and colder winter weather conditions
compared to 1999.
Expenses
Total 2002 operating expenses of $2.7 billion increased by $13 million or 0.5
percent over the previous year. This slight increase is mainly due to a $35
million increase in administrative and general expenses primarily related to
employee salaries, insurance expense and injuries and damages expense, a $19
million increase in production expenses related to boiler plant maintenance, and
II-59
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2002 Annual Report
a $15 million increase in depreciation and amortization expenses due to an
increase in depreciable property. These increases are offset by a $43 million
decrease in purchased power expenses and a $14 million decrease in fuel expenses
related to lower coal prices. Fuel expenses, including purchased power, are
offset by fuel revenues and have no effect on net income.
In 2001 total operating expenses of $2.7 billion were down $50 million or
1.8 percent compared with 2000. This decline is mainly due to an $18 million net
decrease in fuel and purchased power costs related to lower fuel prices,
increased hydro generation and added capacity. The Company also had a $56
million decrease in non-production operation and maintenance expense related to
settlements received in connection with the Company's insurance program, lower
costs related to services provided by the system service company and Southern
Nuclear, and a reduction to the natural disaster reserve accrual. These
decreases in expense were partially offset by a $19 million increase in
depreciation and amortization due to an increase in depreciable property.
Total operating expenses of $2.7 billion in 2000 were up $235 million or 9.4
percent compared with the prior year. This increase was mainly due to a $183
million increase in fuel and purchased power costs as a result of warmer summer
temperatures and colder winter weather conditions compared to 1999, accompanied
by a $23 million increase in maintenance expenses related to overhead line
clearing.
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:
------------------------
2002 2001 2000
------------------------
Total generation
(billions of KWHs) 71 68 65
Sources of generation
(percent) --
Coal 62 64 72
Nuclear 19 18 19
Hydro 6 6 3
Gas 13 12 6
Average cost of fuel per net
KWH generated
(cents) -- 1.47 1.56 1.54
- ------------------------------------------------------------
In 2002, total fuel and purchased power expenses of $1.2 billion decreased
$75 million (5.8 percent) due primarily to lower average fuel cost, while total
energy sales increased 3,012 million kilowatt hours (4.1 percent) compared with
the amounts recorded in 2001. Fuel and purchased power expenses in 2001
decreased $18 million (1.4 percent) compared to 2000 because of milder
temperatures in 2001. Fuel and purchased power expenses increased $183 million
(16 percent) in 2000 compared to 1999 because of hotter-than-normal summer
weather in 2000.
Purchased power consists of purchases from affiliates in the Southern
electric system and non-affiliated companies. 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. During 2002 purchased power transactions from
non-affiliates decreased $54 million (37 percent) due to the addition in May
2001 of a combined cycle unit which generated 6.1 billion kilowatt hours in
2002, an 18.4 percent increase over the previous year. Purchased power
transactions from non-affiliates also declined in 2001 because of the addition
of the combined cycle unit and an increase in hydro generation resulting in a
$20 million (12 percent) decline from the year 2000.
Depreciation and amortization expense increased 3.9 percent in 2002, 5.2
percent in 2001, and 4.9 percent in 2000. These increases reflect additions to
property, plant, and equipment.
Allowance for Funds Used During Construction (AFUDC) increased $4 million
(57.5 percent) in 2002 due to an increase in the amount of construction work in
progress over the prior year. AFUDC decreased $16 million (68.9 percent) in 2001
due to completion of construction of Plant Barry Unit 7 and placing it in
service in May 2001. In 2000, AFUDC increased $11 million (94.6 percent) as a
result of this construction.
Interest expense decreased $26 million (9.9 percent) in 2002. The decrease
reflects a decrease in interest on long-term debt due to refinancing activities.
Interest expense increased $3 million (1.1 percent) in 2001 compared to 2000. In
2000 interest expense was relatively flat when compared to the previous year.
II-60
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2002 Annual Report
Effects of Inflation
The Company is subject to rate regulation that is based on the recovery of
historical costs. In addition, the income tax laws are also based on 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 in the
Company's approved electric rates.
Future Earnings Potential
General
The results of continuing operations for the past three years are not
necessarily indicative of future earnings potential. The level of future
earnings depends on numerous factors. The major factor is the ability of the
Company to achieve energy sales growth while containing costs and maintaining a
stable regulatory environment. Growth in energy sales 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.
Assuming normal weather, sales to retail customers are projected to grow
approximately 1.8 percent annually on average during 2003 through 2007.
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 Alabama Public Service Commission (APSC) under
cost-based regulatory principles.
Rates for the Company can be adjusted periodically within certain
limitations based on earned retail rate of return compared with an allowed
return. Increases in retail rates of 2 percent were effective in April 2002 and
October 2001 in accordance with the Rate Stabilization Equalization plan. See
Note 3 to the financial statements under "Retail Rate Adjustment Procedures" for
additional information.
The rates also provide for adjustments to recognize the placing of new
generating facilities into retail service under Rate CNP (Certificated New
Plant). Effective July 2001, the Company's retail rates were adjusted by 0.6
percent under Rate CNP to recover costs for Plant Barry Unit 7, which was placed
into commercial operation on May 1, 2001.
In April 2000, the APSC approved an amendment to the Company's existing rate
structure to provide for the recovery of retail costs associated with certified
purchased power agreements. In November 2000, the APSC certified a seven-year
purchased power agreement pertaining to a 615 megawatt wholesale generating
facility under construction in Autaugaville, Alabama (Plant Harris), which was
sold to Southern Power in June 2001. All of the 615 megawatts are scheduled to
be available beginning in June 2003. In addition, the APSC certified a
seven-year purchase power agreement with a third party for approximately 630
megawatts; one half of the capacity will be available beginning in 2003, while
the remaining half is scheduled to be available beginning in 2004. Rate CNP will
adjust retail rates one month after the contracted capacity delivery is
scheduled to begin.
In accordance with Financial Accounting Standards Board (FASB) Statement No.
87, Employers' Accounting for Pensions, the Company recorded non-cash pre-tax
pension income of approximately $56 million in 2002. Future pension income is
dependent on several factors including trust earnings and changes to the plan.
Current estimates indicate a reversal of recording pension income to recording
pension expense by as early as 2007. Postretirement benefit costs for the
Company were $23 million in 2002 and are expected to continue to trend upward. A
portion of pension income is capitalized based on construction related labor
charges. For the Company, pension income and postretirement benefits are a
component of the regulated rates and do not have a significant effect on net
income. For more information see Note 2 to the financial statements.
Proposed nuclear security legislation is expected to be introduced in the
108th Congress. The Nuclear Regulatory Commission is also considering additional
security measures for licensees that could require immediate implementation. Any
such requirements could have a significant impact on the Company's nuclear power
II-61
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2002 Annual Report
plant and result in increased operation and maintenance expenses as well as
additional capital expenditures. The impact of any new requirements would depend
upon the development and implementation of the regulations.
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."
Industry Restructuring
The electric utility industry in the United States is continuing to evolve 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 power plants for a utility's large industrial and/or commercial
customers where retail access is allowed and to sell excess energy to other
utilities. Also, electricity sales for resale rates were affected by numerous
new energy suppliers, including power marketers and brokers.
This past year, merchant energy companies and traditional electric utilities
with significant energy marketing and trading activities came under severe
financial pressures. Many of these companies have completely exited or
drastically reduced all energy marketing and trading activities and sold foreign
and domestic electric infrastructure assets. The Company has not experienced any
material financial impact regarding its limited energy trading operations
through SCS and recent generating capacity additions.
Although the Energy Act does not provide for retail customer access, it was a
major catalyst for the recent restructuring and consolidation taking place
within the utility industry. Numerous federal and state initiatives that promote
wholesale and retail competition are in varying stages. Among other things,
these initiatives allow retail customers in some states to choose their
electricity provider. 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 discussed in
Alabama, none have been enacted. In October 2000, the APSC completed a two-year
study of electric industry restructuring, concluding that (i) restructuring of
the electric utility industry in Alabama was not in the public interest and (ii)
the APSC itself would not mandate retail competition or electric industry
restructuring without enabling state legislation. Electric utility restructuring
would require numerous issues to be resolved, including significant ones
relating to recovery of any stranded investments, full cost recovery of energy
produced, and other issues related to the energy crisis that occurred in
California.
Continuing to be a low-cost producer could provide opportunities to increase
market share and profitability in markets that evolve with changing regulation
and competition. 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.
FERC Matters
In December 1999, the Federal Energy Regulatory Commission (FERC) issued its
final ruling on Regional Transmission Organizations (RTOs). The order encouraged
utilities owning transmission systems to form RTOs on a voluntary basis.
Southern Company and its operating companies, including the Company, have
submitted a series of status reports informing the FERC of progress toward the
development of a Southeastern RTO. In these status reports, Southern Company
explained that it is developing a for-profit RTO known as SeTrans with a number
of non-jurisdictional cooperative and public power entities. In 2001, Entergy
Corporation and Cleco Power joined the SeTrans development process. In 2002, the
sponsors of SeTrans established a Stakeholder Advisory Committee, which will
participate in the development of the RTO, and held public meetings to discuss
the SeTrans proposal. On October 10, 2002, the FERC granted Southern Company's
and other SeTrans' sponsors petition for a declaratory order regarding the
governance structure and the selection process for the Independent System
Administrator (ISA) of the SeTrans RTO. The FERC also provided guidance on other
II-62
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2002 Annual Report
issues identified in the petition. The SeTrans sponsors announced the selection
of ESB International, Ltd. (ESBI) to be the preferred ISA candidate. Should
negotiations with this candidate successfully conclude with final agreement
among the parties, the SeTrans sponsors intend to seek any state and federal
regulatory or other approvals necessary for formation of the SeTrans RTO and the
approval of ESBI to serve in the capacity of the SeTrans ISA. The creation of
SeTrans is not expected to have a material impact on the Company's financial
statements; however, the outcome of this matter cannot now be determined.
In July 2002, the FERC issued a notice of proposed rulemaking regarding open
access transmission service and standard electricity market design. The
proposal, if adopted, would among other things: (1) require transmission assets
of jurisdictional utilities to be operated by an independent entity; (2)
establish a standard market design; (3) establish a single type of transmission
service that applies to all customers; (4) assert jurisdiction over the
transmission component of bundled retail service; (5) establish a generation
reserve margin; (6) establish bid caps for a day ahead and spot energy markets;
and (7) revise the FERC policy on the pricing of transmission expansions.
Comments on certain aspects of the proposal have been submitted by Southern
Company and the Company. Any impact of this proposal on the Company will depend
on the form in which final rules may be ultimately adopted; however, the
Company's revenues, expenses, assets, and liabilities could be adversely
affected by changes in the transmission regulatory structure in its regional
power market.
In 2002, the Company initiated the relicensing process for the Company's
seven hydroelectric projects on the Coosa River (Weiss, Henry, Logan Martin,
Lay, Mitchell, Jordan, and Bouldin) and the Smith and Bankhead Projects on the
Warrior River. The FERC licenses for all of these nine projects expire in 2007.
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. The FERC may grant
relicenses subject to certain requirements that could result in additional costs
to the Company.
Accounting Policies
Critical Policy
The Company's significant accounting policies are described in Note 1 to the
financial statements. The Company's only critical accounting policy involves
rate regulation. 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 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.
New Accounting Standards
Derivatives
- -----------
Effective January 2001, the Company adopted FASB Statement No. 133, Accounting
for Derivative Instruments and Hedging Activities, as amended. In October 2002,
the Emerging Issues Task Force (EITF) of the FASB announced accounting changes
related to energy trading contracts in Issue No. 02-03. In October 2002, the
Company prospectively adopted the EITF's requirements to reflect the impact of
certain energy trading contracts on a net basis. This change had no material
impact on the Company's income statement. Another change also required certain
energy trading contracts to be accounted for on an accrual basis effective
January 2003. This change had no impact on the Company's current accounting
treatment.
Asset Retirement Obligations
- ----------------------------
Prior to January 2003, the Company accrued for the ultimate cost of retiring
most long-lived assets over the life of the related asset through depreciation
expense. FASB Statement No. 143, Accounting for Asset Retirement Obligations,
establishes new accounting and reporting standards for legal obligations
associated with the ultimate cost of retiring long-lived assets. The present
value of the ultimate costs for an asset's future retirement must be recorded in
the period in which the liability is incurred. The cost must be capitalized as
part of the related long-lived asset and depreciated over the asset's useful
life. Additionally, Statement No. 143 does not permit non-regulated companies to
II-63
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2002 Annual Report
continue accruing future retirement costs for long-lived assets that they do not
have a legal obligation to retire. For more information regarding the impact of
adopting this standard effective January 1, 2003, see Note 1 to the financial
statements under "Regulatory Assets and Liabilities" and "Depreciation and
Nuclear Decommissioning."
Guarantees
- ----------
In 2002, the FASB issued Interpretation No. 45, Accounting and Disclosure
Requirements for Guarantees. This interpretation requires disclosure of certain
direct and indirect guarantees as reflected in Note 8 to the financial
statements under "Guarantees." Also, the interpretation requires recognition of
a liability at inception for certain new or modified guarantees issued after
December 31, 2002. The adoption of Interpretation No. 45 in January 2003 did not
have a material impact on the Company's financial statements.
FINANCIAL CONDITION
Overview
Over the last several years the Company's financial condition has remained
stable with emphasis on cost control measures combined with significantly lower
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 $635 million in 2002. 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.
Credit Rating Risk
The Company does not have any credit agreements that would require material
changes in payment schedules or terminations as a result of a credit rating
downgrade.
Exposure to Market Risk
The Company is exposed to market risks, including changes in interest 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. Company policy is that derivatives are to be used primarily
for hedging purposes. Derivative positions are monitored using techniques that
include market valuation and sensitivity analysis.
The weighted average interest rate on variable long-term debt outstanding at
December 31, 2002 was 1.64%. If the Company sustained a 100 basis point change
in interest rates for all variable long-term debt, the change would affect
annualized interest expense by $10.5 million. To further mitigate the Company's
exposure to interest rates, it has entered into interest rate swaps that were
designed as cash flow hedges of variable rate debt or anticipated debt
issuances. See Note 1 and Note 7 to the financial statements under "Financial
Instruments" for additional information. The Company is not aware of any facts
or circumstances that would significantly affect such exposures in the near
term.
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.
In addition, in October 2001, the APSC approved a revision to the Company's
Rate ECR (Energy Cost Recovery) allowing the recovery of specific costs
associated with the sales of natural gas that become necessary due to operating
considerations at its electric generating facilities. This revision also
includes the cost of financial instruments used for hedging market price risk up
to 75 percent of the budgeted annual amount of natural gas purchases. The
Company may not engage in natural gas hedging activities that extend beyond a
rolling 42-month window. Also, the premiums paid for natural gas financial
options may not exceed 5 percent of the Company's natural gas budget for that
year.
At December 31, 2002, exposure from these activities was not material to the
Company's financial position, results of operations, or cash flows. The changes
in fair value of derivative energy contracts and year-end valuations were as
follows:
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2002 Annual Report
Changes in Fair Value
- ---------------------------------------------------------------
2002 2001
- ---------------------------------------------------------------
(in thousands)
Contracts beginning of year $ 214 $ 567
Contracts realized or settled (21,088) (509)
New contracts at inception - -
Changes in valuation techniques - -
Current period changes 42,276 156
- --------------------------------------------------------------
Contracts end of year $ 21,402 $ 214
==============================================================
Source of Year-End
Valuation Prices
----------------------------------
Maturity
Total -------------------
Fair Value Year 1 1-3 Years
- -----------------------------------------------------------------
(in thousands)
- -----------------------------------------------------------------
Actively quoted $21,402 $26,462 $(5,060)
External sources - - -
Models and other
methods - - -
- -----------------------------------------------------------------
Contracts end of Year $21,402 $26,462 $(5,060)
=================================================================
Unrealized gains and losses from mark to market adjustments on contracts
related to the retail fuel hedging programs are recorded as regulatory assets
and liabilities. Realized gains and losses from these programs are included in
fuel expense and are recovered through the Company's fuel cost recovery clause.
Gains and losses on contracts that do not represent hedges are recognized in the
Statements of Income as incurred. At December 31, 2002, the fair value of
derivative energy contracts reflected in the financial statements was as
follows:
Amounts
- ----------------------------------------------------------
(in millions)
Regulatory liabilities, net $21.3
Other comprehensive income -
Net income 0.1
- -------------------------------------------------------
Total fair value $21.4
=======================================================
For the years ended December 31, 2002 and 2001, approximately $(2.0) million
and $2.0 million, respectively, of gains (losses) were recognized in income.
Financing Activities
In 2002, the Company's financing costs decreased due to lower interest rates
despite the issuance of new debt during the year. New issues during 2000 through
2002 totaled $2.0 billion and retirement or repayment of higher-cost securities
totaled $1.5 billion.
Composite financing rates for long-term debt, preferred stock, and
preferred securities for the years 2000 through 2002, as of year-end, were as
follows:
2002 2001 2000
- ---------------------------------------------------------------
Long-term debt interest
rate 5.05% 5.72% 6.60%
Preferred stock dividend
rate 5.17 4.79 5.18
Preferred securities
dividend rate 5.25 6.96 7.38
- ---------------------------------------------------------------
The Company's current liabilities exceed current assets because of
securities due within one year. The Company intends to refinance debt that comes
due during 2003. Subsequent to December 31, 2002, the Company has refinanced
$167 million of securities classified as current on the Balance Sheet with
long-term securities. An additional $250 million of securities has been issued
to retire long-term debt and for other corporate purposes.
Capital Structure
The Company's ratio of common equity to total capitalization -- including
short-term debt -- was 42.6 percent in 2002, 42.8 percent in 2001, and 42.2
percent in 2000. See Note 7 to the financial statements under "Capitalization"
for additional information.
Capital Requirements for Construction
Capital expenditures are estimated to be $643 million for 2003, $787 million for
2004, and $948 million for 2005. Over the next three years the Company estimates
spending $485 million on environmental related additions including $355 million
on Selective Catalytic Reduction facilities, $164 million on Plant Farley
including $43 million on replacing reactor vessel heads, $620 million on
distribution facilities, and $569 million on transmission additions. See Note 8
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; FERC rules and transmission 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.
II-65
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2002 Annual Report
Other Capital Requirements
In addition to the funds required for the Company's construction program,
approximately $1.9 billion will be required by the end of 2005 for maturities of
long-term debt. The Company 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.
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. Annual provisions for nuclear decommissioning are based
on an annuity method as approved by the APSC. The amount expensed in 2002 was
$18 million. For additional information concerning nuclear decommissioning
costs, see Note 1 to the financial statements under "Depreciation and Nuclear
Decommissioning."
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, see Note 2 to
the financial statements under "Postretirement Benefits."
These capital requirements, lease obligations, purchase commitments, and
trust requirements - discussed above and in the financial statements - are
summarized as follows:
2003 2004 2005
---------------------------------------------------------------
(in millions)
Construction expenditures $ 643.0 $787.0 $948.0
Senior Notes 1,117.0 525.0 225.0
Leases -
Capital 0.9 1.0 0.5
Operating 28.2 27.2 23.4
Purchase commitments -
Fuel 757.7 768.1 522.6
Purchased Power 53.0 83.0 86.0
Long-term service
agreements 25.7 15.2 14.3
Trusts -
Nuclear decommissioning 20.3 20.3 20.3
Postretirement benefits 5.1 4.9 24.2
- ----------------------------------------------------------------
Sources of Capital
The Company plans 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, the Company has various
internal and external sources of liquidity. At the beginning of 2003, the
Company had approximately $23 million of cash and cash equivalents and $923
million of unused credit arrangements with banks. In addition, the Company has
substantial cash flow from operating activities and access to the capital
markets to meet liquidity needs. Cash flows from operating activities were $951
million in 2002, $838 million in 2001, and $827 million in 2000. Credit
arrangements are as follows:
Expires
----------------------------
Total Unused 2003 2004
- -----------------------------------------------------------
(in millions)
$923 $923 $533 $390
- -----------------------------------------------------------
Approximately $361 million of the credit facilities expiring in 2003 allow
for the execution of term loans for an additional two-year period. See Note 7 to
the financial statements under "Bank Credit Arrangements" for additional
information.
The Company may also meet short-term cash needs through a Southern Company
subsidiary organized to issue and sell commercial paper at the request and for
the benefit of the Company and the other Southern Company operating companies.
At December 31, 2002, the Company had outstanding $37 million of commercial
paper.
Environmental Matters
New Source Review Enforcement Actions
In November 1999, the Environmental Protection Agency (EPA) brought a civil
action against the Company in the U.S. District Court in Atlanta, Georgia. The
complaint alleges violations of the 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
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2002 Annual Report
relief, including an order requiring the installation of the best available
control technology at the affected units. The EPA concurrently issued to the
Company a notice of violation 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 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 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 U.S. District Court in Georgia granted Alabama Power's motion to dismiss
for lack of jurisdiction in Georgia. The EPA refiled its claims against Alabama
Power in the U.S. District Court in Alabama. The Company's case has been stayed
since the spring of 2001, pending a ruling by the U.S. Court of Appeals for the
Eleventh Circuit in the appeal of a very similar New Source Review enforcement
action against the Tennessee Valley Authority (TVA). The TVA appeal involves
many of the same legal issues raised by the actions against the Company.
Because the outcome of the TVA appeal could have a significant adverse impact
on the Company, it is a party to that case as well. In February 2003, the
U.S. District Court in Alabama extended the stay of the EPA litigation
proceeding in Alabama until the earlier of May 6, 2003 or a ruling by the U.S.
Court of Appeals for the Eleventh Circuit in the related litigation involving
TVA.
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 in any one of these cases could require
substantial capital expenditures that cannot be determined at this time and
could 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.
Environmental Statutes and Regulations
The Company's operations are subject to extensive regulation by state and
federal environmental agencies under a variety of statutes and regulations
governing environmental media, including air, water, and land resources.
Compliance with these environmental requirements will involve significant costs,
a major portion of which is expected to be recovered through existing ratemaking
provisions. There is no assurance, however, that all such costs will, in fact,
be recovered.
Compliance with the federal Clean Air Act and resulting regulations has been
and will continue to be, a significant focus for the company. The Title IV acid
rain provisions of the Clean Air Act, for example, required significant
reductions in sulfur dioxide and nitrogen oxide emissions. Compliance was
required in two phases -- Phase I, effective in 1995 and Phase II, effective in
2000. Construction expenditures associated with Phase I and Phase II compliance
totaled approximately $88 million.
Some of the expenditures required to comply with the Phase II acid rain
requirements also assisted the Company in complying with nitrogen oxide emission
reduction requirements under Title I of the Clean Air Act, which were designed
to address one-hour ozone nonattainment problems in Birmingham, Alabama. In
December 2000, the Alabama Department of Environmental Management (ADEM) adopted
revisions to the State Implementation Plan for meeting the one-hour ozone
standard. New emission limits to comply with these requirements must be
implemented in May 2003. Two plants in the Birmingham area will be affected.
Construction expenditures for compliance with these new rules are currently
estimated at approximately $270 million, of which $70 million remains to be
spent.
To help bring the remaining nonattainment areas into compliance with the
one-hour ozone standard, in 1998 the EPA issued regional nitrogen oxide
reduction rules. Those rules required 21 states, including Alabama, to reduce
and cap nitrogen oxide emissions from power plants and other large industrial
sources. Affected sources, including five of the Company's coal-fired plants in
Alabama, must comply with the reduction requirements by May 31, 2004. Additional
construction expenditures for compliance with these new rules are currently
estimated at approximately $292 million, of which $287 million remains to be
spent.
In July 1997, the EPA revised the national ambient air quality standards for
ozone and particulate matter. These revisions made the standards significantly
more stringent. In the subsequent litigation of these standards, the U.S.
Supreme Court found the EPA's implementation program for the new ozone standards
II-67
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2002 Annual Report
unlawful and remanded it to the EPA for further rulemaking. The EPA is expected
to propose implementation rules designed to address the court's concerns in 2003
and issue final implementation rules in 2004. The remaining legal challenges to
the new standards, which were pending before the U.S. Court of Appeals, District
of Columbia Circuit, have been resolved.
The EPA plans to designate areas as attainment or nonattainment with the new
eight-hour ozone standard by April 2004, based on air quality data for 2001
through 2003. Several areas within the Company's service area are likely to be
designated nonattainment under the new ozone standard. State implementation
plans, including new emission control regulations necessary to bring those areas
into attainment, could be required as early as 2007. Those state plans could
require further reductions in nitrogen oxide emissions from power plants. If so,
reductions could be required sometime after 2007. The impact of any new
standards will depend on the development and implementation of applicable
regulations.
The EPA currently plans to designate areas as attainment or nonattainment
with the new fine particulate matter standard by the end of 2004. Those area
designations will be based on air quality data collected during 2001 through
2003. Several areas within the Company's service area will likely be designated
nonattainment under the new particulate matter standard. State implementation
plans, including new regulations necessary to bring those areas into attainment
could be required as early as the end of 2007. Those state plans will likely
require reductions in sulfur dioxide emissions from power plants. If so, the
reductions could be required sometime after 2007. Any additional emission
reductions and costs associated with the new fine particulate matter standard
cannot be determined at this time.
The EPA has also announced plans to issue a proposed Regional Transport Rule
for the fine particulate matter standard by the end of 2003 and to finalize the
rule in 2005. This rule would likely require year-round sulfur dioxide and
nitrogen oxide emission reductions from power plants as early as 2010. If
issued, this rule would likely modify other state implementation plan
requirements for attainment of the fine particulate matter standard and the
eight-hour ozone standard. It is not possible at this time to determine the
effect such a rule would have on the Company.
Further reductions in sulfur dioxide could also be required under the EPA's
Regional Haze rules. The Regional Haze rules require states to establish Best
Available Retrofit Technology (BART) standards for certain sources that
contribute to regional haze. The Company has a number of plants that could be
subject to these rules. The EPA regional haze program calls for States to submit
State Implementation Plans in 2007 and 2008 that contain emission reduction
strategies for achieving progress toward the visibility improvement goal. In
2002, however, the U.S. Court of Appeals, District of Columbia Circuit, vacated
and remanded the BART provisions of the federal Regional Haze rules to the EPA
for further rulemaking. Because new BART rules have not been developed and state
visibility assessments are only beginning, it is not possible to determine the
effect of these rules on the company at this time.
The EPA's Compliance Assurance Monitoring (CAM) regulations under Title V of
the Clean Air Act require that monitoring be performed to ensure compliance with
emissions limitations on an ongoing basis. The regulations require certain
facilities with Title V operating permits to develop and submit a CAM plan to
the appropriate permitting authority upon applying for renewal of the facility's
Title V operating permit. The Company is in the process of developing CAM plans,
which could indicate a need for improved particulate matter controls at affected
facilities. Because the plans are still in the early stages of development, the
Company cannot determine the extent to which improved controls could be required
or the costs associated with any necessary improvements. Actual ongoing
monitoring costs are expensed as incurred and are not material for any period
presented.
In December 2000, having completed its utility studies for mercury and other
hazardous air pollutants (HAPS), the EPA issued a determination that an emission
control program for mercury and, perhaps, other HAPS is warranted. The program
is being developed under the Maximum Achievable Control Technology provisions of
the Clean Air Act. The EPA currently plans to issue proposed rules regulating
mercury emissions from electric utility boilers by the end of 2003, and those
regulations are scheduled to be finalized by the end of 2004. Compliance could
be required as early as 2007. Because the rules have not yet been proposed, the
costs associated with compliance cannot be determined at this time.
In December 2002, the EPA issued final and proposed revisions to the New
Source Review program under the Clean Air Act. In February 2003, several
II-68
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2002 Annual Report
northeastern states petitioned the D.C. Circuit Court for a stay of the final
rules. The proposed rules are open to public comment and may be revised before
being finalized by the EPA. If fully implemented, these proposed and final
regulations could affect the applicability of the New Source Review provisions
to activities at the Company's facilities. In any event, any final regulations
must be adopted by the states in the Company's service area in order to apply to
the Company's facilities. The effect of these proposed and final rules cannot be
determined at this time.
Several major bills to amend the Clean Air Act to impose more stringent
emissions limitations have been proposed. Three of these, the Bush
Administration's Clear Skies Act, the Clean Power Act of 2002, and the Clean Air
Planning Act of 2002, proposed to further limit power plant emissions of sulfur
dioxide, nitrogen oxides, and mercury. The latter two bills also proposed to
limit emissions of carbon dioxide. None of these bills were enacted into law in
the last Congress. Similar bills have been, and are anticipated to be,
introduced this year. The Bush Administration's Clear Skies Act was recently
reintroduced, and President Bush has stated that it will be a high priority for
the Administration. Other bills already introduced include the Climate
Stewardship Act of 2003, which proposes capping greenhouse gas emissions. The
cost impacts of such legislation would depend upon the specific requirements
enacted.
Domestic efforts to limit greenhouse gas emissions have been spurred by
international discussions surrounding the Framework Convention on Climate Change
and specifically the Kyoto Protocol, which proposes international constraints on
the emissions of greenhouse gases. The Bush Administration does not support U.S.
ratification of the Kyoto Protocol or other mandatory carbon dioxide reduction
legislation and has instead announced a new voluntary climate initiative which
seeks an 18 percent reduction by 2012 in the rate of greenhouse gas emissions
relative to the dollar value of the U.S. economy. The Company is involved in a
voluntary electric utility industry sector climate change initiative in
partnership with the government. Because this initiative is still under
development, it is not possible to determine the effect on the company at this
time.
The Company must comply with other environmental laws and regulations that
cover the handling and disposal of hazardous waste and releases of hazardous
substances. 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 and will recognize in its financial
statements costs to clean up known sites. The Company may be liable for a
portion or all required cleanup costs for additional sites that may require
environmental remediation. The Company has not incurred any significant cleanup
costs to date.
Under the Clean Water Act, the EPA is developing new rules aimed at reducing
impingement and entrainment of fish and fish larvae at cooling water intake
structures that will require numerous biological studies, and perhaps, retrofits
to some intake structures at existing power plants. The new rule was proposed in
February 2002 and will be finalized by August 2004. The impact of any new
standards will depend on the development and implementation of applicable
regulations.
Also, under the Clean Water Act, the EPA and ADEM are developing total
maximum daily loads (TMDLs) for certain impaired waters. Establishment of
maximum loads by the EPA or ADEM may result in lowering permit limits for
various pollutants and a requirement to take additional measures to control
non-point source pollution (e.g., storm water runoff) at facilities discharging
into waters for which TMDLs are established. Because the effect on the Company
will depend on the actual TMDLs and permit limitations established by the
implementing agency, it is not possible to determine the effect on the Company
at this time.
The EPA and state environmental regulatory agencies are reviewing and
evaluating various other matters including limits on pollutant discharges to
impaired waters, hazardous waste disposal requirements, and other regulatory
matters. The impact of any new standards will depend on the development and
implementation of applicable regulations.
Several major pieces of environmental legislation are periodically 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; the Emergency Planning & Community Right-to-Know Act; and the
Endangered Species Act.
II-69
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2002 Annual Report
Compliance with possible additional federal or state legislation related to
global climate change, electromagnetic fields, and other environmental and
health concerns could also significantly affect the Company. The impact of any
new legislation, or changes to existing legislation, could affect many areas of
the Company's operations. The full impact of any such changes cannot, however,
be determined at this time.
Cautionary Statement Regarding Forward-Looking
Information
The Company's 2002 Annual Report includes forward-looking statements in addition
to historical information. Forward-looking information includes, among other
things, statements concerning projected retail sales growth and scheduled
completion of new generation. In some cases, forward-looking statements can be
identified by terminology such as "may," "will," "could," "should," "expects,"
"plans," "anticipates," "believes," "estimates," "projects," "predicts,"
"potential," or "continue" or the negative of these terms or other comparable
terminology. The Company cautions that there are various important factors that
could cause actual results to differ materially from those indicated in the
forward-looking statements; accordingly, there can be no assurance that such
indicated results will be realized. These factors include the impact of recent
and future federal and state regulatory change, including legislative and
regulatory initiatives regarding deregulation and restructuring of the electric
utility industry, and also changes in environmental and other laws and
regulations to which the Company is subject, as well as changes in application
of existing laws and regulations; current and future litigation, including the
pending EPA civil action against the Company; the effects, extent, and timing of
the entry of additional competition in the markets in which the Company
operates; the impact of fluctuations in commodity prices, interest rates, and
customer demand; state and federal rate regulations; political, legal, and
economic conditions and developments in the United States; internal
restructuring or other restructuring options that may be pursued; the ability of
counterparties of the Company to make payments as and when due; the effects of,
and changes in, economic conditions in the areas in which the Company operates,
including the current soft economy; the direct or indirect effects on the
Company's business resulting from the terrorist incidents on September 11, 2001,
or any similar such incidents or responses to such incidents; financial market
conditions and the results of financing efforts; the timing and acceptance of
the Company's new product and service offerings; the ability of the Company to
obtain additional generating capacity at competitive prices; weather and other
natural phenomena; and other factors discussed elsewhere herein and in other
reports (including the Form 10-K) filed from time to time by the Company with
the Securities and Exchange Commission.
II-70
STATEMENTS OF INCOME
For the Years Ended December 31, 2002, 2001, and 2000
Alabama Power Company 2002 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------------
2002 2001 2000
- -----------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Revenues:
Retail sales $2,951,217 $2,747,673 $2,952,707
Sales for resale --
Non-affiliates 474,291 485,974 461,730
Affiliates 188,163 245,189 166,219
Other revenues 96,862 107,554 86,805
- -----------------------------------------------------------------------------------------------------------------------------------
Total operating revenues 3,710,533 3,586,390 3,667,461
- -----------------------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
Fuel 969,521 1,000,828 963,275
Purchased power --
Non-affiliates 90,998 144,991 164,881
Affiliates 158,121 147,967 184,014
Other 574,979 508,264 538,529
Maintenance 279,406 275,510 301,046
Depreciation and amortization 398,428 383,473 364,618
Taxes other than income taxes 216,919 214,665 209,673
- -----------------------------------------------------------------------------------------------------------------------------------
Total operating expenses 2,688,372 2,675,698 2,726,036
- -----------------------------------------------------------------------------------------------------------------------------------
Operating Income 1,022,161 910,692 941,425
Other Income and (Expense):
Allowance for equity funds used during construction 11,168 7,092 22,769
Interest income 13,991 15,101 16,152
Equity in earnings of unconsolidated subsidiaries 3,399 4,494 3,156
Interest expense, net of amounts capitalized (225,706) (246,436) (235,331)
Distributions on preferred securities of subsidiary (24,599) (24,775) (25,549)
Other income (expense), net (32,184) (15,671) (24,995)
- -----------------------------------------------------------------------------------------------------------------------------------
Total other income and (expense) (253,931) (260,195) (243,798)
- -----------------------------------------------------------------------------------------------------------------------------------
Earnings Before Income Taxes 768,230 650,497 697,627
Income taxes 292,436 248,597 261,555
- -----------------------------------------------------------------------------------------------------------------------------------
Earnings Before Cumulative Effect of 475,794 401,900 436,072
Accounting Change
Cumulative effect of accounting change--
less income taxes of $215 thousand - 353 -
- -----------------------------------------------------------------------------------------------------------------------------------
Net Income 475,794 402,253 436,072
Dividends on Preferred Stock 14,439 15,524 16,156
- -----------------------------------------------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred Stock $ 461,355 $ 386,729 $ 419,916
===================================================================================================================================
The accompanying notes are an integral part of these financial statements.
II-71
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2002, 2001, and 2000
Alabama Power Company 2002 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------------
2002 2001 2000
- -----------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Activities:
Net income $ 475,794 $ 402,253 $ 436,072
Adjustments to reconcile net income
to net cash provided from operating activities --
Depreciation and amortization 465,325 437,490 412,998
Deferred income taxes and investment tax credits, net 48,828 (21,569) 66,166
Pension, postretirement, and other employee benefits (34,464) (58,118) (53,362)
Other, net (50,863) (64,533) 15,659
Changes in certain current assets and liabilities --
Receivables, net (46,458) 88,325 (125,652)
Fossil fuel stock 25,535 (38,663) 23,967
Materials and supplies 3,728 (13,025) (10,662)
Other current assets 6,889 (15,474) (6,613)
Accounts payable 10,587 (83,077) 107,702
Taxes accrued (40,922) 46,187 3,266
Other current liabilities 86,850 158,110 (42,507)
- -----------------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities 950,829 837,906 827,034
- -----------------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (634,559) (635,540) (870,581)
Cost of removal net of salvage (32,105) (37,304) (34,378)
Sales of property - 102,068 -
Other 2,054 2,533 (15,036)
- -----------------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities (664,610) (568,243) (919,995)
- -----------------------------------------------------------------------------------------------------------------------------------
Financing Activities:
Increase (decrease) in notes payable, net 26,994 (271,347) 184,519
Proceeds --
Pollution control bonds - 35,000 -
Senior notes 975,000 442,000 250,000
Preferred securities 300,000 - -
Common stock - 15,642 -
Capital contributions from parent company 49,788 107,313 204,371
Redemptions --
First mortgage bonds (350,000) (138,991) (111,009)
Pollution control bonds - (15,000) -
Senior notes (415,602) (3,179) (5,041)
Other long-term debt (883) (842) (946)
Preferred securities (347,000) - -
Preferred stock (70,000) - -
Payment of preferred stock dividends (14,176) (14,942) (16,110)
Payment of common stock dividends (431,000) (393,900) (417,100)
Other (22,411) (9,908) (951)
- -----------------------------------------------------------------------------------------------------------------------------------
Net cash provided from (used for) financing activities (299,290) (248,154) 87,733
- -----------------------------------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents (13,071) 21,509 (5,228)
Cash and Cash Equivalents at Beginning of Period 35,756 14,247 19,475
- -----------------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ 22,685 $ 35,756 $ 14,247
===================================================================================================================================
Supplemental Cash Flow Information:
Cash paid during the period for --
Interest (net of $6,738, $11,690, and $19,953 capitalized $230,102 $246,316 $237,066
Income taxes (net of refunds) 236,634 223,961 175,303
- -----------------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
II-72
BALANCE SHEETS
At December 31, 2002 and 2001
Alabama Power Company 2002 Annual Report
- -------------------------------------------------------------------------------------------------------------------------
Assets 2002 2001
- -------------------------------------------------------------------------------------------------------------------------
(in thousands)
Current Assets:
Cash and cash equivalents $ 22,685 $ 35,756
Receivables --
Customer accounts receivable 240,052 201,566
Unbilled revenues 89,336 80,419
Under recovered regulatory clause revenues - 83,497
Other accounts and notes receivable 47,535 49,940
Affiliated companies 74,099 72,639
Accumulated provision for uncollectible accounts (4,827) (5,237)
Fossil fuel stock, at average cost 73,742 99,278
Materials and supplies, at average cost 187,596 191,324
Other 110,035 74,640
- -------------------------------------------------------------------------------------------------------------------------
Total current assets 840,253 883,822
- -------------------------------------------------------------------------------------------------------------------------
Property, Plant, and Equipment:
In serv
ice 13,506,170 13,159,560
Less accumulated provision for depreciation 5,543,416 5,309,557
- -------------------------------------------------------------------------------------------------------------------------
7,962,754 7,850,003
Nuclear fuel, at amortized cost 103,088 88,777
Construction work in progress 478,652 357,906
- -------------------------------------------------------------------------------------------------------------------------
Total property, plant, and equipment 8,544,494 8,296,686
- -------------------------------------------------------------------------------------------------------------------------
Other Property and Investments:
Equity investments in unconsolidated subsidiaries 45,553 44,742
Nuclear decommissioning trusts 292,297 317,508
Other 16,477 12,244
- -------------------------------------------------------------------------------------------------------------------------
Total other property and investments 354,327 374,494
- -------------------------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets:
Deferred charges related to income taxes 327,276 334,830
Prepaid pension costs 389,793 329,259
Unamortized debt issuance expense 4,361 8,150
Unamortized premium on reacquired debt 103,819 77,173
Department of Energy assessments 17,144 21,015
Other 104,539 108,031
- -------------------------------------------------------------------------------------------------------------------------
Total deferred charges and other assets 946,932 878,458
- -------------------------------------------------------------------------------------------------------------------------
Total Assets $10,686,006 $10,433,460
=========================================================================================================================
The accompanying notes are an integral part of these financial statements.
II-73
BALANCE SHEETS
At December 31, 2002 and 2001
Alabama Power Company 2002 Annual Report
- ---------------------------------------------------------------------------------------------------------------------------
Liabilities and Stockholder's Equity 2002 2001
- ---------------------------------------------------------------------------------------------------------------------------
(in thousands)
Current Liabilities:
Securities due within one year $ 1,117,945 $ 5,382
Notes payable 36,991 9,996
Accounts payable --
Affiliated 109,790 98,268
Other 150,195 151,705
Customer deposits 44,410 42,124
Taxes accrued --
Income taxes 80,438 113,003
Other 20,561 19,023
Interest accrued 36,344 35,522
Vacation pay accrued 33,901 32,324
Other 114,870 93,589
- ---------------------------------------------------------------------------------------------------------------------------
Total current liabilities 1,745,445 600,936
- ---------------------------------------------------------------------------------------------------------------------------
Long-term debt (See accompanying statements) 2,851,562 3,742,346
- ---------------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 1,436,559 1,387,661
Deferred credits related to income taxes 177,205 202,881
Accumulated deferred investment tax credits 227,270 238,225
Employee benefits provisions 141,149 115,078
Deferred capacity revenues 33,924 40,730
Other 147,640 130,214
- ---------------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 2,163,747 2,114,789
- ---------------------------------------------------------------------------------------------------------------------------
Company obligated mandatorily redeemable preferred
securities of subsidiary trusts holding company junior
subordinated notes (See accompanying statements) 300,000 347,000
- ---------------------------------------------------------------------------------------------------------------------------
Cumulative preferred stock (See accompanying statements) 247,512 317,512
- ---------------------------------------------------------------------------------------------------------------------------
Common stockholder's equity (See accompanying statements) 3,377,740 3,310,877
- ---------------------------------------------------------------------------------------------------------------------------
Total Liabilities and Stockholder's Equity $10,686,006 $10,433,460
===========================================================================================================================
Commitments and Contingent Matters (See notes)
- ---------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
II-74
STATEMENTS OF CAPITALIZATION
At December 31, 2002 and 2001
Alabama Power Company 2002 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------------
2002 2001 2002 2001
- ----------------------------------------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
Long-Term Debt:
First mortgage bonds --
Maturity Interest Rates
-------- -------------
2023 7.30% - 7.75% $ - $350,000
- ---------------------------------------------------------------------------------------------------------------------------------
Total first mortgage bonds - 350,000
- ---------------------------------------------------------------------------------------------------------------------------------
Long-term notes payable --
Variable rate (1.525% at 1/1/03)
due 2003 517,000 167,000
5.35% to 7.85% due 2003 406,200 406,200
4.875% to 7.125% due 2004 525,000 525,000
5.49% due November 1, 2005 225,000 225,000
7.125% due October 1, 2007 200,000 200,000
5.375% due October 1, 2008 160,000 160,000
4.70% to 7.125% due 2010-2048 1,408,800 1,199,402
- ---------------------------------------------------------------------------------------------------------------------------------
Total long-term notes payable 3,442,000 2,882,602
- ---------------------------------------------------------------------------------------------------------------------------------
Other long-term debt --
Pollution control revenue bonds --
Collateralized:
5.50% due 2024 24,400 24,400
Variable rates (1.56% to 1.80% at 1/1/03)
due 2015-2017 89,800 89,800
Non-collateralized:
Variable rates (1.42% to 1.95% at 1/1/03)
due 2021-2031 445,940 445,940
- ---------------------------------------------------------------------------------------------------------------------------------
Total other long-term debt 560,140 560,140
- ---------------------------------------------------------------------------------------------------------------------------------
Capitalized lease obligations 2,439 3,323
- ---------------------------------------------------------------------------------------------------------------------------------
Unamortized debt premium (discount), net (35,072) (48,337)
- ---------------------------------------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
requirement -- $202.1 million) 3,969,507 3,747,728
Less amount due within one year 1,117,945 5,382
- ---------------------------------------------------------------------------------------------------------------------------------
Long-term debt excluding amount due within one year $2,851,562 $3,742,346 42.1% 48.5%
- ----------------------------------------------------------------------------------------------------------------------------------
II-75
STATEMENTS OF CAPITALIZATION (continued)
At December 31, 2002 and 2001
Alabama Power Company 2002 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------------
2002 2001 2002 2001
- -----------------------------------------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
Company Obligated Mandatorily
Redeemable Preferred Securities:
$25 liquidation value --
4.75% $ 100,000 $ -
5.50% 200,000 -
7.375% - 97,000
7.60% - 200,000
Auction rate (3.60% at 1/1/02) - 50,000
- -----------------------------------------------------------------------------------------------------------------------------------
Total (annual distribution requirement -- $15.8 million) 300,000 347,000 4.4 4.5
- -----------------------------------------------------------------------------------------------------------------------------------
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 1/1/02
3.10% to 3.557% - 70,000
- -----------------------------------------------------------------------------------------------------------------------------------
Total (annual dividend requirement -- $12.8 million) 247,512 317,512 3.7 4.1
- -----------------------------------------------------------------------------------------------------------------------------------
Common Stockholder's Equity:
Common stock, par value $40 per share --
Authorized - 6,000,000 shares
Outstanding - 6,000,000 shares
Par value 240,000 240,000
Paid-in capital 1,900,464 1,850,676
Premium on Preferred Stock 99 99
Retained earnings 1,250,594 1,220,102
Accumulated other comprehensive income (loss) (13,417) -
- -----------------------------------------------------------------------------------------------------------------------------------
Total common stockholder's equity 3,377,740 3,310,877 49.8 42.9
- -----------------------------------------------------------------------------------------------------------------------------------
Total Capitalization $6,776,814 $7,717,735 100.0% 100.0%
===================================================================================================================================
The accompanying notes are an integral part of these financial statements.
II-76
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
For the Years Ended December 31, 2002, 2001, and 2000
Alabama Power Company 2002 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------------
Premium on Other
Common Paid-In Preferred Retained Comprehensive
Stock Capital Stock Earnings Income (loss) Total
- -----------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Balance at December 31, 1999 $224,358 $1,538,992 $99 $1,225,414 $ - $2,988,863
Net income after dividends on preferred stock - - - 419,916 - 419,916
Capital contributions from parent company - 204,371 - - - 204,371
Cash dividends on common stock - - - (417,100) - (417,100)
Other - - - (278) - (278)
- -----------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2000 224,358 1,743,363 99 1,227,952 - 3,195,772
Net income after dividends on preferred stock - - - 386,729 - 386,729
Capital contributions from parent company - 107,313 - - - 107,313
Cash dividends on common stock - - - (393,900) - (393,900)
Issuance of common stock 15,642 - - - - 15,642
Other - - - (679) - (679)
- -----------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2001 240,000 1,850,676 99 1,220,102 - 3,310,877
Net income after dividends on preferred stock - - - 461,355 - 461,355
Capital contributions from parent company - 49,788 - - - 49,788
Other comprehensive income (loss) - - - - (13,417) (13,417)
Cash dividends on common stock - - - (431,000) - (431,000)
Other - - - 137 - 137
- -----------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2002 $240,000 $1,900,464 $99 $1,250,594 $(13,417) $3,377,740
===================================================================================================================================
The accompanying notes are an integral part of these financial statements.
STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2002, 2001, and 2000
Alabama Power Company 2002 Annual Report
- --------------------------------------------------------------------------------------------------------------------------------
2002 2001 2000
- --------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Net income after dividends on preferred stock $461,355 $386,729 $419,916
- --------------------------------------------------------------------------------------------------------------------------------
Other comprehensive income (loss):
Change in additional minimum pension liability, net of tax of (4,172) - -
$(2,536)
Changes in fair value of qualifying hedges, net of tax of (9,245) - -
$(5,621)
- --------------------------------------------------------------------------------------------------------------------------------
Total other comprehensive income (loss) (13,417) - -
- --------------------------------------------------------------------------------------------------------------------------------
Comprehensive Income $447,938 $386,729 $419,916
================================================================================================================================
The accompanying notes are an integral part of these financial statements.
II-77
NOTES TO FINANCIAL STATEMENTS
Alabama Power Company 2002 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING
POLICIES
General
Alabama Power Company (the Company) is a wholly owned subsidiary of Southern
Company, which is the parent company of five operating companies, Southern Power
Company (Southern Power), a system service company, Southern Communications
Services (Southern LINC), Southern Company Gas (Southern GAS), Southern Company
Holdings (Southern Holdings), Southern Nuclear Operating Company (Southern
Nuclear), Southern Telecom, and other direct and indirect subsidiaries. The
operating companies -- Alabama Power Company, Georgia Power Company, Gulf Power
Company, Mississippi Power Company, and Savannah Electric and Power Company --
provide electric service in four southeastern states. Southern Power constructs,
owns, and manages Southern Company's competitive generation assets and sells
electricity at market-based rates in the wholesale market. Contracts among the
operating companies and Southern Power -- related to jointly-owned generating
facilities, interconnecting transmission lines, or the exchange of electric
power -- are regulated by the Federal Energy Regulatory Commission (FERC) and/or
the Securities and Exchange Commission. The system service company provides, at
cost, specialized services to Southern Company and its 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 Telecom provides fiber cable services within the Southeast. Southern
GAS, which began operation in August 2002, is a competitive retail natural gas
business serving communities in Georgia. Southern Holdings is an intermediate
holding subsidiary for Southern Company's investments in leveraged leases,
alternative fuel products, and an energy service business. Southern Nuclear
provides services to the operating companys' nuclear power plants.
Southern Company is registered as a holding company under the Public Utility
Holding Company Act of 1935 (PUHCA). Both Southern Company and its subsidiaries
are subject to the regulatory provisions of the PUHCA. The Company is also
subject to regulation by the FERC and the Alabama Public Service Commission
(APSC). The Company follows accounting principles generally accepted in the
United States and complies with the accounting policies and practices prescribed
by its respective regulatory commissions. The preparation of financial
statements in conformity with accounting principles generally accepted in the
United States 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.
Affiliate Transactions
The Company has an agreement with the system service company under which the
following services are rendered to the Company at direct or allocated cost:
general and design engineering, purchasing, accounting and statistical analysis,
finance and treasury, tax, information resources, marketing, auditing, insurance
and pension administration, 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, $183 million, and $187
million during 2002, 2001, and 2000, respectively. Cost allocation methodologies
used by the system service company are approved by the SEC and management
believes they are reasonable.
The Company 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 analysis,
and employee relations; and other services with respect to business and
operations. Costs for these services amounted to $154 million, $160 million, and
$148 million during 2002, 2001, and 2000, respectively.
The Company has an agreement with Mississippi Power under which Mississippi
Power owns a portion of Plant Greene County. The Company operates Plant Greene
County and Mississippi Power reimburses the Company for its proportionate share
of expenses which were $6.4 million in 2002. See Note 4 for additional
information.
In 2001, the Company had under construction a 1,230 megawatt combined cycle
facility in Autaugaville, Alabama (Plant Harris). In June 2001, the Company sold
this project to Southern Power. The Company has entered into an agreement with
Southern Power to operate and maintain Plant Harris and provide fuel at cost
beginning in June 2003.
The operating companies, including the Company, Southern Power, and Southern
GAS may jointly enter into various types of wholesale energy, natural gas and
II-78
NOTES (continued)
Alabama Power Company 2002 Annual Report
certain other contracts, either directly or through the system service company
as agent. Each participating company may be jointly and severally liable for the
obligations incurred under these agreements.
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.
Regulatory assets and (liabilities) reflected in the Balance Sheets at
December 31 relate to the following:
2002 2001
--------------------
(in millions)
Deferred income tax charges $ 327 $ 335
Premium on reacquired debt 104 77
Department of Energy assessments 17 21
Vacation pay 34 32
Deferred income tax credits (177) (203)
Natural disaster reserve (12) (12)
Fuel-hedging assets - 4
Fuel-hedging liabilities (21) (2)
Other regulatory assets 56 55
Other regulatory liabilities (12) (4)
- --------------------------------------------------------------
Total $ 316 $ 303
==============================================================
See "Depreciation and Nuclear Decommissioning" in this note for information
regarding significant regulatory assets and liabilities created as a result of
the January 1, 2003, adoption of FASB Statement No. 143, Accounting for Asset
Retirement Obligations.
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. All regulatory assets
and liabilities are reflected in rates.
Revenues and Fuel Costs
The Company currently operates as a vertically integrated utility providing
electricity to retail customers within its traditional service area located
within the state of Alabama and to wholesale customers in the southeast.
Revenues are recognized as services are rendered. Unbilled revenues are accrued
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, fuel hedging, 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 periods.
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 2002, $58 million in 2001, and $61 million in 2000. 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 fuel storage capacity is available at Plant Farley to maintain
full-core discharge capability until the refueling outage scheduled in 2006 for
Farley Unit 1 and the refueling outage scheduled in 2008 for Farley Unit 2.
Procurement of on-site dry spent fuel storage capacity at Plant Farley is in
progress, with the intent to place the capacity in operation in 2005.
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. The Company estimates its remaining
liability under this law to be approximately $17 million at December 31, 2002.
This obligation is recorded in other deferred credits in the accompanying
Balance Sheets.
II-79
NOTES (continued)
Alabama Power Company 2002 Annual Report
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 2002, 2001, and 2000. When property subject to depreciation is
retired or otherwise disposed of in the normal course of business, its original
cost -- together with the cost of removal, less salvage -- is charged to
accumulated 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. Prior to January 2003, in accordance
with regulatory requirements, the Company followed the industry practice of
accruing for the ultimate cost of retiring most long-lived assets over the life
of the related asset as part of the annual depreciation expense provision.
In January 2003, the Company adopted FASB Statement No. 143, Accounting for
Asset Retirement Obligations. Statement No. 143 establishes new accounting and
reporting standards for legal obligations associated with the ultimate cost of
retiring long-lived assets. The present value of the ultimate costs for an
asset's future retirement must be recorded in the period in which the liability
is incurred. The cost must be capitalized as part of the related long-lived
asset and depreciated over the asset's useful life.
There was no cumulative effect to net income resulting from the adoption of
Statement No. 143. The Company received an accounting order from the APSC to
defer the transition adjustment; therefore, the Company recorded a related
regulatory liability of $71 million to reflect the Company's regulatory
treatment of these costs under Statement No. 71. The initial Statement No. 143
liability the Company recognized was $301 million, of which $310 million was
removed from the accumulated depreciation reserve. The amount capitalized to
property, plant, and equipment was $63 million.
The liability recognized to retire long-lived assets primarily relates to the
Company's nuclear facility, Plant Farley. In addition, the Company has
retirement obligations related to various landfill sites and underground storage
tanks. The Company has also identified retirement obligations related to certain
transmission and distribution facilities, co-generation facilities, certain
wireless communication towers, and certain structures authorized by the United
States Army Corps of Engineers. However, a liability for the removal of these
assets will not be recorded because no reasonable estimate can be made regarding
the timing of any related retirements. The Company will continue to recognize in
the income statement its ultimate removal costs in accordance with its
regulatory treatment. Any difference between costs recognized under Statement
No. 143 and those reflected in rates will be recognized as either a regulatory
asset or liability as ordered by the APSC. It is estimated that this annual
difference will be approximately $4 million. The APSC regulatory order states
that actual asset removal costs will be recoverable in rates.
Statement No. 143 does not permit non-regulated companies to continue
accruing future retirement costs for long-lived assets they do not have a legal
obligation to retire. However, in accordance with the regulatory treatment of
these costs, the Company will continue to recognize the removal costs for these
other obligations in their depreciation rates. As of January 1, 2003, the amount
included in the accumulated depreciation reserve that represents a regulatory
liability for these costs was $550 million.
The Nuclear Regulatory Commission (NRC) requires all licensees operating
commercial nuclear power reactors to establish a plan for providing with
reasonable assurance funds for decommissioning. The Company has established
external trust funds to comply with the NRC's regulations. Amounts previously
recorded in internal reserves are being transferred into the external trust
funds over periods approved by the APSC. The NRC's minimum external funding
requirements are based on a generic estimate of the cost to decommission the
radioactive portions of a nuclear unit based on the size and type of reactor.
The Company has filed plans with the NRC to ensure that -- over time -- the
deposits and earnings of the external trust funds will provide the minimum
funding amounts prescribed by the NRC.
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 costs of decommissioning -- both site study
costs and ultimate costs - based on the most current study for Plant Farley were
as follows:
II-80
NOTES (continued)
Alabama Power Company 2002 Annual Report
Site study 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 2002 and fund balances as of
December 31, 2002 were as follows:
(in millions)
Amount expensed in 2002 $ 18
------------------------------------------------------------
Accumulated provisions:
External trust funds, at fair value $292
Internal reserves 34
------------------------------------------------------------
Total $326
============================================================
All of the Company's decommissioning costs are approved for recovery by the
APSC through the ratemaking process. 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.
The Company has informed the NRC that the Company plans to submit an
application in September 2003 to extend the operating license for Plant Farley
for 20 additional years.
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) and Interest Capitalized
In accordance with regulatory treatment, the Company records AFUDC. AFUDC
represents the estimated debt and equity costs of capital funds that are
necessary to finance the construction of new regulated 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. Interest related to the construction of new facilities not
included in the Company's retail rates is capitalized in accordance with
standard interest capitalization requirements. All current construction costs
should be included in retail rates. The composite rate used to determine the
amount of AFUDC was 8.2 percent in 2002, 7.7 percent in 2001, and 9.6 percent in
2000. AFUDC and interest capitalized, net of income tax, as a percent of net
income after dividends on preferred stock was 3.3 percent in 2002 and 2001, and
8.4 percent in 2000.
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 replacements of property--exclusive of minor items of
property--is capitalized. The cost of maintenance, repairs and replacement of
minor items of property is charged to maintenance expense as incurred or
performed with the exception of nuclear refueling costs, which are recorded in
accordance with specific APSC orders. The Company accrues estimated refueling
costs in advance of the unit's next refueling outage. The refueling cycle is 18
months for each unit. During 2002, the Company accrued $34.4 million to the
nuclear refueling outage reserve and at December 31, the reserve balance was
$9.7 million.
II-81
NOTES (continued)
Alabama Power Company 2002 Annual Report
Impairment of Long-Lived Assets and Intangibles
The Company evaluates long-lived assets for impairment 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
either a specific regulatory disallowance or an estimate of undiscounted future
cash flows attributable to the assets, as compared with 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
the 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 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 accordance with an APSC order, the Company has established a Natural Disaster
Reserve. The Company is allowed to accrue $250 thousand per month until the
maximum accumulated provision of $32 million is attained. Higher accruals to
restore the reserve to its authorized level are allowed whenever the balance in
the reserve declines below $22.4 million. During 2002, the Company accrued $3
million to the reserve and at December 31, the reserve balance was $11.8
million.
Comprehensive Income
Comprehensive income - consisting of net income and changes in the fair value of
qualifying cash flow hedges and changes in additional minimum pension
liabilities, less income taxes and reclassifications for amounts included in net
income - is presented in the financial statements. The objective of
comprehensive income 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. For additional information,
see Note 7.
Stock Options
Southern Company provides non-qualified stock options to a large segment of the
Company's employees ranging from line management to executives. The Company
accounts for its stock-based compensation plans in accordance with Accounting
Principles Board Opinion No. 25. Accordingly, no compensation expense has been
recognized because the exercise price of all options granted equaled the
fair-market value on the date of grant. When options are exercised, the Company
receives a capital contribution from Southern Company equivalent to the related
income tax benefit.
Financial Instruments
The Company uses derivative financial instruments to limit exposure to
fluctuations in interest rates, the prices of certain fuel purchases, and
electricity purchases and sales. All derivative financial instruments are
recognized as either assets or liabilities and are measured at fair value.
Substantially all of the Company's bulk energy purchases and sales contracts are
derivatives. However, in many cases, these contracts qualify as normal purchases
and sales and are accounted for under the accrual method. Other contracts
qualify as cash flow hedges of anticipated transactions. This results in the
deferral of related gains and losses in other comprehensive income or regulatory
assets or liabilities as appropriate until the hedged transactions occur. Any
ineffectiveness is recognized currently in net income. Contracts that do not
qualify for the normal purchase and sale exception and that do not meet the
hedge requirements are marked to market through current period income and are
recorded on a net basis in the Statements of Income.
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.
II-82
NOTES (continued)
Alabama Power Company 2002 Annual Report
Other 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, 2002 $3,967 $4,065
At December 31, 2001 3,744 3,800
Preferred Securities:
At December 31, 2002 300 303
At December 31, 2001 347 346
------------------------------------------------------------
The fair value for long-term debt and preferred securities was based on
either closing market prices or closing prices of comparable instruments.
2. RETIREMENT BENEFITS
The Company has a defined benefit, trusteed, pension plan that covers
substantially all employees. The Company also provides certain non-qualified
benefit plans for a selected group of management and highly-compensated
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
the FERC. In late 2000, as well as in 2002, the Company adopted several pension
and postretirement benefit plan changes that had the effect of increasing
benefits to both current and future retirees.
Plan assets consist primarily of domestic and international equities, global
fixed income securities, real estate, and private equity investments. 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 as follows:
2002 2001 2000
- ---------------------------------------------------------------
Discount 6.50% 7.50% 7.50%
Annual salary increase 4.00 5.00 5.00
Long-term return on plan assets 8.50 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
-------------------------
2002 2001
- -------------------------------------------------------------
(in millions)
Balance at beginning of year $1,011 $ 925
Service cost 26 25
Interest cost 74 70
Benefits paid (61) (56)
Actuarial gain and
employee transfers 16 (1)
Amendments 22 48
- -------------------------------------------------------------
Balance at end of year $1,088 $1,011
=============================================================
Plan Assets
-------------------------
2002 2001
- -------------------------------------------------------------
(in millions)
Balance at beginning of year $1,584 $1,921
Actual return on plan assets (106) (277)
Benefits paid (61) (56)
Employee transfers 2 (4)
- -------------------------------------------------------------
Balance at end of year $1,419 $1,584
=============================================================
The accrued pension costs recognized in the Balance Sheets were as
follows:
2002 2001
- ---------------------------------------------------------------
(in millions)
Funded status $331 $ 573
Unrecognized transition obligation (10) (15)
Unrecognized prior service cost 93 78
Unrecognized net gain (loss) (40) (322)
- ---------------------------------------------------------------
Prepaid asset, net 374 314
Portion included in
benefit obligations 16 15
- ---------------------------------------------------------------
Prepaid asset recognized in the
Balance Sheets $390 $ 329
===============================================================
In 2002 and 2001, amounts recognized in the Balance Sheets for accumulated
other comprehensive income and intangible assets were $6.7 million and $4.8
million, and $0 and $6.3 million, respectively.
II-83
NOTES (continued)
Alabama Power Company 2002 Annual Report
Components of the pension plan's net periodic cost were as follows:
2002 2001 2000
- ---------------------------------------------------------------
(in millions)
Service cost $ 26 $ 25 $ 23
Interest cost 74 70 65
Expected return on plan assets (138) (131) (119)
Recognized net actuarial gain (20) (22) (19)
Net amortization 2 1 (1)
- ---------------------------------------------------------------
Net pension cost (income) $ (56) $ (57) $ (51)
===============================================================
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
------------------------
2002 2001
- ------------------------------------------------------------
(in millions)
Balance at beginning of year $348 $264
Service cost 5 5
Interest cost 26 24
Benefits paid (20) (18)
Actuarial gain and
employee transfers 46 (13)
Amendments - 86
- ------------------------------------------------------------
Balance at end of year $405 $348
============================================================
Plan Assets
------------------------
2002 2001
- -----------------------------------------------------------
(in millions)
Balance at beginning of year $169 $192
Actual return on plan assets (12) (24)
Employer contributions 21 19
Benefits paid (20) (18)
- ------------------------------------------------------------
Balance at end of year $158 $169
============================================================
The accrued postretirement costs recognized in the Balance
Sheets were as follows:
2002 2001
- --------------------------------------------------------------
(in millions)
Funded status $(247) $(179)
Unrecognized transition obligation 41 45
Prior service cost 77 82
Unrecognized net actuarial gain 66 (9)
Fourth quarter contributions 8 8
- --------------------------------------------------------------
Accrued liability recognized in the
Balance Sheets $ (55) $ (53)
==============================================================
Components of the plan's net periodic cost were as follows:
2002 2001 2000
- --------------------------------------------------------------
(in millions)
Service cost $ 5 $ 5 $ 4
Interest cost 25 24 19
Expected return on plan assets (16) (15) (13)
Net amortization 9 7 4
- --------------------------------------------------------------
Net postretirement cost $ 23 $ 21 $ 14
==============================================================
An additional assumption used in measuring the accumulated postretirement
benefit obligations was a weighted average medical care cost trend rate of 8.75
percent for 2002, decreasing gradually to 5.25 percent through the year 2010,
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,
2002 as follows:
1 Percent 1 Percent
Increase Decrease
- -------------------------------------------------------------
(in millions)
Benefit obligation $32 $28
Service and interest costs 3 2
=============================================================
Employee Savings Plan
The Company also sponsors a 401(k) defined contribution plan covering
substantially all employees. The Company provides a 75 percent matching
contribution up to 6 percent of an employee's base salary. Total matching
contributions made to the plan for the years 2002, 2001, and 2000 were $12
million, $12 million, and $11 million, respectively.
Work Force Reduction Programs
The Company has incurred costs for work force reduction programs totaling $13.6
million, $13.0 million and $2.6 million for the years 2002, 2001 and 2000,
respectively. These costs were deferred and are being amortized in accordance
with regulatory treatment over 22 month periods. The unamortized balance of
these costs was $5.1 million at December 31, 2002.
II-84
NOTES (continued)
Alabama Power Company 2002 Annual Report
3. CONTINGENCIES AND REGULATORY
MATTERS
General Litigation Matters
The Company is subject to certain claims and legal actions arising in the
ordinary course of business. The Company's business activities are also subject
to extensive governmental regulation related to public health and the
environment. Litigation over environmental issues and claims of various types,
including property damage, personal injury, and citizen enforcement of
environmental requirements, has increased generally throughout the United
States. In particular, personal injury claims for damages caused by alleged
exposure to hazardous materials have become more frequent.
The ultimate outcome of such litigation currently filed against the Company
cannot be predicted at this time; however, after consultation with legal
counsel, management does not anticipate that the liabilities, if any, arising
from such proceedings would have a material adverse effect on the Company's
financial statements.
Environmental Protection Agency Litigation
In November 1999, the EPA brought a civil action in U.S. District Court in
Georgia against the Company. The complaint alleges violations of the 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
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 Company a notice of violation 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 U.S. District Court in
Georgia granted Alabama Power's motion to dismiss for lack of jurisdiction in
Georgia. The EPA refiled its claims against Alabama Power in U.S. District Court
in Alabama.
The Company's case has been stayed since the spring of 2001, pending a ruling
by the U.S. Court of Appeals for the Eleventh Circuit in the appeal of a very
similar New Source Review enforcement action against the Tennessee Valley
Authority (TVA). The TVA appeal involves many of the same legal issues raised by
the actions against the Company. Because the outcome of the TVA appeal could
have a significant adverse impact on the Company, it is a party to that
case as well. In February 2003, the U.S. District Court in Alabama extended the
stay of the EPA litigation proceeding in Alabama until the earlier of May 6,
2003 or a ruling by the U.S. Court of Appeals for the Eleventh Circuit in the
related litigation involving TVA.
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 if such costs are not recovered through
regulated rates.
Retail Rate Adjustment Procedures
The APSC has adopted rates that provide for periodic adjustments based upon the
Company's earned return on end-of-period retail common equity. Increases in
retail rates of 2 percent were effective in April 2002 and in October 2001 in
accordance with the Rate Stabilization Equalization Plan. In March 2002, the
APSC approved a revision to the rate adjustment procedures that provides for an
annual, rather than quarterly, adjustment and imposes a 3 percent limit on
changes in rates in any calendar year. The return on common equity range of 13.0
percent to 14.5 percent remained unchanged.
The rates also provide for adjustments to recognize the placing of new
generating facilities into retail service under Rate CNP (Certificated New
Plant). Effective July 2001, the Company's retail rates were adjusted by 0.6
percent under Rate CNP to recover costs for Plant Barry Unit 7, which was placed
into commercial operation on May 1, 2001.
In April 2000, the APSC approved an amendment to the Company's existing rate
structure to provide for the recovery of retail costs associated with certified
purchased power agreements. In November 2000, the APSC certified a seven-year
II-85
NOTES (continued)
Alabama Power Company 2002 Annual Report
purchased power agreement pertaining to a 615 megawatt wholesale generating
facility under construction at Plant Harris, which was sold to Southern Power in
June 2001. All of the 615 megawatts are scheduled to be available beginning in
June 2003. In addition, the APSC certified a seven-year purchased power
agreement with a third party for approximately 630 megawatts; one half of the
capacity will be available beginning in 2003 while the remaining half is
scheduled to be available beginning in 2004. Rate CNP will adjust retail rates
one month after the contracted capacity delivery is scheduled to begin.
In October 2001, the APSC approved a revision to the Company's Rate ECR
(Energy Cost Recovery) allowing the recovery of specific costs associated with
the sales of natural gas that become necessary due to operating considerations
at its electric generating facilities. This revision also includes the cost of
financial tools used for hedging market price risk up to 75 percent of the
budgeted annual amount of natural gas purchases. The Company may not engage in
natural gas hedging activities that extend beyond a rolling 42-month window.
Also, the premiums paid for natural gas financial options may not exceed 5
percent of the Company's natural gas budget for that year.
The Company's ratemaking procedures will remain in effect until the APSC
votes to modify or discontinue them.
4. JOINT OWNERSHIP AGREEMENTS
The Company and Georgia Power own equally all of the outstanding capital stock
of Southern Electric Generating Company (SEGCO), which owns electric generating
units with a total rated capacity of 1,020 megawatts, together with associated
transmission facilities. The capacity of these units is sold equally to the
Company and Georgia Power 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 $84 million in 2002, $80 million in 2001, and $85
million in 2000 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 has agreed to reimburse the Company for the pro rata portion of such
obligation corresponding to its then proportionate ownership of stock of SEGCO
if the Company is called upon to make such payment under its guaranty.
At December 31, 2002, the capitalization of SEGCO consisted of $59 million
of equity and $92 million of debt on which the annual interest requirement is
$2.2 million. SEGCO paid dividends totaling $5.8 million in 2002, $0.7 million
in 2001, and $5.1 million in 2000, of which one-half of each was paid to the
Company. In addition, the Company recognizes 50 percent of SEGCO's net income.
The Company's percentage ownership and investment in jointly-owned
generating plants at December 31, 2002 is as 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 $105 $ 51
Plant Miller
Units 1 and 2 760 341
----------------------------------------------------------
The Company has contracted to operate and maintain the jointly owned
facilities as agent for their co-owners. The Company's proportionate share of
their plant operating expenses is included in the operating expenses in the
Statements of Income.
5. LONG-TERM POWER SALES AGREEMENTS
General
The Company and the other operating companies of Southern Company have entered
into long-term contractual agreements for the sale of capacity to certain
non-affiliated utilities located outside the system's service area. These
II-86
NOTES (continued)
Alabama Power Company 2002 Annual Report
agreements are firm and related to specific generating units. Because the energy
is generally provided at cost under these agreements, profitability is primarily
affected by capacity revenues.
Unit power from Plant Miller is being sold to Florida Power Corporation
(FPC), Florida Power & Light Company (FP&L), and Jacksonville Electric Authority
(JEA). Under these agreements approximately 1,239 megawatts of capacity are
scheduled to be sold annually through the expiration of the contract in 2010.
The Company's capacity revenues from these unit power sales amounted to $119
million in 2002, $125 million in 2001, and $127 million in 2000.
Alabama Municipal Electric Authority (AMEA)
Capacity Contracts
In October 1991, the Company entered into a firm power sales contract with AMEA
entitling AMEA to scheduled amounts of capacity (up to a maximum 80 megawatts)
for a period of 15 years. Under the terms of the contract, the Company received
payments from AMEA representing the net present value of the revenues associated
with the capacity entitlement, discounted at an effective annual rate of 11.19
percent. These payments are being recognized as operating revenues and the
discount is amortized to other interest expense as scheduled capacity is made
available over the terms of the contract.
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, a portion of the bond equal to the
decrease is returned to the Company. At December 31, 2002, $32.6 million of
these bonds was held by the escrow agent under the contract.
6. INCOME TAXES
At December 31, 2002, the Company's tax-related regulatory assets and
liabilities were $327 million and $177 million, respectively. These assets are
attributable to tax benefits flowed through to customers in prior years and to
taxes applicable to capitalized interest. 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:
2002 2001 2000
-------------------------------
(in millions)
Total provision for income taxes:
Federal --
Current $209 $234 $168
Deferred 41 (20) 60
- ---------------------------------------------------------------
250 214 228
- ---------------------------------------------------------------
State --
Current 35 37 27
Deferred 7 (2) 7
- ---------------------------------------------------------------
42 35 34
- ---------------------------------------------------------------
Total $292 $249 $262
===============================================================
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:
2002 2001
---------------
(in millions)
Deferred tax liabilities:
Accelerated depreciation $1,081 $1,034
Property basis differences 381 390
Fuel cost adjustment - 28
Premium on reacquired debt 39 29
Pensions 103 89
Other 38 23
---------------------------------------------------------------
Total 1,642 1,593
- ----------------------------------------------------------------
Deferred tax assets:
Capacity prepayments 11 13
Other deferred costs 13 14
Postretirement benefits 18 21
Unbilled revenue 20 18
Other 87 93
- ----------------------------------------------------------------
Total 149 159
- ----------------------------------------------------------------
Total deferred tax liabilities, net 1,493 1,434
Portion included in current liabilities, net (56) (47)
- ----------------------------------------------------------------
Accumulated deferred income taxes
in the Balance Sheets $1,437 $1,387
================================================================
In accordance with regulatory requirements, 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 2002, 2001, and
2000. At December 31, 2002, all investment tax credits available to reduce
federal income taxes payable had been utilized.
II-87
NOTES (continued)
Alabama Power Company 2002 Annual Report
A reconciliation of the federal statutory income tax rate to the effective
income tax rate is as follows:
2002 2001 2000
------------------------
Federal statutory rate 35.0% 35.0% 35.0%
State income tax,
net of federal deduction 3.5 3.5 3.1
Non-deductible book
depreciation 1.3 1.5 1.4
Differences in prior years'
deferred and current tax rates (1.2) (1.3) (1.3)
Other (0.5) (0.5) (0.7)
- -------------------------------------------------------------
Effective income tax rate 38.1% 38.2% 37.5%
=============================================================
Southern Company files a consolidated federal income tax return. Under a
joint consolidated income tax agreement, each subsidiary's current and deferred
tax expense is computed on a stand-alone basis. In accordance with Internal
Revenue Service regulations, each company is jointly and severally liable for
the tax liability.
7. CAPITALIZATION
Mandatorily Redeemable Preferred Securities
Statutory business trusts formed by the Company, of which the Company owns all
the common securities, have issued mandatorily redeemable flexible trust
preferred securities as follows:
Date of Maturity
Issue Amount Rate* Notes Date
---------------------------------------------------
(millions) (millions)
Trust IV 10/2002 $ 100 4.75% $103 10/2042
Trust V 10/2002 200 5.50 206 10/2042
* Issued at a five year initial fixed rate and a seven year initial fixed rate
for Trust IV and Trust V, respectively, and thereafter, at fixed rates
determined through remarketings for specific periods of varying length or at
floating rates determined by reference to 3-month LIBOR plus 2.91% and 3.10%,
respectively.
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.
The securities issued by Trusts I, II, and III were redeemed in 2002.
Pollution Control Bonds
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 $114.2 million of such pollution control obligations, the Company has
authenticated and delivered to the trustees a like principal amount of first
mortgage bonds as security for its obligations under the installment purchase
agreements. No principal or interest on these first mortgage bonds is payable
unless and until a default occurs on the installment purchase agreements. The
amount of pollution control revenue bonds outstanding was $560 million at
December 31, 2002 and 2001.
Senior Notes
The Company issued a total of $975 million of unsecured senior notes in 2002.
The proceeds of these issues were used to redeem higher cost debt and for other
general corporate purposes.
At December 31, 2002 and 2001, the Company had $3.4 billion and $2.9 billion,
respectively, of senior notes outstanding. These senior notes are subordinate to
all secured debt of the Company which amounted to approximately $302 million at
December 31, 2002.
Capitalized Leases
The estimated aggregate annual maturities of capitalized lease obligations
through 2006 are as follows: $0.9 million in 2003, $1.0 million in 2004, $0.5
million in 2005, and $0.1 million in 2006.
Securities 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:
2002 2001
------------------------
(in thousands)
First mortgage bond maturities
and redemptions $ - $4,498
Other long-term debt maturities
and redemptions 1,117,945 884
--------------------------------------------------------------
Total long-term debt due within
one year $1,117,945 $5,382
==============================================================
II-88
NOTES (continued)
Alabama Power Company 2002 Annual Report
Bank Credit Arrangements
The Company maintains committed lines of credit in the amount of $923 million
(including $454 million of such lines which are dedicated to funding purchase
obligations relating to variable rate pollution control bonds). Of these lines,
$533 million expire at various times during 2003 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. Commitment fees are less than 1/8 of 1 percent for the Company.
Because the arrangements are based on an average balance, the Company does not
consider any of its cash balances to be restricted as of any specific date. An
annual fee is also paid to the agent bank.
Most of the Company's credit arrangements with banks have covenants that
limit the Company's debt to 65 percent of total capitalization. Exceeding this
debt level would result in a default under the credit arrangements. In addition,
the credit arrangements typically contain cross default provisions on other
indebtedness of the Company that would be triggered if the Company defaulted on
other indebtedness above a specified threshold. The Company is currently in
compliance with all such covenants. Borrowings under unused credit arrangements
totaling $74 million would be prohibited if the Company experiences a material
adverse change (as defined in such arrangements).
The Company borrows through commercial paper programs that have the
liquidity support of committed bank credit arrangements. In addition, the
Company borrows from time to time pursuant to arrangements with banks for
uncommitted lines of credit and through extendible commercial note programs. At
December 31, 2002, there were no extendible commercial notes outstanding. The
amount of commercial paper outstanding at December 31, 2002 was $37 million.
At December 31, 2002, the Company had regulatory approval to have
outstanding up to $1 billion of short-term borrowings.
Financial Instruments
The Company enters into interest rate swaps to hedge exposure to interest rate
changes. Swaps related to fixed rate securities are accounted for as fair value
hedges. Swaps related to variable rate securities or forecasted transactions are
accounted for as cash flow hedges. The swaps are generally structured to mirror
the terms of the hedged debt instruments; therefore, no material ineffectiveness
has been recorded in earnings. The gain or loss in fair value for cash flow
hedges is recorded in other comprehensive income and will be recognized in
earnings over the life of the hedged items.
At December 31, 2002, the Company had $1.25 billion notional amount of
interest rate swaps outstanding with net deferred losses of $15 million as
follows:
Cash Flow Hedges
Weighted Average
-----------------------
Variable Fixed Fair
Rate Rate Notional Value
Maturity Received Paid Amount (Loss)
- -------------------------------------------------------------
(in millions)
2003 1.95 3.02 $350 $(5)
2004 1.43 1.63 486 (2)
2003 * 3.05 167 (2)
2003 * 3.96 250 (6)
- -------------------------------------------------------------
*Rate has not been set.
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.
8. COMMITMENTS
Construction Program
The Company's construction program includes significant projects related to
transmission, distribution and generating facilities, including the expenditures
necessary to comply with environmental regulation. The Company currently
estimates property additions to be $643 million in 2003, $787 million in 2004,
and $948 million in 2005.
The capital budget is subject to periodic review and revision, and actual
capital costs incurred may vary from estimates because of numerous factors.
These factors include: changes in business conditions; revised load growth
estimates; changes in environmental regulations; changes in existing nuclear
plants to meet new regulatory requirements; increasing costs of labor,
equipment, and materials; and cost of capital. At December 31, 2002, significant
purchase commitments were outstanding in connection with the construction
program. There can be no assurance that costs related to capital expenditures
will be fully recovered.
II-89
NOTES (continued)
Alabama Power Company 2002 Annual Report
Southern Company has guaranteed Southern Power obligations totaling $6.6
million for the Company's construction of transmission interconnection
facilities to Plant Harris.
Long-Term Service Agreements
The Company has entered into several Long-Term Service Agreements (LTSAs) with
General Electric (GE) for the purpose of securing maintenance support for its
combined cycle and combustion turbine generating facilities. In summary, the
LTSAs stipulate that GE will perform all planned maintenance on the covered
equipment, which includes the cost of all labor and materials. GE is also
obligated to cover the costs of unplanned maintenance on the covered equipment
subject to a limit specified in each contract.
In general, these LTSAs are in effect through two major inspection cycles per
unit. Scheduled payments to GE are made at various intervals based on actual
operating hours of the respective units. Total payments to GE under these
agreements are currently estimated at $253 million over the life of the
agreements, which are approximately 12 to 14 years per unit. However, the LTSAs
contain various cancellation provisions at the option of the Company.
Payments made to GE prior to the performance of any planned maintenance are
recorded as a prepayment in the Balance Sheets. Inspection costs are capitalized
or charged to expense based on the nature of the work performed.
Purchased Power Commitments
The Company has entered into various long-term commitments for the purchase of
electricity. Estimated total long-term obligations at December 31, 2002 were as
follows:
Commitments
-----------------------------------
Non-
Year Affiliated Affiliated Total
- ---- -----------------------------------
(in millions)
2003 $ 37 $ 16 $ 53
2004 49 34 83
2005 49 37 86
2006 49 38 87
2007 49 39 88
2008 and thereafter 111 103 214
- --------------------------------------------------------------
Total commitments $344 $267 $611
==============================================================
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, 2002, were as follows:
Year Commitments
- ---- ----------------
(in millions)
2003 $ 772
2004 782
2005 537
2006 448
2007 453
2008 and thereafter 280
- --------------------------------------------------------------
Total commitments $3,272
==============================================================
In addition, the system service company acts as agent for the five operating
companies, Southern Power, and Southern GAS with regard to natural gas
purchases. Natural gas purchases (in dollars) are based on various indices at
the actual time of delivery; therefore, only the volume commitments are firm.
The Company's committed volumes allocated based on usage projections, as of
December 31, 2002, are as follows:
Year Natural Gas
- ---- -----------
(MMBtu)
2003 91,672,637
2004 53,978,335
2005 20,562,820
2006 12,962,557
2007 4,534,876
- ------------------------------------------------------------
Total commitments 183,711,225
============================================================
Additional commitments for fuel will be required to supply the Company's
future needs.
Acting as an agent for all of Southern Company's operating companies,
Southern Power, and Southern GAS, the system service company may enter into
various types of wholesale energy and natural gas contracts. Under these
agreements, each of the operating companies, Southern Power, and Southern GAS
may be jointly and severally liable for the obligations of each of the operating
companies. Accordingly, the creditworthiness of Southern Power and Southern GAS
is currently inferior to the creditworthiness of the operating companies.
Southern Company has entered into keep-well agreements with each of the
II-90
NOTES (continued)
Alabama Power Company 2002 Annual Report
operating companies to insure they will not subsidize or be responsible for any
costs, losses, liabilities, or damages resulting from the inclusion of Southern
Power or Southern GAS as a contracting party under these agreements.
Operating Leases
The Company has entered into rental agreements for coal rail cars, vehicles, and
other equipment with various terms and expiration dates. These expenses totaled
$29.6 million in 2002, $27.9 million in 2001, and $20.9 million in 2000. Of
these amounts, $19.1 million, $21.1 million, and $20.9 million for 2002, 2001,
and 2000, respectively, relates to the railcar leases and is recoverable through
the Company's energy cost recovery clause. At December 31, 2002, estimated
minimum rental commitments for noncancellable operating leases were as follows:
Vehicles
Year Railcars & Other Total
- --------------------------------------------------------------
(in millions)
2003 $18.6 $ 9.6 $28.2
2004 18.2 9.0 27.2
2005 15.5 7.9 23.4
2006 10.6 5.6 16.2
2007 3.3 2.8 6.1
2008 and thereafter 33.4 4.2 37.6
- --------------------------------------------------------------
Total minimum payments $99.6 $39.1 $138.7
==============================================================
In addition to the rental commitments above, the Company has potential
obligations upon expiration of certain leases with respect to the residual value
of the leased property. These leases expire in 2004 and 2006, and the Company's
maximum obligations are $25.7 million and $66 million, respectively. At the
termination of the leases, at the Company's option, the Company may negotiate an
extension, exercise its purchase option, or the property can be sold to a third
party. The Company expects that the fair market value of the leased property
would substantially reduce or eliminate the Company's payments under the
residual value obligations.
Guarantees
At December 31, 2002, the Company had outstanding guarantees related to SEGCO's
purchase of certain pollution control facilities, as discussed in Note 4, and to
certain residual values of leased assets. See "Operating Leases" above.
9. 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
that could arise from a single nuclear incident. Plant Farley is insured against
this liability to a maximum of $300 million by American Nuclear Insurers (ANI),
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 purchase this coverage, subject to a deductible waiting
period of between 8 to 26 weeks, with a maximum per occurrence per unit limit of
$490 million. After this deductible period, weekly indemnity payments would be
received until either the unit is operational or until the limit is exhausted in
approximately three years. The Company purchases the maximum limit allowed by
NEIL and has elected a 12 week waiting period.
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 $36 million.
Following the terrorist attacks of September 2001, both ANI and NEIL
confirmed that terrorist acts against commercial nuclear power stations would be
covered under their insurance. However, both companies revised their policy
terms on a prospective basis to include an industry aggregate for all terrorist
II-91
NOTES (continued)
Alabama Power Company 2002 Annual Report
acts. The NEIL aggregate, which applies to all claims stemming from terrorism
within a 12 month duration, is $3.24 billion plus any amounts that would be
available through reinsurance or indemnity from an outside source. The ANI cap
is a $300 million shared industry aggregate.
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.
10. QUARTERLY FINANCIAL INFORMATION
(Unaudited)
Summarized quarterly financial data for 2002 and 2001 are as follows:
Net Income
After
Dividends
Quarter Operating Operating on Preferred
Ended Revenues Income Stock
- -------------------- ------------ ----------- -------------
(in millions)
March 2002 $ 802 $191 $ 72
June 2002 924 256 116
September 2002 1,119 393 201
December 2002 865 182 72
March 2001 $ 850 $180 $ 70
June 2001 904 194 75
September 2001 1,061 362 180
December 2001 772 175 62
- ----------------------------------------------------------------
The Company's business is influenced by seasonal weather conditions.
II-92
SELECTED FINANCIAL AND OPERATING DATA 1998-2002
Alabama Power Company 2002 Annual Report
- -------------------------------------------------------------------------------------------------------------------------------
2002 2001 2000 1999 1998
- -------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands) $3,710,533 $3,586,390 $3,667,461 $3,385,474 $3,386,373
Net Income after Dividends
on Preferred Stock (in thousands) $461,355 $386,729 $419,916 $399,880 $377,223
Cash Dividends
on Common Stock (in thousands) $431,000 $393,900 $417,100 $399,600 $367,100
Return on Average Common Equity (percent) 13.80 11.89 13.58 13.85 13.63
Total Assets (in thousands) $10,686,006 $10,433,460 $10,379,108 $9,648,704 $9,225,698
Gross Property Additions (in thousands) $634,559 $635,540 $870,581 $809,044 $610,132
- -------------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $3,377,740 $3,310,877 $3,195,772 $2,988,863 $2,784,067
Preferred stock 247,512 317,512 317,512 317,512 317,512
Company obligated mandatorily
redeemable preferred securities 300,000 347,000 347,000 347,000 297,000
Long-term debt 2,851,562 3,742,346 3,425,527 3,190,378 2,646,566
- -------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $6,776,814 $7,717,735 $7,285,811 $6,843,753 $6,045,145
===============================================================================================================================
Capitalization Ratios (percent):
Common stock equity 49.8 42.9 43.9 43.7 46.1
Preferred stock 3.7 4.1 4.4 4.6 5.3
Company obligated mandatorily
redeemable preferred securities 4.4 4.5 4.8 5.1 4.9
Long-term debt 42.1 48.5 46.9 46.6 43.7
- -------------------------------------------------------------------------------------------------------------------------------
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+
Fitch A+ A+ AA- AA- AA-
Preferred Stock -
Moody's Baa1 Baa1 a2 a2 a2
Standard and Poor's BBB+ BBB+ BBB+ A- A
Fitch 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
Fitch A A A+ A+ A+
===============================================================================================================================
Customers (year-end):
Residential 1,148,645 1,139,542 1,132,410 1,120,574 1,106,217
Commercial 203,017 196,617 193,106 188,368 182,738
Industrial 4,874 4,728 4,819 4,897 5,020
Other 789 751 745 735 733
- -------------------------------------------------------------------------------------------------------------------------------
Total 1,357,325 1,341,638 1,331,080 1,314,574 1,294,708
===============================================================================================================================
Employees (year-end): 6,715 6,706 6,871 6,792 6,631
- -------------------------------------------------------------------------------------------------------------------------------
II-93
SELECTED FINANCIAL AND OPERATING DATA 1998-2002 (continued)
Alabama Power Company 2002 Annual Report
- ------------------------------------------------------------------------------------------------------------------------------
2002 2001 2000 1999 1998
- ------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $1,264,431 $1,138,499 $1,222,509 $1,145,646 $1,133,435
Commercial 882,669 829,760 854,695 807,098 779,169
Industrial 788,037 763,934 859,668 843,090 853,550
Other 16,080 15,480 15,835 15,283 14,523
- ------------------------------------------------------------------------------------------------------------------------------
Total retail 2,951,217 2,747,673 2,952,707 2,811,117 2,780,677
Sales for resale - non-affiliates 474,291 485,974 461,730 415,377 448,973
Sales for resale - affiliates 188,163 245,189 166,219 92,439 103,562
- ------------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 3,613,671 3,478,836 3,580,656 3,318,933 3,333,212
Other revenues 96,862 107,554 86,805 66,541 53,161
- ------------------------------------------------------------------------------------------------------------------------------
Total $3,710,533 $3,586,390 $3,667,461 $3,385,474 $3,386,373
==============================================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 17,402,645 15,880,971 16,771,821 15,699,081 15,794,543
Commercial 13,362,631 12,798,711 12,988,728 12,314,085 11,904,509
Industrial 21,102,568 20,460,022 22,101,407 21,942,889 21,585,117
Other 205,346 198,102 205,827 201,149 196,647
- ------------------------------------------------------------------------------------------------------------------------------
Total retail 52,073,190 49,337,806 52,067,783 50,157,204 49,480,816
Sales for resale - non-affiliates 15,553,545 15,277,839 14,847,533 12,437,599 11,840,910
Sales for resale - affiliates 8,844,050 8,843,094 5,369,474 5,031,781 5,976,099
- ------------------------------------------------------------------------------------------------------------------------------
Total 76,470,785 73,458,739 72,284,790 67,626,584 67,297,825
==============================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 7.27 7.17 7.29 7.30 7.18
Commercial 6.61 6.48 6.58 6.55 6.55
Industrial 3.73 3.73 3.89 3.84 3.95
Total retail 5.67 5.57 5.67 5.60 5.62
Sales for resale 2.72 3.03 3.11 2.91 3.10
Total sales 4.73 4.74 4.95 4.91 4.95
Residential Average Annual
Kilowatt-Hour Use Per Customer 15,198 13,981 14,875 14,097 14,370
Residential Average Annual
Revenue Per Customer $1,104.28 $1,002.30 $1,084.26 $1,028.76 $1,031.21
Plant Nameplate Capacity
Ratings (year-end) (megawatts) 12,153 12,153 12,122 11,379 11,151
Maximum Peak-Hour Demand (megawatts):
Winter 9,423 9,300 9,478 8,863 7,757
Summer 10,910 10,241 11,019 10,739 10,329
Annual Load Factor (percent) 62.9 62.5 59.3 59.7 62.9
Plant Availability (percent):
Fossil-steam 85.8 87.1 89.4 80.4 85.6
Nuclear 93.2 83.7 88.3 91.0 80.2
- ------------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 55.5 56.8 63.0 64.1 65.3
Nuclear 17.1 15.8 16.9 17.8 16.3
Hydro 5.1 5.1 2.9 4.7 6.9
Gas 11.6 10.7 4.9 1.1 1.5
Purchased power -
From non-affiliates 4.0 4.4 4.6 4.5 3.3
From affiliates 6.7 7.2 7.7 7.8 6.7
- ------------------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0 100.0 100.0
==============================================================================================================================
II-94
GEORGIA POWER COMPANY
FINANCIAL SECTION
II-95
MANAGEMENT'S REPORT
Georgia Power Company 2002 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 accounting principles generally
accepted in the United States 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 accounting 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.
Southern Company's audit committee of its board of directors, composed of
five independent directors, provides a broad overview of management's financial
reporting and control functions. Additionally, a committee of Georgia Power's
board of directors, composed of a minimum of three outside directors, meets
periodically with management, the internal auditors, and the independent public
accountants to discuss auditing, internal controls, and compliance matters. The
internal auditors and independent public accountants have access to the members
of these committees 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 accounting principles generally
accepted in the United States.
/s/David M. Ratcliffe
David M. Ratcliffe
President and Chief Executive Officer
/s/Allen L. Leverett
Allen L. Leverett
Executive Vice President, Treasurer
and Chief Financial Officer
February 17, 2003
II-96
INDEPENDENT AUDITORS' REPORT
Georgia Power Company:
We have audited the accompanying balance sheet and statement of capitalization
of Georgia Power Company (a wholly owned subsidiary of Southern Company) as of
December 31, 2002, and the related statements of income, comprehensive income,
common stockholder's equity, and cash flows for the year then ended. These
financial statements are the responsibility of Georgia Power's management. Our
responsibility is to express an opinion on these financial statements based on
our audit. The financial statements of Georgia Power as of December 31, 2001,
and for each of the two years then ended were audited by other auditors who
have ceased operations. Those auditors expressed an unqualified opinion on
those consolidated financial statements and included an explanatory paragraph
that described a change in the method of accounting for derivative instruments
and hedging activities in their report dated February 13, 2002.
We conducted our audit in accordance with auditing standards generally
accepted in the United States of America. 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 audit provides a
reasonable basis for our opinion.
In our opinion, the 2002 financial statements (pages II-111 to II-133)
present fairly, in all material respects, the financial position of Georgia
Power Company at December 31, 2002, and the results of its operations and its
cash flows for the year then ended, in conformity with accounting principles
generally accepted in the United States of America.
/s/Deloitte & Touche LLP
Atlanta, Georgia
February 17, 2003
THE FOLLOWING REPORT OF INDEPENDENT ACCOUNTANTS IS A COPY OF THE REPORT
PREVIOUSLY ISSUED IN CONNECTION WITH THE COMPANY'S 2001 ANNUAL REPORT
ON FORM 10-K AND HAS NOT BEEN REISSUED BY ARTHUR ANDERSEN LLP. SEE EXHIBIT
23(c)2 FOR ADDITIONAL INFORMATION.
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, 2001 and 2000, and the related statements
of income, comprehensive income, common stockholder's equity, and cash flows for
each of the three years in the period ended December 31, 2001. 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-93 through II-113)
referred to above present fairly, in all material respects, the financial
position of Georgia Power Company as of December 31, 2001 and 2000, and the
results of its operations and its cash flows for each of the three years in the
period ended December 31, 2001, in conformity with accounting principles
generally accepted in the United States.
As explained in Note 1 to the financial statements, effective January 1,
2001, Georgia Power Company changed its method of accounting for derivative
instruments and hedging activities.
/s/Arthur Andersen LLP
Atlanta, Georgia
February 13, 2002
II-97
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Georgia Power Company 2002 Annual Report
RESULTS OF OPERATIONS
Earnings
Georgia Power Company's 2002 earnings totaled $618 million, representing an $8
million (1.2 percent) increase over 2001. Operating income declined slightly in
2002. Lower retail and wholesale revenues, higher other operating and
maintenance expenses and increased purchased power capacity expenses were
significantly offset by lower depreciation and amortization expense as a result
of a Georgia Public Service Commission (GPSC) retail rate order effective
January 2002. The increase in net income for 2002 is attributed to lower
financing costs and a lower effective tax rate due to the realization of certain
state tax credits. The Company's 2001 earnings totaled $610 million,
representing a $51 million (9.1 percent) increase over 2000. Operating income
was lower in 2001 compared to 2000 due to the impact of mild weather on retail
revenues; however, overall net income improved due to lower financing costs and
non-operating expenses and a lower effective tax rate resulting from various
factors including property donations and positive resolution of outstanding tax
issues. The Company's 2000 earnings totaled $559 million, representing an $18
million (3.3 percent) increase over the prior year due to increased sales and
continued control of operating expenses.
Increase (Decrease)
Amount From Prior Year
-----------------------------------
2002 2002 2001 2000
- ----------------------------------------------------------------
(in millions)
Operating revenues $ 4,822 $ (144) $ 95 $ 414
- ----------------------------------------------------------------
Fuel 1,003 64 (79) 98
Purchased power 685 (87) 175 206
Other operation
and maintenance 1,325 85 41 4
Depreciation and
amortization 403 (197) (19) 66
Taxes other than
income taxes 202 (1) (1) 2
- ----------------------------------------------------------------
Total operating
expenses 3,618 (136) 117 376
- ----------------------------------------------------------------
Operating income 1,204 (8) (22) 38
Other income and
(expense) (229) 9 76 (11)
Less -
Income taxes 357 (7) 3 9
- ----------------------------------------------------------------
Net income $ 618 $ 8 $ 51 $ 18
================================================================
Revenues
Operating revenues in 2002, 2001, and 2000 and the percent of change
from the prior year are as follows:
Amount
-------------------------------------
2002 2001 2000
-------------------------------------
(in millions)
Retail - prior year $4,349 $4,317 $4,050
Change in -
Base rates (118) - (24)
Sales growth and other 2 90 53
Weather 82 (107) 55
Fuel cost recovery
and other clauses (27) 49 183
- --------------------------------------------------------------------
Total retail 4,288 4,349 4,317
- --------------------------------------------------------------------
Sales for resale -
Non-affiliates 271 366 298
Affiliates 98 100 96
- --------------------------------------------------------------------
Total sales for resale 369 466 394
- --------------------------------------------------------------------
Other operating revenues 165 151 160
- --------------------------------------------------------------------
Total operating revenues $4,822 $4,966 $4,871
====================================================================
Percent change (2.9%) 2.0% 9.3%
- --------------------------------------------------------------------
Retail base revenues of $3.068 billion in 2002 decreased by $34 million
(1.1 percent) from 2001 primarily due to a base rate reduction effective January
2002 under the retail rate order and generally lower prices to large business
customers. This decrease was partially offset by a 10.1 percent increase in
residential kilowatt-hour sales due to warmer weather.
Retail base revenues of $3.102 billion in 2001 decreased $17 million (0.5
percent) from 2000, primarily due to a 2.5 percent decrease in retail
kilowatt-hour sales from the prior year. Milder-than-normal weather and a
slowdown in the economy contributed to the decline in such sales. Retail base
revenues of $3.119 billion in 2000 increased $84 million from the prior year
primarily due to a 4.9 percent increase in retail kilowatt-hour sales due to
warmer summer temperatures and colder winter weather.
Electric rates include provisions to adjust billings for fluctuations in
fuel costs, the energy component of purchased power costs, and certain other
costs. Under these fuel cost recovery provisions, fuel revenues generally equal
fuel expenses -- including the fuel component of purchased energy -- and do not
affect net income. As of December 31, 2002, the Company had $118 million in
underrecovered fuel costs. Under a GPSC rate order, the fuel cost recovery rate
was increased effective June 2001 to allow for an estimated 24-month recovery of
II-98
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2002 Annual Report
the deferred underrecovered fuel costs. Also, effective January 1, 2002, the
Company is allowed to collect a carrying cost on average underrecovered fuel
balances.
Wholesale revenues from sales to non-affiliated utilities were:
2002 2001 2000
---------------------------
(in millions)
Unit power sales --
Capacity $ 34 $ 26 $ 30
Energy 34 35 25
Other power sales --
Capacity 41 72 67
Energy 162 233 176
- -----------------------------------------------------------
Total $271 $366 $298
===========================================================
Revenues from unit power contracts increased $7 million in 2002 due to
higher capacity charges and $6 million in 2001 due to increased energy sales,
while remaining constant in 2000. See Note 7 to the financial statements for
further information regarding these sales. Revenues from other non-affiliated
sales decreased $102 million (33.4 percent) in 2002 and increased $62 million in
2001 and $88 million in 2000 primarily due to fluctuations in off-system sale
transactions that were generally offset by corresponding purchase transactions.
These transactions had no significant effect on income. In 2002, revenues also
decreased $37 million as a result of transferring Plant Dahlberg to Southern
Power Company (Southern Power) in July 2001.
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.
Other operating revenues in 2002 increased $14 million (9.5 percent)
primarily due to the collection of new late payment fees approved under the
retail rate order effective January 2002 and revenues from outdoor lighting and
the transmission of electricity. Other operating revenues in 2001 decreased $9
million (5.3 percent) primarily due to lower gains on the sale of generating
plant emission allowances, partially offset by increased revenues from the
transmission of electricity and from the rental of electric equipment and
property. Other operating revenues in 2000 increased $39 million (32.8 percent)
due to increased revenues from the transmission of electricity and gains on the
sale of generating plant emission allowances.
Kilowatt-hour (KWH) sales for 2002 and the percent change by year were as
follows:
Percent Change
----------------------------
KWH
2002 2002 2001 2000
---------------------------------------
(in billions)
Residential 22.1 10.1% (2.8)% 6.6%
Commercial 27.0 1.7 3.4 8.1
Industrial 25.7 1.5 (8.0) 0.9
Other 0.6 1.7 2.5 3.2
------
Total retail 75.4 4.0 (2.5) 4.9
------
Sales for resale -
Non-affiliates 8.1 (0.5) 25.5 27.7
Affiliates 4.0 26.5 28.7 35.6
------
Total sales for
resale 12.1 7.0 26.3 29.8
------
Total sales 87.5 4.4 0.5 7.1
======
- ------------------------------------------------------------
Residential sales increased 10.1 percent in 2002 due to the effect of the
warmer weather. Commercial and industrial sales increased 1.7 percent and 1.5
percent, respectively, due to corresponding increases of 2.6 percent and 2.4
percent, respectively, in customers. Residential sales decreased 2.8 percent in
2001 due to milder-than-normal weather. Commercial sales increased 3.4 percent
due to an increase in customers, while industrial sales decreased 8.0 percent
due to an economic slowdown. Residential and commercial sales increased 6.6
percent and 8.1 percent, respectively, in 2000 due to weather and economic
growth. Industrial sales remained fairly constant in 2000.
Expenses
Fuel costs constitute the single largest expense for the Company. The mix of
fuel sources for generation of electricity is determined primarily by system
load, the unit cost of fuel consumed, and the availability of hydro and nuclear
generating units. The amount and sources of generation and the average cost of
fuel per net kilowatt-hour generated were as follows:
II-99
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2002 Annual Report
2002 2001 2000
--------------------------
Total generation
(billions of KWH) 70.4 68.9 73.6
Sources of generation
(percent) --
Coal 77.4 74.9 75.8
Nuclear 21.1 23.2 21.2
Hydro 1.2 1.4 0.8
Oil and gas 0.3 0.5 2.2
Average cost of fuel per net
KWH generated
(cents) -- 1.44 1.38 1.39
- ---------------------------------------------------------------
Fuel expense increased 6.8 percent due to an increase in generation because
of higher energy demands and a higher average cost of fuel due to the higher
cost of coal in 2002. In 2001, fuel expense decreased 7.7 percent due to a
decrease in generation because of lower energy demands and a slightly lower
average cost of fuel. In 2000, fuel expense increased 10.7 percent due to an
increase in generation because of higher energy demands and a slightly higher
average cost of fuel.
Purchased power expense decreased $87 million (11.2 percent) in 2002
primarily due to a decrease in off-system purchases used to meet lower
off-system sales commitments. This decrease, which had no significant effect on
income, was partially offset by a $43 million increase in capacity expense
associated with new purchased power contracts. Purchased power expense increased
$175 million (29.4 percent) in 2001 primarily due to an increase in off-system
purchases used to meet off-system sales commitments. These transactions had no
significant effect on earnings. Purchased power expense in 2000 increased $206
million (53.0 percent) over the prior year due to higher retail energy demands
and off-system purchase transactions used to meet off-system sales transactions.
In 2002, other operation and maintenance expenses increased $85 million
(6.8 percent) due to increased generating plant maintenance, higher transmission
expense, and increased property insurance expense. In 2001, other operation and
maintenance expenses increased $41 million (3.4 percent) due to additional
severance costs, increased scheduled generating plant maintenance, and higher
uncollectible account expense. Other operation and maintenance expenses in 2000
increased slightly over the prior year. Increased line maintenance, customer
assistance and sales expense, and severance costs were partially offset by
decreased generating plant maintenance and decreased employee benefit
provisions.
Depreciation and amortization decreased $197 million in 2002 primarily as a
result of discontinuing accelerated depreciation, beginning amortization of the
regulatory liability for accelerated cost recovery, and lowering the composite
depreciation rates in January 2002 all in accordance with the retail rate order.
Depreciation and amortization decreased $19 million in 2001 primarily due to
lower accelerated amortization under the third year of a prior GPSC retail rate
order. Depreciation and amortization increased $66 million in 2000 primarily due
to $50 million of additional accelerated amortization of regulatory assets
required under the second year of the prior GPSC retail rate order and increased
plant in service. See Note 3 to the financial statements under "Retail Rate
Orders" for additional information.
Interest expense decreased in 2002 and 2001 primarily due to lower interest
rates that offset new financing costs. Interest expense increased in 2000 due to
the issuance of additional senior notes. The Company refinanced or retired $929
million, $775 million, and $179 million of securities in 2002, 2001, and 2000,
respectively. Interest capitalized decreased in 2002 due to the transfer of
three new generation projects to Southern Power. Interest capitalized increased
in 2001 and 2000 during the construction phase of these new projects. See Note 4
under "Construction Program" for additional information regarding the
construction and subsequent transfer of these generation assets. Distributions
on preferred securities of subsidiary companies increased in 2002 due to the
issuance of additional securities and remained unchanged in 2001. Distributions
on preferred securities of subsidiary companies decreased $7 million in 2000 due
to the redemption of $100 million of preferred securities in December 1999.
Other income (expense), net decreased in 2002 due to lower gains realized
on sales of assets. Other income (expense), net increased in 2001 due to gains
realized on sales of assets and a decrease in charitable contributions. Other
income (expense), net decreased in 2000 due to an increase in charitable
contributions.
Effects of Inflation
The Company is subject to rate regulation that is based on the recovery of
historical costs. In addition, the income tax laws are also based on historical
costs. Therefore, inflation creates an economic loss because the Company is
II-100
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2002 Annual Report
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
General
The results of operations for the past three years are not necessarily
indicative of future earnings. The level of future earnings depends on numerous
factors including energy sales and regulatory matters.
Growth in energy sales is subject to a number of factors which
traditionally have included changes in contracts with neighboring utilities,
energy conservation practiced by customers, the price elasticity of demand,
weather, competition, initiatives to increase sales to existing customers, and
the rate of economic growth in the Company's service area which has decreased
recently in concert with a slowing national economy. Retail sales growth
assuming normal weather is expected to be 2.3 percent on average from 2003 to
2005 and is down from last year's forecast of 3.1 percent.
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.
In accordance with Financial Accounting Standards Board (FASB) Statement
No. 87, Employers' Accounting for Pensions, the Company recorded non-cash
pension income, before tax, of approximately $59 million in 2002. Future pension
income is dependent on several factors including trust earnings and changes to
the plan. Current estimates indicate a reversal of recording pension income to
recording pension expense by as early as 2006. Postretirement benefit costs for
the Company were $43 million in 2002 and are expected to continue to trend
upward. A portion of pension and postretirement benefit costs is capitalized
based on construction-related labor charges. For the Company, pension income and
postretirement benefit costs are a component of the regulated rates and do not
have a significant effect on net income. For additional information, see Note 2
to the financial statements.
In December 2001, the GPSC approved a three-year retail rate order for the
Company ending December 31, 2004. Under the terms of the order, earnings will be
evaluated annually against a retail return on common equity range of 10 percent
to 12.95 percent. Two-thirds of any earnings above the 12.95 percent return will
be applied to rate refunds with the remaining one-third retained by the Company.
Retail rates were decreased by $118 million effective January 1, 2002. Pursuant
to a previous three-year accounting order, the Company recorded $333 million of
accelerated cost amortization and interest thereon which has been credited to a
regulatory liability account as mandated by the GPSC. Under the rate order, the
accelerated amortization and the interest will be amortized equally over three
years as a credit to expense beginning in 2002. Within the three year period
covered by the rate order, the Company may 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, 2004,
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.
Beginning in 2002, the Company entered into purchased power agreements
which will result in higher capacity and operating and maintenance payments in
future years. Under the current retail rate order, these costs will be reflected
in rates evenly over the three years ending 2004. In December 2002, the GPSC
approved additional expansion of the Company's electricity generating capacity
starting in 2005 through purchased power contracts. Beginning in June 2005, the
Company will purchase 1,040 megawatts of capacity from the planned units at
Plant McIntosh to be built and owned by Southern Power, and will also buy 620
megawatts of capacity from a plant owned by Duke Energy Trading & Marketing. See
Note 4 to the financial statements under "Purchased Power Commitments" for
additional information. Additionally, the GPSC approved the retirement of 415
megawatts from 11 units at plants Arkwright, Atkinson, and Mitchell. The
II-101
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2002 Annual Report
retirements are the result of a unit retirement analysis that determined the
units are more expensive to operate than the cost of replacement power. When
property subject to composite depreciation is retired or otherwise disposed of
in the normal course of business, its original cost - together with the cost of
removal, less salvage - is charged to accumulated depreciation.
On December 24, 2002, the GPSC approved an order allowing Georgia Power to
implement a natural gas and oil procurement and hedging program effective
January 1, 2003. This order allows the Company to use financial instruments in
implementing a hedging program. The order limits the program in terms of time,
volume, dollars, and physical amounts hedged. The costs of the program,
including any net losses, are recovered as a fuel cost through the fuel cost
recovery mechanism. Annual net financial gains from the hedging program will be
shared with the retail customers receiving 75 percent and Georgia Power
retaining 25 percent of the net gains.
Georgia Power had three generation projects under construction during 2001.
They included two units at Plant Dahlberg, a ten-unit, 800 megawatt combustion
turbine facility; two units totaling 1,132 megawatts at Plant Wansley; and Plant
Franklin (formerly Plant Goat Rock), a two-unit, 1,181 megawatt facility. All
three of these projects have been transferred, at cost, to Southern Power. The
ten Dahlberg units and two Franklin units were transferred in 2001 and the
transfer of the two Wansley units was completed in January 2002.
See Note 3 to the financial statements for information regarding material
litigation issues that could possibly affect future earnings.
Compliance costs related to current and future environmental laws,
regulations, and litigation could affect earnings if such costs are not fully
recovered. See "Environmental Matters" for further discussion of these matters.
The State of Georgia is currently considering changes to laws that could
potentially impact Georgia Power's ability to establish sites for new
transmission lines. The proposed legislation would require certification by the
GPSC prior to the acquisition of any property for the construction of an
electric transmission line. The outcome of this matter cannot now be determined.
Proposed nuclear security legislation is expected to be introduced in the
108th Congress. The Nuclear Regulatory Commission (NRC) is also considering
additional security measures for licensees that could require immediate
implementation. Any such requirements could have a significant impact on the
Company's nuclear power plants and result in increased operation and maintenance
expenses as well as additional capital expenditures. The impact of any new
requirements would depend upon the development and implementation of the
regulations.
Industry Restructuring
The electric utility industry in the United States is continuing to evolve as a
result of regulatory and competitive factors. Among the primary agents of change
was 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 enhanced the incentive for
IPPs to build power plants for a utility's large industrial and commercial
customers where retail access is allowed and sell energy to other utilities.
Also, electricity sales for resale rates were affected by numerous new energy
suppliers, including power marketers and brokers.
This past year, merchant energy companies and traditional electric
utilities with significant energy marketing and trading activities came under
severe financial pressures. Many of these companies have completely exited or
drastically reduced all energy marketing and trading activities and sold foreign
and domestic electric infrastructure assets. The Company has not experienced any
material financial impact regarding its limited energy trading operations.
Although the Energy Act does not provide for retail customer access, it has
been a major catalyst for recent restructuring and consolidations taking place
within the utility industry. Numerous federal and state initiatives that promote
wholesale and retail competition are in varying stages. Among other things,
these initiatives allow retail customers in some states to choose their
electricity provider. 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 discussed in
Georgia, none have been enacted. Enactment could require numerous issues to be
II-102
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2002 Annual Report
resolved, including significant ones relating to recovery of any stranded
investments, full cost recovery of energy produced, and other issues related to
the energy crisis that occurred in California. The Company does 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.
Continuing to be a low-cost producer could provide opportunities to
increase market share and profitability in markets that evolve with changing
regulation and competition. 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.
FERC Matters
In December 1999, the Federal Energy Regulatory Commission (FERC) issued its
final rule on Regional Transmission Organizations (RTOs). The order encouraged
utilities owning transmission systems to form RTOs on a voluntary basis.
Southern Company has submitted a series of status reports informing the FERC of
progress toward the development of a Southeastern RTO. In these status reports,
Southern Company explained that it is developing a for-profit RTO known as
SeTrans with a number of non-jurisdictional cooperative and public power
entities. In 2002, the sponsors of SeTrans established a Stakeholder Advisory
Committee, which will participate in the development of the RTO, and held public
meetings to discuss the SeTrans proposal. On October 10, 2002, the FERC granted
Southern Company's and other SeTrans sponsors' petition for a declaratory order
regarding the governance structure and the selection process for the Independent
System Administrator (ISA) of the SeTrans RTO. The FERC also provided guidance
on other issues identified in the petition. The SeTrans sponsors announced the
selection of ESB International, Ltd. (ESBI) to be the preferred candidate for
ISA. Should negotiations with this candidate successfully conclude with final
agreement among the parties, the SeTrans sponsors intend to seek any state and
federal regulatory or other approvals necessary for the formation of the SeTrans
RTO and the approval of ESBI to serve in the capacity of SeTrans ISA. The
creation of SeTrans is not expected to have a material impact on the Company's
financial statements; however, the outcome of this matter cannot now be
determined.
In July 2002, the FERC issued a notice of proposed rulemaking regarding
open access transmission service and standard electricity market design. The
proposal, if adopted, would among other things: (1) require transmission assets
of jurisdictional utilities to be operated by an independent entity; (2)
establish a standard market design; (3) establish a single type of transmission
service that applies to all customers; (4) assert jurisdiction over the
transmission component of bundled retail service; (5) establish a generation
reserve margin; (6) establish bid caps for a day ahead and spot energy markets;
and (7) revise the FERC policy on the pricing of transmission expansions.
Comments on certain aspects of the proposal have been submitted by Southern
Company. Any impact of this proposal on the Company will depend on the form in
which final rules may be ultimately adopted; however, the Company's revenues,
expenses, assets, and liabilities could be adversely affected by changes in the
transmission regulatory structure in its regional power market.
Accounting Policies
Critical Policy
Georgia Power's significant accounting policies are described in Note 1 to the
financial statements. The Company's only critical accounting policy involves
rate regulation. 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, including plant, have been impaired. See Note 1 to the financial
statements under "Regulatory Assets and Liabilities" for additional information.
New Accounting Standards
Derivatives
- -----------
Effective January 2001, Georgia Power adopted FASB Statement No. 133, Accounting
for Derivative Instruments and Hedging Activities, as amended. In October 2002,
the Emerging Issues Task Force (EITF) of the FASB announced accounting changes
related to energy trading contracts in Issue No. 02-03. In October 2002, the
Company prospectively adopted the EITF's requirements to reflect the impact of
certain energy trading contracts on a net basis. This change had no material
II-103
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2002 Annual Report
impact on the Company's income statement. Another change also required certain
energy trading contracts to be accounted for on an accrual basis effective
January 2003. This change had no impact on the Company's current accounting
treatment.
Asset Retirement Obligations
- ----------------------------
Prior to January 2003, the Company accrued for the ultimate cost of retiring
most long lived assets over the life of the related asset through depreciation
expense. FASB Statement No. 143, Accounting for Asset Retirement Obligations,
establishes new accounting and reporting standards for legal obligations
associated with the ultimate cost of retiring long-lived assets. The present
value of the ultimate costs for an asset's future retirement must be recorded in
the period in which the liability is incurred. The cost must be capitalized as
part of the related long-lived asset and depreciated over the asset's useful
life. Additionally, Statement No. 143 does not permit non-regulated companies to
continue accruing future retirement costs for long-lived assets that they do not
have a legal obligation to retire. For more information regarding the impact of
adopting this standard effective January 1, 2003, see Note 1 to the financial
statements under "Regulatory Assets and Liabilities" and "Depreciation and
Nuclear Decommissioning."
Guarantees
- ----------
In 2002, the FASB issued Interpretation No. 45, Accounting and Disclosure
Requirements for Guarantees. This interpretation requires disclosure of certain
direct and indirect guarantees, as reflected in Note 4 to the financial
statements under "Guarantees." Also, the interpretation requires recognition of
a liability at inception for certain new or modified guarantees issued after
December 31, 2002. The adoption of Interpretation No. 45 in January 2003 did not
have a material impact on the Company's financial statements.
FINANCIAL CONDITION
Plant Additions
In 2002, gross utility plant additions were $884 million. These additions were
primarily related to transmission and distribution facilities, the purchase of
nuclear fuel and equipment to comply with environmental standards. The funds
needed for gross property additions are currently provided from operations,
short-term and long-term debt, and capital contributions from Southern Company.
The Statements of Cash Flows provide additional details.
Credit Rating Risk
The Company does not have any credit agreements that would require material
changes in payment schedules or terminations as a result of a credit rating
downgrade. There are contracts that could require collateral -- but not
accelerated payment -- in the event of a credit rating change to below
investment grade. At December 31, 2002, the maximum potential collateral
requirements were approximately $229 million.
Exposure to Market Risks
Due to cost-based rate regulations, the Company has limited exposure to market
volatility in interest rates, commodity fuel prices, and prices of electricity.
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. Company
policy is that derivatives are to be used primarily for hedging purposes.
Derivative positions are monitored using techniques that include market
valuation and sensitivity analysis.
The weighted average interest rate on variable long-term debt outstanding
at December 31, 2002 was 1.7 percent. If the Company sustained a 100 basis point
change in interest rates for all variable rate long-term debt, the change would
affect annualized interest expense by approximately $9 million. To further
mitigate the Company's exposure to interest rates, the Company has entered into
interest rate swaps that were designed as cash flow hedges of variable rate debt
or anticipated debt issuances. See Note 1 and Note 9 to the financial statements
under "Financial Instruments" for additional information. The Company is not
aware of any facts or circumstances that would significantly affect such
exposures in the near term.
To mitigate residual risks relative to movements in electricity prices, the
Company entered into fixed price contracts for the purchase and sale of
electricity through the wholesale electricity market and to a lesser extent
similar contracts for gas purchases. Realized gains and losses are recognized in
the Statements of Income as incurred. At December 31, 2002 and 2001, exposure
II-104
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2002 Annual Report
from these activities was not material to the Company's financial statements.
Fair value of changes in derivative energy contracts and year-end valuations
were as follows:
Changes in Fair Value
- ----------------------------------------------------------------
2002 2001
- ----------------------------------------------------------------
(in millions)
Contracts beginning of year $0.4 $0.9
Contracts realized or settled 0.9 (0.6)
New contracts at inception - -
Changes in valuation techniques - -
Current period changes (1.2) 0.1
================================================================
Contracts end of year $0.1 $0.4
================================================================
All of these contracts are actively quoted and mature within one year. For
additional information, see Note 1 to the financial statements under "Financial
Instruments."
Gains (losses) were not material and were recognized in income in 2002 and
2001. The Company is exposed to market-price risk in the event of nonperformance
by parties to the derivative energy contracts. The Company's policy is to enter
into agreements with counterparties that have investment grade credit ratings by
Moody's and Standard & Poor's or with counterparties who have posted collateral
to cover potential credit exposure. Therefore, the Company does not anticipate
market risk exposure from nonperformance by the counterparties. For additional
information, see Notes 1 and 9 to the financial statements under "Financial
Instruments."
Financing Activities
In 2002, the Company's financing costs decreased due to lower interest rates
despite the issuance of new debt during the year. New issues during 2000 through
2002 totaled $2.6 billion and retirement or repayment of higher-cost securities
totaled $1.9 billion.
The Company's current liabilities exceed current assets because of the
continued use of short-term debt as a funding source to meet cash needs as well
as scheduled maturities of long-term debt. Subsequent to December 31, 2002, the
Company has issued $250 million of new securities with the proceeds being used
primarily to retire current maturities and to reduce short-term debt. An
additional $150 million of securities has been issued to retire long-term debt
and for other corporate purposes.
The proceeds from assets transferred to Southern Power were used to reduce
short-term debt and return capital that was used during the construction of
these projects to Southern Company.
Composite financing rates for long-term debt, preferred stock, and
preferred securities for the years 2000 through 2002, as of year-end, were as
follows:
2002 2001 2000
-------------------------------
Composite interest rate
on long-term debt 4.47% 4.26% 5.90%
Composite preferred
stock dividend rate 4.60 4.60 4.60
Composite preferred
securities dividend rate 6.35 7.49 7.49
- ---------------------------------------------------------------
Liquidity and Capital Requirements
Cash provided from operating activities of $1.2 billion increased by $142
million primarily due to lower fuel inventories and the collection of
underrecovered fuel costs. See the Statements of Cash Flows for additional
information.
The Company plans investments primarily in additional transmission and
distribution facilities and equipment to comply with environmental requirements.
In addition to the funds needed for the construction program, capital will be
needed for lease commitments and fuel and purchased power contracts. For
additional information, see Note 4 to the financial statements.
Also, capital will be needed for the maturities of long-term debt. The
Company will continue to retire higher-cost debt and preferred securities and
replace these obligations with lower-cost capital if market conditions permit.
For additional information, see Note 9 to the financial statements under
"Securities Due Within One Year."
As a result of requirements by the NRC, the Company has established
external trust funds for nuclear decommissioning costs. For additional
information concerning nuclear decommissioning costs, see Note 1 to the
financial statements under "Depreciation and Nuclear Decommissioning."
As discussed in Note 2, the Company also provides postretirement benefits
to substantially all employees and funds trusts to the extent required by the
GPSC and the FERC.
II-105
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2002 Annual Report
The liquidity and capital requirements discussed above are as follows:
2003 2004 2005
- -------------------------------------------------------------------
(in millions)
Construction expenditures $ 759 $ 781 $806
Senior and other notes 320 0 150
Leases
Capital 2 2 2
Operating 30 28 23
Purchase commitments
Fuel 1,097 764 657
Purchased power 223 285 389
Trusts
Nuclear decommissioning 9 9 9
Postretirement benefits 8 9 8
- -------------------------------------------------------------------
Sources of Capital
The Company expects to meet future capital requirements primarily using funds
generated from operating activities and equity funds from Southern Company and
by the issuance of new debt and equity securities, term loans, and short-term
borrowings. The Company received new financing authority from the GPSC in early
2002, which allows for the issuance of new long-term securities.
Recently, the Company has relied on the issuance of unsecured debt and
trust preferred securities, in addition to unsecured pollution control bonds
issued for its benefit by public authorities, to meet its long-term external
financing requirements. To meet short-term cash needs and contingencies, the
Company had approximately $1.175 billion of unused credit arrangements with
banks at the beginning of 2003. See Note 9 to the financial statements under
"Bank Credit Arrangements" for additional information.
The Company may also meet short-term cash needs through a Southern Company
subsidiary organized to issue and sell commercial paper and extendible
commercial notes at the request and for the benefit of the Company and the other
Southern Company operating companies. At December 31, 2002, the Company had
outstanding $358 million of commercial paper and $19 million of extendible
commercial notes.
In February 2002, the Company defeased its first mortgage bond indenture.
As a result, the Company cannot issue any securities pursuant to the first
mortgage bond indenture. Any liens or encumbrances on the Company's property
pursuant to the first mortgage bond indenture were discharged. See "First
Mortgage Bond Indenture" under Note 9 to the financial statements for more
information.
At the beginning of 2003, Georgia Power had not used any of its available
credit arrangements. Bank credit arrangements are as follows:
Expires
---------------------
Total Unused 2003
------------------------------------------------
(in millions)
$1,175 $1,175 $1,175
- --------------------------------------------------
All of these credit arrangements allow for the execution of term loans for
an additional two year period.
Environmental Matters
New Source Review Enforcement Actions
In November 1999, the Environmental Protection Agency (EPA) brought a civil
action in U.S. District Court in Georgia. The complaint alleges violations of
the 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 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 Company a notice of violation related to
the two plants mentioned previously. 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 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 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. As directed by the court, the EPA refiled its amended complaint limiting
claims to those brought against the Company.
The case against the Company has been stayed since the spring of 2001,
pending a ruling by the U.S. Court of Appeals for the Eleventh Circuit in the
appeal of a very similar New Source Review enforcement action against the
II-106
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2002 Annual Report
Tennessee Valley Authority (TVA). The TVA appeal involves many of the same legal
issues raised by the actions against the Company. Because the outcome of the TVA
appeal could have a significant adverse impact on Georgia Power, the Company has
been a party to that case as well. On August 21, 2002, the U.S. District Court
in Georgia denied the EPA's motion to reopen the Georgia case. The denial was
without prejudice to the EPA to refile the motion at a later date, which the EPA
has not done at this time.
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 in any one of these cases could require substantial
capital expenditures and additional operation and maintenance expenses that
cannot be determined at this time and could 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.
Plant Wansley Clean Air Act Litigation
On December 30, 2002, the Sierra Club, Physicians for Social Responsibility,
Georgia ForestWatch, and one individual filed a civil suit in the U.S. District
Court in Georgia against Georgia Power for alleged violations of the Clean Air
Act at Plant Wansley. The complaint alleges Clean Air Act violations at both the
existing coal-fired units and the new combined cycle units. Specifically, the
plaintiffs allege (1) opacity violations at the coal-fired units, (2) violations
of a permit provision that requires the combined cycle units to operate above
certain levels, (3) violation of the nitrogen oxide emission offset
requirements, and (4) violation of the hazardous air pollutant (HAPS)
requirements. The civil action requests injunctive and declaratory relief, civil
penalties, a supplemental environmental project, and attorneys' fees. The Clean
Air Act authorizes civil penalties of up to $27,500 per day, per violation at
each generating unit. On January 27, 2003, Georgia Power filed a response to the
complaint. Georgia Power also filed a motion to dismiss the allegations
regarding emission offsets and HAPS. While Georgia Power believes that it has
complied with applicable laws and regulations, an adverse outcome could require
payment of substantial penalties. The final outcome of this matter cannot now be
determined.
Environmental Statutes and Regulations
The Company's operations are subject to extensive regulation by state and
federal environmental agencies under a variety of statutes and regulations
governing environmental media, including air, water, and land resources.
Compliance with these environmental requirements will involve significant costs,
a major portion of which is expected to be recovered through existing ratemaking
provisions. There is no assurance, however, that all such costs will, in fact,
be recovered.
Compliance with the federal Clean Air Act and resulting regulations has
been, and will continue to be, a significant focus for the Company. The Title IV
acid rain provisions of the Clean Air Act, for example, required significant
reductions in sulfur dioxide and nitrogen oxide emissions. Compliance was
required in two phases -- Phase I, effective in 1995 and Phase II, effective in
2000. Construction expenditures associated with Phase I and Phase II compliance
totaled approximately $206 million.
Some of the expenditures required to comply with the Phase II acid rain
requirements also assisted the Company in complying with nitrogen oxide emission
reduction requirements under Title I of the Clean Air Act, which were designed
to address one-hour ozone nonattainment problems in Atlanta, Georgia. The State
of Georgia has adopted regulations that will require additional nitrogen oxide
emission reductions from plants in and/or near those nonattainment areas,
beginning in May 2003. Seven generating plants in the Atlanta area will be
affected. Construction expenditures for compliance with these new rules are
currently estimated at approximately $690 million, of which $71 million remains
to be spent.
To help bring the remaining nonattainment areas into compliance with the
one-hour ozone standard, in 1998 the EPA issued regional nitrogen oxide
reduction rules. Those rules required 21 states, including Georgia, to reduce
and cap nitrogen oxide emissions from power plants and other large industrial
sources. For Georgia, the EPA must complete a separate rulemaking before the
requirements will apply. The EPA proposed a rule for Georgia in 2002 and expects
to issue a final rule in 2003. The proposed rule requires compliance by May 1,
2005.
In July 1997, the EPA revised the national ambient air quality standards for
ozone and particulate matter. These revisions made the standards significantly
more stringent. In the subsequent litigation of these standards, the U.S.
II-107
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2002 Annual Report
Supreme Court found the EPA's implementation program for the new ozone standard
unlawful and remanded it to the EPA for further rulemaking. The EPA is expected
to propose implementation rules designed to address the court's concerns in 2003
and issue final implementation rules in 2004. The remaining legal challenges to
the new standards, which were pending before the U.S. Court of Appeals, District
of Columbia Circuit, have been resolved.
The EPA plans to designate areas as attainment or nonattainment with the new
eight-hour ozone standard by April 2004, based on air quality data for 2001
through 2003. Several areas within the Company's service territory are likely to
be designated nonattainment under the new ozone standard. State implementation
plans, including new emission control regulations necessary to bring those areas
into attainment, could be required as early as 2007. Those state plans could
require further reductions in nitrogen oxide emissions from power plants. If so,
reductions could be required sometime after 2007. The impact of any new
standards will depend on the development and implementation of applicable
regulations.
The EPA currently plans to designate areas as attainment or nonattainment
with the new fine particulate matter standard by the end of 2004. Those area
designations will be based on air quality data collected during 2001 through
2003. Several areas within the Company's service territory will likely be
designated nonattainment under the new particulate matter standard. State
implementation plans, including new emission control regulations necessary to
bring those areas into attainment, could be required as early as the end of
2007. Those state plans will likely require reductions in sulfur dioxide
emissions from power plants. If so, the reductions could be required sometime
after 2007. Any additional emission reductions and costs associated with the new
fine particulate matter standard cannot be determined at this time.
The EPA has also announced plans to issue a proposed Regional Transport Rule
for the fine particulate matter standard by the end of 2003 and to finalize the
rule in 2005. This rule would likely require year-round sulfur dioxide and
nitrogen oxide emission reductions from power plants as early as 2010. If
issued, this rule would likely modify other state implementation plan
requirements for attainment of the fine particulate matter standard and the
eight-hour ozone standard. It is not possible at this time to determine the
effect such a rule would have on the Company.
Further reductions in sulfur dioxide could also be required under the EPA's
Regional Haze rules. The Regional Haze rules require states to establish Best
Available Retrofit Technology (BART) standards for certain sources that
contribute to regional haze. The Company has a number of plants that could be
subject to these rules. The EPA regional haze program calls for states to submit
State Implementation Plans in 2007 and 2008 that contain emission reduction
strategies for achieving progress toward the visibility improvement goal. In
2002, however, the U.S. Court of Appeals, District of Columbia Circuit, vacated
and remanded the BART provisions of the federal Regional Haze rules to the EPA
for further rulemaking. Because new BART rules have not been developed and state
visibility assessments are only beginning, it is not possible to determine the
effect of these rules on the Company at this time.
The EPA's Compliance Assurance Monitoring (CAM) regulations under Title V of
the Clean Air Act require that monitoring be performed to ensure compliance with
emissions limitations on an ongoing basis. The regulations require certain
facilities with Title V operating permits to develop and submit a CAM plan to
the appropriate permitting authority upon applying for renewal of the facility's
Title V operating permit. The Company will be applying for renewal of its Title
V operating permits between 2003 and 2005, and a number of its plants will
likely be subject to CAM requirements for at least one pollutant, in most cases,
particulate matter. The Company is in the process of developing CAM plans, which
could indicate a need for improved particulate matter controls at affected
facilities. Because the plans are still in the early stages of development, the
Company cannot determine the extent to which improved controls could be required
or the costs associated with any necessary improvements. Actual ongoing
monitoring costs are expensed as incurred and are not material for any period
presented.
In December 2000, having completed its utility studies for mercury and other
HAPS, the EPA issued a determination that an emission control program for
mercury and, perhaps, other HAPS is warranted. The program is being developed
under the Maximum Achievable Control Technology provisions of the Clean Air Act.
The EPA currently plans to issue proposed rules regulating mercury emissions
from electric utility boilers by the end of 2003, and those regulations are
II-108
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2002 Annual Report
scheduled to be finalized by the end of 2004. Compliance could be required as
early as 2007. Because the rules have not yet been proposed, the costs
associated with compliance cannot be determined at this time.
In December 2002, the EPA issued final and proposed revisions to the New
Source Review program under the Clean Air Act. In February 2003, several
northeastern states petitioned the D.C. Circuit Court for a stay of the final
rules. The proposed rules are open to public comment and may be revised before
being finalized by the EPA. If fully implemented, these proposed and final
regulations could affect the applicability of the New Source Review provisions
to activities at the Company's facilities. In any event, any final regulations
must be adopted by the State of Georgia in order to apply to the Company's
facilities. The effect of these proposed and final rules cannot be determined at
this time.
Several major bills to amend the Clean Air Act to impose more stringent
emissions limitations have been proposed. Three of these, the Bush
Administration's Clear Skies Act, the Clean Power Act of 2002, and the Clean Air
Planning Act of 2002, proposed to further limit power plant emissions of sulfur
dioxide, nitrogen oxides, and mercury. The latter two bills also proposed to
limit emissions of carbon dioxide. None of these bills were enacted into law in
the last Congress. Similar bills have been, and are anticipated to be,
introduced this year. The Bush Administration's Clear Skies Act was recently
reintroduced, and President Bush has stated that it will be a high priority for
the Administration. Other bills already introduced include the Climate
Stewardship Act of 2003, which proposes capping greenhouse gas emissions. The
cost impacts of such legislation would depend upon the specific requirements
enacted.
Domestic efforts to limit greenhouse gas emissions have been spurred by
international discussions surrounding the Framework Convention on Climate Change
and specifically the Kyoto Protocol, which proposes international constraints on
the emissions of greenhouse gases. The Bush Administration does not support U.S.
ratification of the Kyoto Protocol or other mandatory carbon dioxide reduction
legislation and has instead announced a new voluntary climate initiative which
seeks an 18 percent reduction by 2012 in the rate of greenhouse gas emissions
relative to the dollar value of the U.S. economy. As part of Southern Company,
the Company is involved in a voluntary electric utility industry sector climate
change initiative in partnership with the government. Because this initiative is
still under development, it is not possible to determine the effect on the
Company at this time.
The Company must comply with other environmental laws and regulations that
cover the handling and disposal of hazardous waste and releases of hazardous
substances. 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 and has recognized in its financial
statements the costs to clean up known sites. The Company expensed $4.0 million,
$0.6 million, and $4.0 million for cleanup and ongoing monitoring costs in 2002,
2001, and 2000, respectively. The Company may be liable for a portion or all
required cleanup costs for additional sites that may require environmental
remediation. Under GPSC ratemaking provisions, $21 million has been deferred in
a regulatory liability account for use in meeting future environmental
remediation costs. See Note 3 to the financial statements under "Other
Environmental Contingencies" for information regarding the Company's potentially
responsible party status at sites in Georgia.
Under the Clean Water Act, the EPA is developing new rules aimed at reducing
impingement and entrainment of fish and fish larvae at cooling water intake
structures that will require numerous biological studies, and, perhaps,
retrofits to some intake structures at existing power plants. The new rule was
proposed in February 2002 and will be finalized by August 2004. The impact of
any new standards will depend on the development and implementation of
applicable regulations.
Also, under the Clean Water Act, the EPA and the State of Georgia
Environmental Protection Division are developing total maximum daily loads
(TMDLs) for certain impaired waters. Establishment of maximum loads by the EPA
or state agencies may result in lowering permit limits for various pollutants
and a requirement to take additional measures to control non-point source
pollution (e.g., storm water runoff) at facilities discharging into waters for
which TMDLs are established. Because the effect on the Company will depend on
the actual TMDLs and permit limitations established by the implementing agency,
it is not possible to determine the effect on the Company at this time.
II-109
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2002 Annual Report
The EPA and state environmental regulatory agencies are reviewing and
evaluating various other matters including limits on pollutant discharges to
impaired waters, hazardous waste disposal requirements, and other regulatory
matters. The impact of any new standards will depend on the development and
implementation of applicable regulations.
Several major pieces of environmental legislation are periodically
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; the Emergency Planning & Community Right-to-Know
Act; and the Endangered Species Act.
Compliance with possible additional federal or state legislation related to
global climate change, electromagnetic fields, and other environmental and
health concerns could also significantly affect the Company. The impact of any
new legislation, or changes to existing legislation, could affect many areas of
the Company's operations. The full impact of any such changes cannot be
determined at this time.
CAUTIONARY STATEMENT REGARDING
FORWARD-LOOKING INFORMATION
The Company's 2002 Annual Report includes forward-looking statements in addition
to historical information. Forward-looking information includes, among other
things, statements concerning retail sales growth expectations. In some cases,
forward-looking statements can be identified by terminology such as "may,"
"will," "could," "should," "expects," "plans," "anticipates," "believes,"
"estimates," "predicts," "projects," "potential" or "continue" or the negative
of these terms or other comparable terminology. The Company cautions that there
are various important factors that could cause actual results to differ
materially from those indicated in the forward-looking statements; accordingly,
there can be no assurance that such indicated results will be realized.
These factors include the impact of recent and future federal and state
regulatory change, including legislative and regulatory initiatives regarding
deregulation and restructuring of the electric utility industry and also changes
in environmental and other laws and regulations to which the Company is subject,
as well as changes in application of existing laws and regulations; current and
future litigation, including the pending EPA civil action; the effect, extent,
and timing of the entry of additional competition in the markets in which the
Company operates; the impact of fluctuations in commodity prices, interest
rates, and customer demand; state and federal rate regulations; political,
legal, and economic conditions and developments in the United States; the
effects of, and changes in economic conditions in the areas in which the Company
operates, including the current soft economy; internal restructuring or other
restructuring options that may be pursued by the Company; potential business
strategies, including acquisitions or dispositions of assets or businesses,
which cannot be assured to be completed or beneficial; the direct or indirect
effects on the Company's business resulting from the terrorist incidents on
September 11, 2001, or any similar such incidents or responses to such
incidents; financial market conditions and the results of financing efforts; the
ability of counterparties of the Company to make payments as and when due; the
ability of the Company to obtain additional generating capacity at competitive
prices; weather and other natural phenomena; and other factors discussed
elsewhere herein and in other reports (including Form 10-K) filed from time to
time by the Company with the Securities and Exchange Commission.
II-110
STATEMENTS OF INCOME
For the Years Ended December 31, 2002, 2001, and 2000
Georgia Power Company 2002 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------
2002 2001 2000
- ----------------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Revenues:
Retail sales $4,288,097 $4,349,312 $4,317,338
Sales for resale --
Non-affiliates 270,678 366,085 297,643
Affiliates 98,323 99,411 96,150
Other revenues 165,362 150,986 159,487
- ----------------------------------------------------------------------------------------------------------------------------
Total operating revenues 4,822,460 4,965,794 4,870,618
- ----------------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
Fuel 1,002,703 939,092 1,017,878
Purchased power --
Non-affiliates 264,814 442,196 356,189
Affiliates 419,839 329,232 239,815
Other 848,436 810,043 795,458
Maintenance 476,962 430,413 404,189
Depreciation and amortization 403,507 600,631 619,094
Taxes other than income taxes 201,857 202,483 204,527
- ----------------------------------------------------------------------------------------------------------------------------
Total operating expenses 3,618,118 3,754,090 3,637,150
- ----------------------------------------------------------------------------------------------------------------------------
Operating Income 1,204,342 1,211,704 1,233,468
Other Income and (Expense):
Allowance for equity funds used during construction 7,622 9,081 2,901
Interest income 3,857 4,264 2,629
Equity in earnings of unconsolidated subsidiaries 3,714 4,178 3,051
Interest expense, net of amounts capitalized (168,391) (183,879) (208,868)
Distributions on preferred securities of subsidiary (62,553) (59,104) (59,104)
Other income (expense), net (12,973) (11,897) (53,396)
- ----------------------------------------------------------------------------------------------------------------------------
Total other income and (expense) (228,724) (237,357) (312,787)
- ----------------------------------------------------------------------------------------------------------------------------
Earnings Before Income Taxes 975,618 974,347 920,681
Income taxes 357,319 363,599 360,587
- -----------------------------------------------------------------------------------------------------------------------------
Earnings Before Cumulative Effect of 618,299 610,748 560,094
Accounting Change
Cumulative effect of accounting change--
less income taxes of $162 - 257 -
- ----------------------------------------------------------------------------------------------------------------------------
Net Income 618,299 611,005 560,094
Dividends on Preferred Stock 670 670 674
- ----------------------------------------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred Stock $ 617,629 $ 610,335 $ 559,420
============================================================================================================================
The accompanying notes are an integral part of these financial statements.
II-111
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2002, 2001, and 2000
Georgia Power Company 2002 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------
2002 2001 2000
- -----------------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Activities:
Net income $618,299 $ 611,005 $ 560,094
Adjustments to reconcile net income
to net cash provided from operating activities --
Depreciation and amortization 411,435 697,143 712,960
Deferred income taxes and investment tax credits, net 65,550 (48,329) (28,961)
Pension, postretirement, and other employee benefits (76,700) (57,239) (61,825)
Other, net (38,353) (43,458) 10,324
Changes in certain current assets and liabilities --
Receivables, net 68,527 60,914 (108,621)
Fossil fuel stock 82,711 (103,296) 26,835
Materials and supplies 15,874 (15,628) (9,715)
Other current assets (18,880) 3,755 (9,282)
Accounts payable 64,902 (15,406) 64,412
Taxes accrued (6,540) 18,392 7,334
Other current liabilities 16,166 (46,691) (102,379)
- -----------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities 1,202,991 1,061,162 1,061,176
- -----------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (883,968) (1,389,751) (1,078,163)
Cost of removal net of salvage (60,912) (50,093) 3,247
Sales of property 387,212 534,760 -
Other 27,169 45,319 (8,697)
- -----------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities (530,499) (859,765) (1,083,613)
- -----------------------------------------------------------------------------------------------------------------------------
Financing Activities:
(Decrease) increase in notes payable, net (389,860) 43,698 67,598
Proceeds --
Senior notes 500,000 600,000 300,000
Pollution control bonds - 404,535 78,725
Preferred securities 740,000 - -
Capital contributions from parent company 173,483 225,060 301,514
Redemptions --
First mortgage bonds (1,860) (390,140) (100,000)
Pollution control bonds (7,800) (385,035) (78,725)
Senior notes (330,000) - -
Preferred securities (589,250) - -
Preferred stock - - (383)
Capital distributions to parent company (200,000) (160,000) -
Payment of preferred stock dividends (721) (578) (751)
Payment of common stock dividends (542,900) (527,300) (549,600)
Other (29,971) (17,747) (1,231)
- -----------------------------------------------------------------------------------------------------------------------------
Net cash (used for) provided from financing activities (678,879) (207,507) 17,147
- -----------------------------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents (6,387) (6,110) (5,290)
Cash and Cash Equivalents at Beginning of Period 23,260 29,370 34,660
- -----------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ 16,873 $ 23,260 $ 29,370
=============================================================================================================================
Supplemental Cash Flow Information:
Cash paid during the period for --
Interest (net of $9,368, $38,331, and $23,152 capitalized
for 2002, 2001, and 2000, respectively) $203,707 $234,456 $265,373
Income taxes (net of refunds) 281,661 381,995 392,310
- -----------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
II-112
BALANCE SHEETS
At December 31, 2002 and 2001
Georgia Power Company 2002 Annual Report
- ------------------------------------------------------------------------------------------------------------------------------
Assets 2002 2001
- ------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Current Assets:
Cash and cash equivalents $ 16,873 $ 23,260
Receivables --
Customer accounts receivable 302,995 271,728
Unbilled revenues 104,454 104,594
Under recovered regulatory clause revenues 117,580 161,462
Other accounts and notes receivable 122,585 129,073
Affiliated companies 40,501 87,786
Accumulated provision for uncollectible accounts (5,825) (8,895)
Fossil fuel stock, at average cost 120,048 202,759
Materials and supplies, at average cost 263,364 279,237
Other 96,922 125,246
- ------------------------------------------------------------------------------------------------------------------------------
Total current assets 1,179,497 1,376,250
- ------------------------------------------------------------------------------------------------------------------------------
Property, Plant, and Equipment:
In service 17,222,661 16,886,399
Less accumulated provision for depreciation 7,333,529 7,243,209
- ------------------------------------------------------------------------------------------------------------------------------
9,889,132 9,643,190
Nuclear fuel, at amortized cost 119,588 112,771
Construction work in progress 667,581 883,285
- ------------------------------------------------------------------------------------------------------------------------------
Total property, plant, and equipment 10,676,301 10,639,246
- ------------------------------------------------------------------------------------------------------------------------------
Other Property and Investments:
Equity investments in unconsolidated subsidiaries 36,167 35,209
Nuclear decommissioning trusts 346,870 364,180
Other 28,612 29,618
- ------------------------------------------------------------------------------------------------------------------------------
Total other property and investments 411,649 429,007
- ------------------------------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets:
Deferred charges related to income taxes 524,510 543,584
Prepaid pension costs 341,944 273,405
Unamortized debt issuance expense 67,362 58,165
Unamortized premium on reacquired debt 178,590 173,724
Other 162,686 117,706
- ------------------------------------------------------------------------------------------------------------------------------
Total deferred charges and other assets 1,275,092 1,166,584
- ------------------------------------------------------------------------------------------------------------------------------
Total Assets $13,542,539 $13,611,087
==============================================================================================================================
The accompanying notes are an integral part of these financial statements.
II-113
BALANCE SHEETS
At December 31, 2002 and 2001
Georgia Power Company 2002 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------
Liabilities and Stockholder's Equity 2002 2001
- ----------------------------------------------------------------------------------------------------------------------------
(in thousands)
Current Liabilities:
Securities due within one year $ 322,125 $ 311,620
Notes payable 357,677 747,537
Accounts payable --
Affiliated 135,260 109,591
Other 445,220 409,253
Customer deposits 94,859 83,172
Taxes accrued --
Income taxes 20,245 35,247
Other 134,269 125,807
Interest accrued 59,608 46,942
Vacation pay accrued 42,442 41,830
Other 112,131 120,980
- ----------------------------------------------------------------------------------------------------------------------------
Total current liabilities 1,723,836 2,031,979
- ----------------------------------------------------------------------------------------------------------------------------
Long-term debt (See accompanying statements) 3,109,619 2,961,726
- ----------------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 2,176,438 2,163,959
Deferred credits related to income taxes 208,410 229,216
Accumulated deferred investment tax credits 324,994 337,482
Employee benefits provisions 236,486 244,647
Other 373,740 440,774
- ----------------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 3,320,068 3,416,078
- ----------------------------------------------------------------------------------------------------------------------------
Company obligated mandatorily redeemable preferred
securities of subsidiary trusts holding company junior
subordinated notes (See accompanying statements) 940,000 789,250
- ----------------------------------------------------------------------------------------------------------------------------
Preferred stock (See accompanying statements) 14,569 14,569
- ----------------------------------------------------------------------------------------------------------------------------
Common stockholder's equity (See accompanying statements) 4,434,447 4,397,485
- ----------------------------------------------------------------------------------------------------------------------------
Total Liabilities and Stockholder's Equity $13,542,539 $13,611,087
============================================================================================================================
Commitments and Contingent Matters (See notes)
- ----------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
II-114
STATEMENTS OF CAPITALIZATION
At December 31, 2002 and 2001
Georgia Power Company 2002 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------------
2002 2001 2002 2001
- -----------------------------------------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
Long-Term Debt:
First mortgage bonds --
Maturity Interest Rates
------- --------------
2005 6.07% $ - $ 1,860
- --------------------------------------------------------------------------------------------------------
Total first mortgage bonds - 1,860
- --------------------------------------------------------------------------------------------------------
Long-term notes payable --
Variable rate (1.98125% at 1/1/02) due February 22, 2002 - 300,000
5.25% to 5.75% due 2003 320,000 350,000
5.50% due December 1, 2005 150,000 150,000
6.20% due February 1, 2006 150,000 150,000
4.875% due July 15, 2007 300,000 -
5.125% to 6.875% due 2011-2047 745,000 545,000
- --------------------------------------------------------------------------------------------------------
Total long-term notes payable 1,665,000 1,495,000
- --------------------------------------------------------------------------------------------------------
Other long-term debt --
Pollution control revenue bonds --
Collateralized: 6.00% to 6.25% due 2018-2019 - 7,800
Non-collateralized:
1.75% to 5.45% due 2012-2034 751,760 701,760
Variable rates (1.30% to 2.50% at 1/1/03)
due 2011-2032 934,130 984,130
- --------------------------------------------------------------------------------------------------------
Total other long-term debt 1,685,890 1,693,690
- --------------------------------------------------------------------------------------------------------
Capitalized lease obligations 81,411 83,371
- --------------------------------------------------------------------------------------------------------
Unamortized debt premium (discount), net (557) (575)
- --------------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
requirement -- $179.6 million) 3,431,744 3,273,346
Less amount due within one year 322,125 311,620
- -----------------------------------------------------------------------------------------------------------------------------------
Long-term debt excluding amount due within one year $3,109,619 $2,961,726 36.5% 36.3%
- -----------------------------------------------------------------------------------------------------------------------------------
Company Obligated Mandatorily
Redeemable Preferred Securities
$25 liquidation value --
4.875% $300,000 $ -
6.85% 200,000 200,000
7.125% 440,000 -
7.60% - 175,000
7.75% - 414,250
- -----------------------------------------------------------------------------------------------------------------------------------
Total (annual distribution requirement -- $59.1 million) 940,000 789,250 11.1 9.6
- -----------------------------------------------------------------------------------------------------------------------------------
Cumulative Preferred Stock:
$100 stated value at 4.60% 14,569 14,569
- -----------------------------------------------------------------------------------------------------------------------------------
Total (annual dividend requirement -- $0.7 million) 14,569 14,569
Less amount due within one year - -
- -----------------------------------------------------------------------------------------------------------------------------------
Total excluding amount due within one year 14,569 14,569 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 2,156,040 2,182,557
Premium on preferred stock 40 40
Retained earnings 1,945,520 1,870,791
Accumulated other comprehensive income (loss) (11,403) (153)
- -----------------------------------------------------------------------------------------------------------------------------------
Total common stockholder's equity 4,434,447 4,397,485 52.2 53.9
- -----------------------------------------------------------------------------------------------------------------------------------
Total Capitalization $8,498,635 $8,163,030 100.0% 100.0%
===================================================================================================================================
The accompanying notes are an integral part of these financial statements.
II-115
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
For the Years Ended December 31, 2002, 2001, and 2000
Georgia Power Company 2002 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------------
Premium on Other
Common Paid-In Preferred Retained Comprehensive
Stock Capital Stock Earnings Income (loss) Total
- -----------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Balance at December 31, 1999 $344,250 $1,815,983 $40 $1,777,937 $ - $3,938,210
Net income after dividends on preferred stock - - - 559,420 - 559,420
Capital contributions from parent company - 301,514 - - - 301,514
Cash dividends on common stock - - - (549,600) - (549,600)
- ----------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2000 344,250 2,117,497 40 1,787,757 - 4,249,544
Net income after dividends on preferred stock - - - 610,335 - 610,335
Capital distributions to parent company - (160,000) - - (160,000)
Capital contributions from parent company - 225,060 - - - 225,060
Other comprehensive income (loss) - - - - (153) (153)
Cash dividends on common stock - - - (527,300) - (527,300)
Preferred stock transactions, net - - - (1) - (1)
- ----------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2001 344,250 2,182,557 40 1,870,791 (153) 4,397,485
Net income after dividends on preferred stock - - - 617,629 - 617,629
Capital contributions from parent company - 173,483 - - - 173,483
Capital distributions to parent company - (200,000) - - - (200,000)
Other comprehensive income (loss) - - - - (11,250) (11,250)
Cash dividends on common stock - - - (542,900) - (542,900)
- ----------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2002 $344,250 $2,156,040 $40 $1,945,520 $(11,403) $4,434,447
==================================================================================================================================
The accompanying notes are an integral part of these financial statements.
STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2002, 2001, and 2000
Georgia Power Company 2002 Annual Report
- ---------------------------------------------------------------------------------------------------------------------------
2002 2001 2000
- ---------------------------------------------------------------------------------------------------------------------------
(in thousands)
Net income after dividends on preferred stock $617,629 $610,335 $559,420
- ---------------------------------------------------------------------------------------------------------------------------
Other comprehensive income (loss):
Change in additional minimum pension liability, net of tax of
$(4,853) (7,693) - -
Change in fair value of marketable securities, net of tax of $(97) 153 - -
Cumulative effect of accounting change for qualifying hedges, net of
tax of $180 - 286 -
Changes in fair value of qualifying hedges, net of tax of
$(2,599), $(277), respectively (3,708) (439) -
Less: Reclassification adjustment for amounts included in net
income (2) - -
- ---------------------------------------------------------------------------------------------------------------------------
Total other comprehensive income (loss) (11,250) (153) -
- ---------------------------------------------------------------------------------------------------------------------------
Comprehensive Income $606,379 $610,182 $559,420
===========================================================================================================================
The accompanying notes are an integral part of these financial statements.
II-116
NOTES TO FINANCIAL STATEMENTS
Georgia Power Company 2002 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING
POLICIES
General
The Company is a wholly owned subsidiary of Southern Company, which is the
parent company of five operating companies, Southern Power Company (Southern
Power), a system service company (SCS), Southern Communications Services
(Southern LINC), Southern Company Gas (Southern GAS), Southern Company Holdings
(Southern Holdings), Southern Nuclear Operating Company (Southern Nuclear),
Southern Telecom, and other direct and indirect subsidiaries. The operating
companies -- Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and
Savannah Electric -- provide electric service in four southeastern states.
Southern Power constructs, owns, and manages Southern Company's competitive
generation assets and sells electricity at market-based rates in the wholesale
market. Contracts among the operating companies and Southern Power -- related to
jointly owned generating facilities, interconnecting transmission lines, or the
exchange of electric power -- are regulated by the Federal Energy Regulatory
Commission (FERC) and/or the Securities and Exchange Commission. SCS provides,
at cost, specialized services to Southern Company and 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 Telecom provides fiber cable services within the Southeast. Southern
GAS, which began operation in August 2002, is a competitive retail natural gas
marketer serving communities in Georgia. Southern Holdings is an intermediate
holding subsidiary for Southern Company's investments in leveraged leases,
alternative fuel products, and an energy services business. Southern Nuclear
provides services to Southern Company's nuclear power plants.
Southern Company is registered as a holding company under the Public
Utility Holding Company Act of 1935 (PUHCA). Both Southern Company and its
subsidiaries are subject to the regulatory provisions of the PUHCA. The Company
is also subject to regulation by the FERC and the Georgia Public Service
Commission (GPSC). The Company follows accounting principles generally accepted
in the United States and complies with the accounting policies and practices
prescribed by the respective regulatory commissions. The preparation of
financial statements in conformity with accounting principles generally accepted
in the United States 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.
Affiliate Transactions
The Company has an agreement with SCS under which the following services are
rendered to the Company at direct or allocated cost: general and design
engineering, purchasing, accounting and statistical analysis, finance and
treasury, tax, information resources, marketing, auditing, insurance and pension
administration, human resources, systems and procedures, and other services with
respect to business and operations and power pool operations. Costs for these
services amounted to $318 million in 2002, $286 million in 2001, and $266
million in 2000. Cost allocation methodologies used by SCS are approved by the
SEC and management believes they are reasonable.
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, 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 $301 million in 2002, $281 million in 2001, and $281
million in 2000.
The Company has an agreement with Southern Power under which the Company
operates and maintains Southern Power owned plants Dahlberg, Franklin, and
Wansley at cost. Collections from these agreements with Southern Power amounted
to $5.3 million in 2002 and $1.0 million in 2001. These agreements arose from
the transfer of certain generation facilities to Southern Power in 2001 and
2002. See Note 4 under "Construction Program" for additional information.
Effective June 2002, the Company entered into purchased power agreements
with Southern Power for capacity and energy. Purchased power costs in 2002
amounted to $128 million. Additionally, the Company recorded $12 million of
II-117
NOTES (continued)
Georgia Power Company 2002 Annual Report
prepaid capacity expenses included in Other Deferred Charges and Other Assets on
the balance sheet at December 31, 2002. See Note 4 under "Purchased Power
Commitments" for additional information.
The Company has an agreement with Gulf Power under which Gulf Power jointly
owns a portion of Plant Scherer. Under this agreement, Georgia Power operates
Plant Scherer and Gulf Power reimburses the Company for its proportionate share
of the related expenses which were $4.5 million in 2002. Georgia Power has an
agreement with Savannah Electric under which Georgia Power jointly owns a
portion of Plant McIntosh. Under this agreement, Savannah Electric operates
Plant McIntosh and Georgia Power reimburses Savannah Electric for its
proportionate share of the related expenses which were $1.8 million in 2002. See
Note 6 for additional information.
The operating companies, including Georgia Power, Southern Power, and
Southern GAS may jointly enter into various types of wholesale energy, natural
gas and certain other contracts, either directly or through SCS as agent. Each
participating company may be jointly and severally liable for the obligations
incurred under these agreements. See Note 4 under "Fuel Commitments" and
"Purchased Power Commitments" for additional information.
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. See Note 3 under "Retail Rate Orders"
for additional information regarding the disposition of the regulatory liability
for the accelerated cost recovery recorded under the retail rate order that
ended December 31, 2001. Regulatory assets and (liabilities) reflected in the
Company's Balance Sheets at December 31 relate to the following:
2002 2001
---------------------
(in millions)
Deferred income tax charges $ 525 $ 544
Deferred income tax credits (208) (229)
Premium on reacquired debt 179 174
Corporate building lease 54 54
Vacation pay 54 52
Postretirement benefits 25 28
Department of Energy assessments 16 18
Generating plant outage costs 48 24
Accelerated cost recovery (222) (336)
Environmental remediation reserve (21) -
Purchased power (63) -
Other regulatory assets 7 17
Other regulatory liabilities (1) (1)
- --------------------------------------------------------------
Total $ 393 $ 345
==============================================================
See "Depreciation and Nuclear Decommissioning" in this note for information
regarding significant regulatory assets and liabilities created as a result of
the January 1, 2003 adoption of FASB Statement No. 143, Accounting for Asset
Retirement Obligations.
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 if
impaired, write down the assets to their fair value. All regulatory assets and
liabilities are reflected in rates.
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 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 despite an
increase in customer bankruptcies.
Revenues are recognized as services are rendered. Unbilled revenues are
accrued at the end of each fiscal period. Fuel costs are expensed as the fuel is
used. The Company's fuel cost recovery mechanism includes provisions to adjust
revenues for fluctuations in fuel costs, fuel hedging, the energy component of
II-118
NOTES (continued)
Georgia Power Company 2002 Annual Report
purchased power costs, and certain other costs. Revenues are adjusted for
differences between recoverable fuel costs and amounts actually recovered in
current rates.
Fuel expense includes the amortization of the cost of nuclear fuel and a
charge, based on nuclear generation, for the permanent disposal of spent nuclear
fuel. Total charges for nuclear fuel included in fuel expense amounted to $71
million in 2002, $75 million in 2001, and $75 million in 2000. The Company has
contracts with the U.S. Department of Energy (DOE) that provide for the
permanent disposal of used nuclear fuel. The DOE failed to begin disposing of
used nuclear fuel in January 1998 as required by the contracts, and the Company
is pursuing legal remedies against the government for breach of contract.
Sufficient pool storage capacity is available at Plant Vogtle to maintain
full-core discharge capability for both units until the year 2014. To maintain
pool discharge capability at Plant Hatch, effective June 2000, an on-site dry
storage facility for Plant Hatch became operational. Sufficient dry storage
capacity is believed to be available to continue dry storage operations at Plant
Hatch through the life of the plant. Procurement of on-site dry storage capacity
at Plant Vogtle will commence in sufficient time to maintain pool full-core
discharge capability.
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. The 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 -- based on
its ownership interests -- estimates its remaining liability at December 31,
2002 under this law to be approximately $13 million. This obligation is recorded
in other deferred credits 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
2.9 percent in 2002 and 3.3 percent in 2001 and 2000. The composite depreciation
rate was reduced because the lives of depreciable assets were extended effective
January 2002 under the retail rate order. When property subject to depreciation
is retired or otherwise disposed of in the normal course of business, its
original cost -- together with the cost of removal, less salvage -- is charged
to accumulated depreciation. Minor items of property included in the original
cost of the plant are retired when the related property unit is retired.
In January 2003, the Company adopted FASB Statement No. 143, Accounting for
Asset Retirement Obligations. Statement No. 143 establishes new accounting and
reporting standards for legal obligations associated with the ultimate cost of
retiring long-lived assets. The present value of the ultimate costs for an
asset's future retirement must be recorded in the period in which the liability
is incurred. The cost must be capitalized as part of the related long-lived
asset and depreciated over the asset's useful life.
There was no cumulative effect adjustment to net income resulting from the
adoption of Statement No. 143. The Company received permission from the GPSC to
defer the transition adjustment, therefore, the Company recorded a related
regulatory asset of $21 million to reflect the regulatory treatment of these
costs under Statement No. 71 as of January 2003. The initial Statement No. 143
liability the Company recognized was $469 million, of which $332 million was
removed from the accumulated depreciation reserve. The amount capitalized to
property, plant, and equipment was $116 million.
The liability recognized to retire long-lived assets primarily relates to the
Company's nuclear facilities, which include the Company's ownership interests in
plants Hatch and Vogtle. In addition, the Company has retirement obligations
related to various landfill sites, ash ponds, and underground storage tanks. The
Company has also identified retirement obligations related to certain
transmission and distribution facilities, leasehold improvements, equipment on
customer property, and property associated with Georgia Power rail lines.
However, a liability for the removal of these facilities will not be recorded
because no reasonable estimate can be made regarding the timing of any related
retirements. The Company will continue to recognize in the Statements of Income
the ultimate removal costs in accordance with respective regulatory treatment.
Any difference between costs recognized under Statement No. 143 and those
reflected in rates will be recognized as either a regulatory asset or liability.
II-119
NOTES (continued)
Georgia Power Company 2002 Annual Report
It is estimated that this annual difference will be approximately $23 million.
Management believes actual asset removal costs will be recoverable in rates over
time.
Statement No. 143 does not permit non-regulated companies to continue
accruing future retirement costs for long-lived assets they do not have a legal
obligation to retire. However, in accordance with the regulatory treatment of
these costs, the Company will continue to recognize the removal costs for these
other obligations in the depreciation rates. As of January 1, 2003, the amount
included in the accumulated depreciation reserve that represents a regulatory
liability for these costs was $419 million.
The Company recorded accelerated depreciation and amortization amounting to
$91 million in 2001 and $135 million in 2000. Effective January 2002, the
Company discontinued recording accelerated depreciation and amortization in
accordance with the retail rate order. Also, the Company was ordered to amortize
$333 million -- the cumulative balance previously expensed -- equally over three
years as a credit to depreciation and amortization expense beginning January
2002. See Note 3 under "Retail Rate Orders" for additional information.
The Nuclear Regulatory Commission (NRC) regulations require all licensees
operating commercial power reactors to establish a plan for providing, with
reasonable assurance, funds for decommissioning. The Company has established
external trust funds to comply with the NRC's regulations. Earnings on the trust
funds are considered in determining decommissioning expense. Amounts previously
recorded in internal reserves are being transferred into the external trust
funds over periods approved by the GPSC. The NRC's minimum external funding
requirements are based on a generic estimate of the cost to decommission the
radioactive portions of a nuclear unit based on the size and type of reactor.
The Company has filed plans with the NRC to ensure that -- over time -- the
deposits and earnings of the external trust funds will provide the minimum
funding amounts prescribed by the NRC.
The Company periodically conducts site-specific studies to estimate the
actual cost of decommissioning its nuclear generating facilities. 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 4.7 percent for the Company's
ownership interests are as follows:
Plant Plant
Hatch Vogtle
-------------------
Site study year 2000 2000
Decommissioning periods:
Beginning year 2014 2027
Completion year 2042 2045
- ------------------------------------------------------------
(in millions)
Site study costs:
Radiated structures $486 $420
Non-radiated structures 37 48
- ------------------------------------------------------------
Total $523 $468
============================================================
(in millions)
Ultimate costs:
Radiated structures $1,004 $1,468
Non-radiated structures 79 166
- ------------------------------------------------------------
Total $1,083 $1,634
============================================================
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, the NRC requirements, the assumptions used in making the
estimates, regulatory requirements, technology, and 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 2002 and fund
balances as of December 31, 2002 were:
Plant Plant
Hatch Vogtle
- ----------------------------------------------------------------
(in millions)
Amount expensed in 2002 $7 $2
================================================================
(in millions)
Accumulated provisions:
External trust funds, at fair value $219 $128
Internal reserves 7 4
- ----------------------------------------------------------------
Total $226 $132
================================================================
Effective January 1, 2002, the GPSC decreased the annual provision for
decommissioning expenses to $9 million. This amount is based on the NRC generic
estimate to decommission the radioactive portion of the facilities as of 2000.
The estimates are $383 million and $282 million for plants Hatch and Vogtle,
II-120
NOTES (continued)
Georgia Power Company 2002 Annual Report
respectively. The ultimate costs associated with the 2000 NRC minimum funding
requirements are $823 million and $1.03 billion for plants Hatch and Vogtle,
respectively. Significant assumptions include an estimated inflation rate of 4.7
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.
In January 2002, the NRC granted the Company a 20-year extension of the
licenses for both units at Plant Hatch which permits the operation of units 1
and 2 until 2034 and 2038, respectively. Decommissioning costs will not reflect
the license extension until a new site study is completed in 2003 and the GPSC
issues a new rate order, which is not expected until 2004.
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) and Interest Capitalized
AFUDC represents the estimated debt and equity costs of capital funds that are
necessary to finance the construction of new regulated 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. Interest related to the construction of new facilities not
included in the Company's retail rates is capitalized in accordance with
standard interest capitalization requirements. For the years 2002, 2001, and
2000, the average AFUDC rates were 3.79 percent, 6.33 percent, and 6.74 percent,
respectively. AFUDC and interest capitalized, net of taxes, as a percentage of
net income after dividends on preferred stock, was less than 3.0 percent for
2002, 2001, and 2000.
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 interest capitalized
and/or estimated cost of funds used during construction.
The cost of replacements of property (exclusive of minor items of property)
is capitalized. The cost of maintenance, repairs, and replacement of minor items
of property is charged to maintenance expense as incurred or performed with the
exception of certain generating plant maintenance costs. In accordance with a
GPSC order, the Company defers and amortizes nuclear refueling costs over the
unit's operating cycle before the next refueling. The refueling cycles range
from 18 to 24 months for each unit. In accordance with the 2001 retail rate
order, the Company defers the costs of certain significant inspection costs for
the combustion turbines at Plant McIntosh and amortizes such costs over 10
years, which approximates the expected maintenance cycle.
Impairment of Long-Lived Assets and Intangibles
The Company evaluates long-lived assets for impairment 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
either a specific regulatory disallowance or an estimate of undiscounted future
cash flows attributable to the assets, as compared with 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
the 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 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.
II-121
NOTES (continued)
Georgia Power Company 2002 Annual Report
Stock Options
Southern Company provides non-qualified stock options to a large segment of the
Company's employees ranging from line management to executives. The Company
accounts for its stock-based compensation plans in accordance with Accounting
Principles Board Opinion No. 25. Accordingly, no compensation expense has been
recognized because the exercise price of all options granted equaled the fair
market value on the date of grant. When options are exercised, the Company
receives a capital contribution from Southern Company equivalent to the related
income tax benefit.
Comprehensive Income
Comprehensive income -- consisting of net income, changes in the fair values of
marketable securities and qualifying cash flow hedges, and changes in additional
minimum pension liabilities, net of income taxes less reclassifications for
amounts included in net income -- is presented in the financial statements. The
objective of comprehensive income is to report a measure of all changes in
common stock equity of an enterprise that result from transactions and other
economic events of the period other than transactions with owners.
Financial Instruments
The Company uses derivative financial instruments to hedge exposures to
fluctuations in interest rates, the prices of certain fuel purchases and
electricity purchases and sales. All derivative financial instruments are
recognized as either assets or liabilities and are measured at fair value.
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 and its affiliates, through SCS acting as their agent, enter
into commodity related forward and option contracts to limit exposure to
changing prices on certain fuel purchases and electricity purchases and sales.
Substantially all of the Company's bulk energy purchases and sales contracts are
derivatives. However, these contracts qualify as normal purchases and sales and
are accounted for under the accrual method. Other contracts qualify as cash flow
hedges of anticipated transactions, resulting in the deferral of related gains
and losses in other comprehensive income until the hedged transactions occur.
Any ineffectiveness is recognized currently in net income. Contracts that do not
qualify for the normal purchase and sale exception and that do not meet the
hedge requirements are marked to market through current period income and are
recorded on a net basis in the Statements of Income.
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, 2002 $3,350 $3,417
At December 31, 2001 $3,190 $3,190
Preferred securities:
At December 31, 2002 $940 $961
At December 31, 2001 $789 $782
- --------------------------------------------------------------
The fair values for securities were based on either closing market prices
or closing prices of comparable instruments.
2. RETIREMENT BENEFITS
The Company has defined benefit, trusteed pension plans that cover substantially
all employees. The Company also provides certain non-qualified benefit plans for
a selected group of management and highly compensated employees. Also, the
Company provides certain medical care and life insurance benefits for retired
employees. The Company funds postretirement trusts to the extent required by the
GPSC and the FERC. In late 2000, as well as in 2002, the Company adopted several
pension and postretirement benefits plan changes that had the effect of
increasing benefits to both current and future retirees.
Plan assets consist primarily of domestic and international equities,
global fixed income securities, real estate, and private equity investments. The
measurement date for plan assets and obligations is September 30 for each year.
II-122
NOTES (continued)
Georgia Power Company 2002 Annual Report
Pension Plan
Changes during the year in the projected benefit obligations and in the fair
value of plan assets were as follows:
Projected
Benefit Obligation
-------------------------
2002 2001
- --------------------------------------------------------------
(in millions)
Balance at beginning of year $1,448 $1,322
Service cost 36 35
Interest cost 107 101
Benefits paid (74) (74)
Amendments 33 -
Actuarial loss 14 64
- --------------------------------------------------------------
Balance at end of year $1,564 $1,448
==============================================================
Plan Assets
------------------------
2002 2001
- -------------------------------------------------------------
(in millions)
Balance at beginning of year $2,044 $2,464
Actual return on plan assets (137) (356)
Benefits paid (69) (64)
- -------------------------------------------------------------
Balance at end of year $1,838 $2,044
=============================================================
The accrued pension costs recognized in the Balance Sheets
were as follows:
2002 2001
- -------------------------------------------------------------
(in millions)
Funded status $274 $ 596
Unrecognized transition obligation (17) (22)
Unrecognized prior service cost 123 98
Unrecognized net actuarial (loss) (78) (444)
- -------------------------------------------------------------
Prepaid asset, net 302 228
Portion included in
benefit obligations 40 45
- -------------------------------------------------------------
Total prepaid assets recognized in
the Balance Sheets $342 $ 273
=============================================================
In 2002 and 2001, amounts recognized in the Balance Sheets
for accumulated other comprehensive income and intangible assets
were $13 million and $10 million and $0 and $11 million, respectively.
Components of the plan's net periodic cost were as follows:
2002 2001 2000
- ---------------------------------------------------------------
(in millions)
Service cost $ 36 $ 35 $ 33
Interest cost 107 101 94
Expected return on plan assets (179) (168) (152)
Recognized net gain (27) (31) (26)
Net amortization 4 3 (1)
- ---------------------------------------------------------------
Net pension (income) $ (59) $ (60) $ (52)
===============================================================
Postretirement Benefits
Changes during the year in the accumulated benefit obligations and
in the fair value of plan assets were as follows:
Accumulated
Benefit Obligation
--------------------------
2002 2001
- ---------------------------------------------------------------
(in millions)
Balance at beginning of year $542 $495
Service cost 8 9
Interest cost 40 39
Benefits paid (27) (24)
Actuarial loss 64 23
- ---------------------------------------------------------------
Balance at end of year $627 $542
===============================================================
Plan Assets
---------------------------
2002 2001
- ----------------------------------------------------------------
(in millions)
Balance at beginning of year $195 $198
Actual return on plan assets (18) (26)
Employer contributions 49 47
Benefits paid (27) (24)
- ----------------------------------------------------------------
Balance at end of year $199 $195
================================================================
The accrued postretirement costs recognized in the Balance
Sheets were as follows:
2002 2001
- ---------------------------------------------------------------
(in millions)
Funded status $ (427) $ (347)
Unrecognized transition obligation 96 105
Unrecognized prior service cost 98 104
Unrecognized net loss 106 5
Fourth quarter contributions 37 27
- ---------------------------------------------------------------
Accrued liability recognized in the
Balance Sheets $ (90) $(106)
===============================================================
II-123
NOTES (continued)
Georgia Power Company 2002 Annual Report
Components of the plans' net periodic cost were as follows:
2002 2001 2000
- ---------------------------------------------------------------
(in millions)
Service cost $ 8 $ 9 $ 7
Interest cost 40 39 36
Expected return on plan assets (20) (19) (16)
Net amortization 15 14 12
- ---------------------------------------------------------------
Net postretirement cost $ 43 $ 43 $ 39
===============================================================
The weighted average rates assumed in the actuarial calculations
for both the pension and postretirement benefit plans were:
2002 2001 2000
- ---------------------------------------------------------------
Discount 6.5% 7.5% 7.5%
Annual salary increase 4.0 5.0 5.0
Long-term return on plan
assets 8.5 8.5 8.5
- ---------------------------------------------------------------
An additional assumption used in measuring the accumulated postretirement
benefit obligations was a weighted average medical care cost trend rate of 8.75
percent for 2002, decreasing gradually to 5.25 percent through the year 2010 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,
2002 as follows:
1 Percent 1 Percent
Increase Decrease
- ---------------------------------------------------------------
(in millions)
Benefit obligation $59 $52
Service and interest costs 5 4
===============================================================
Employee Savings Plan
The Company sponsors a 401(k) defined contribution plan covering substantially
all employees. The Company provides a 75 percent matching contribution up to 6
percent of an employee's base salary. Total matching contributions made to the
plan for the years 2002, 2001, and 2000 were $17 million, $16 million, and $15
million, respectively.
3. CONTINGENCIES AND REGULATORY
MATTERS
General Litigation Matters
The Company is subject to certain claims and legal actions arising in the
ordinary course of business. The Company's business activities are also subject
to extensive governmental regulation related to public health and the
environment. Litigation over environmental issues and claims of various types,
including property damage, personal injury, and citizen enforcement of
environmental requirements, has increased generally throughout the United
States. In particular, personal injury claims for damages caused by alleged
exposure to hazardous materials have become more frequent.
The ultimate outcome of such litigation currently filed against the Company
cannot be predicted at this time; however, after consultation with legal
counsel, management does not anticipate that the liabilities, if any, arising
from such proceedings would have a material adverse effect on the Company's
financial statements.
Retail Rate Orders
In December 2001, the GPSC approved a three-year retail rate order for the
Company ending December 31, 2004. Under the terms of the order, earnings will be
evaluated against a retail return on common equity range of 10 percent to 12.95
percent. Two-thirds of any earnings above the 12.95 percent return will be
applied to rate refunds, with the remaining one-third retained by the Company.
The Company's earnings in 2002 were within the common equity range. Retail rates
were decreased by $118 million effective January 1, 2002.
Under a previous three-year order ending December 2001, the Company's
earnings were evaluated against a retail return on common equity range of 10
percent to 12.5 percent. The order further provided 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 were applied to rate refunds, with the remaining one-third
retained by the Company. In 2000, the Company recorded $44 million of revenue
subject to refund for estimated earnings above 12.5 percent retail return on
common equity. Refunds applicable to 2000 were made to customers in 2001.
II-124
NOTES (continued)
Georgia Power Company 2002 Annual Report
Pursuant to the order, the Company recorded $333 million of accelerated
amortization and interest thereon, which has been credited to a regulatory
liability account as mandated by the GPSC.
Under the rate order, the accumulated accelerated amortization and the
interest are being amortized equally over three years as a credit to expense
beginning in 2002. Effective January 1, 2002, the Company discontinued recording
accelerated depreciation and amortization. Within the three-year period covered
by the rate order, the Company may 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, 2004, in
response to which the GPSC would be expected to determine whether the rate order
should be continued, modified, or discontinued.
Under GPSC ratemaking provisions, $21 million has been deferred in a
regulatory liability account for use in meeting future environmental remediation
costs.
Retail Fuel Hedging Program
On December 24, 2002, the GPSC approved an order, effective in January 2003,
allowing Georgia Power to implement a natural gas and oil procurement and
hedging program. This order allows the Company to use financial instruments in
implementing a hedging program. The order limits the program in terms of time,
volume, dollars, and physical amounts hedged. The costs of the program,
including any net losses, are recovered as a fuel cost through the fuel cost
recovery clause. Annual net financial gains from the hedging program will be
shared with the retail customers receiving 75 percent and Georgia Power
retaining 25 percent of the net gains.
New Source Review Enforcement Actions
In November 1999, the EPA brought a civil action in U.S. District Court in
Georgia. The complaint alleges violations of the 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 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 Company a notice of violation related to
the two plants mentioned previously. 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 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 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. As directed by the court, the EPA refiled its amended complaint limiting
claims to those brought against the Company.
The case against the Company has been stayed since the spring of 2001,
pending a ruling by the U.S. Court of Appeals for the Eleventh Circuit in the
appeal of a very similar New Source Review enforcement action against the
Tennessee Valley Authority (TVA). The TVA appeal involves many of the same legal
issues raised by the actions against the Company. Because the outcome of the TVA
appeal could have a significant adverse impact on Georgia Power, the Company has
been a party to that case as well. On August 21, 2002, the U.S. District Court
in Georgia denied the EPA's motion to reopen the Georgia case. The denial was
without prejudice to the EPA to refile the motion at a later date, which the EPA
has not done at this time.
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 in any one of these cases could require substantial
capital expenditures that cannot be determined at this time and could possibly
require payment of substantial penalties. This could affect future results of
operations, cash flows, and financial condition if such costs are not recovered
through regulated rates.
Plant Wansley Clean Air Act Litigation
On December 30, 2002, the Sierra Club, Physicians for Social Responsibility,
Georgia ForestWatch, and one individual filed a civil suit in the U.S. District
Court in Georgia against Georgia Power for alleged violations of the Clean Air
Act at Plant Wansley. The complaint alleges Clean Air Act violations at both the
existing coal-fired units and the new combined cycle units. Specifically, the
plaintiffs allege (1) opacity violations at the coal-fired units, (2) violations
II-125
NOTES (continued)
Georgia Power Company 2002 Annual Report
of a permit provision that requires the combined cycle units to operate above
certain levels, (3) violation of the nitrogen oxide emission offset
requirements, and (4) violation of the hazardous air pollutant requirements. The
civil action requests injunctive and declaratory relief, civil penalties, a
supplemental environmental project, and attorneys' fees. The Clean Air Act
authorizes civil penalties of up to $27,500 per day, per violation at each
generating unit.
On January 27, 2003, Georgia Power filed a response to the complaint. Georgia
Power also filed a motion to dismiss the allegations regarding emission offsets
and hazardous air pollutants. While Georgia Power believes that it has complied
with applicable laws and regulations, an adverse outcome could require payment
of substantial penalties. The final outcome of this matter cannot now be
determined.
Other Environmental Contingencies
The Company has been designated as a potentially responsible party at sites
governed by the Georgia Hazardous Site Response Act and/or by the federal
Comprehensive Environmental Response, Compensation and Liability Act. Georgia
Power has recognized $34 million in cumulative expenses through December 31,
2002 for the assessment and anticipated cleanup of sites on the Georgia
Hazardous Sites Inventory. In addition, in 1995 the EPA designated Georgia Power
and four other unrelated entities as potentially responsible parties at a site
in Brunswick, Georgia that is listed on the federal National Priorities List.
Georgia Power has contributed to the removal and remedial investigation and
feasibility study costs for the site. Additional claims for recovery of natural
resource damages at the site are anticipated. As of December 31, 2002, Georgia
Power had recorded approximately $6 million in cumulative expenses associated
with Georgia Power's agreed-upon share of the removal and remedial investigation
and feasibility study costs for the Brunswick site.
The final outcome of these matters cannot now be determined. However, based
on the currently known conditions at these sites and the nature and extent of
Georgia Power's activities relating to these sites, management does not believe
that the Company's additional liability, if any, at these sites would be
material to the financial statements.
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.
The GPSC has approved a performance award of approximately $7.8 million for
performance during the 1996-1998 period. This award was collected through the
retail fuel cost recovery provision and recognized in income over a 36-month
period that began in January 2000 as mandated by the GPSC.
For the period 1999-2001, the Company's performance fell within the
criteria prescribed by the GPSC. The Company will therefore not receive an award
or penalty for the 1999-2001 performance period.
Race Discrimination Litigation
In July 2000, a lawsuit alleging race discrimination was filed by three Georgia
Power employees against the Company, Southern Company, and SCS in the United
States District Court for the Northern District of Georgia. The lawsuit also
raised claims on behalf of a purported class. The plaintiffs seek compensatory
and punitive damages in an unspecified amount, as well as injunctive relief. In
August 2000, the lawsuit was amended to add four more plaintiffs. Also, Southern
Company Energy Solutions, a subsidiary of Southern Company, was named a
defendant.
In October 2001, the district court denied plaintiffs' motion for class
certification. The plaintiffs filed a motion to reconsider the order denying
class certification, and the court denied the plaintiffs' motion to reconsider.
In December 2001, the plaintiffs filed a petition in the United States Court of
Appeals for the Eleventh Circuit seeking permission to file an appeal of the
October 2001 decision, and this petition was denied. After discovery was
completed on the claims raised by the seven named plaintiffs, the defendants
filed motions for summary judgment on all of the named plaintiff's claims. The
II-126
NOTES (continued)
Georgia Power Company 2002 Annual Report
parties await the district court's ruling on the seven motions for summary
judgment. The final outcome of this matter cannot now be determined.
Right of Way Litigation
In 2002, Georgia Power was named as a defendant in several lawsuits brought by
landowners regarding the installation and use of fiber optic cable over
defendants' rights of way located on the landowners' property. The plaintiffs'
lawsuits claim that defendants may not use or sublease to third parties some or
all of the fiber optic communications lines on the rights of way that cross the
plaintiffs' properties and that such actions by defendants exceed the easements
or other property rights held by defendants. The plaintiffs assert claims for,
among other things, trespass and unjust enrichment. The plaintiffs seek
compensatory and punitive damages and injunctive relief. The Company believes
that the plaintiffs' claims are without merit. An adverse outcome could result
in substantial judgments; however, the final outcome of these matters cannot now
be determined.
4. COMMITMENTS
Construction Program
Significant construction of transmission and distribution facilities and
projects to remain in compliance with environmental requirements will continue.
The Company currently estimates property additions to be approximately $759
million, $781 million, and $806 million in 2003, 2004, and 2005, respectively.
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, 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, 2002, significant
purchase commitments were outstanding in connection with the construction
program.
Georgia Power had three generation projects under construction during 2001.
They included two units at Plant Dahlberg, a ten-unit, 800 megawatt combustion
turbine facility; two combined cycle units totaling 1,132 megawatts at Plant
Wansley; and Plant Franklin, a two-unit, 1,181 megawatt combined cycle facility.
All three of these projects have been transferred to Southern Power. The ten
Dahlberg units and two Franklin units were transferred in 2001 and the transfer
of the two Wansley units was completed in January 2002.
In connection with the transfer of plants Dahlberg, Franklin, and Wansley,
the Company has assigned $12 million in vendor equipment contracts to Southern
Power. While the Company could be obligated to assume responsibility for these
contracts if Southern Power fails to meet these commitments, Southern Company
has entered into limited keep-well arrangements whereby Southern Company would
contribute funds to Southern Power either through loans or capital contributions
in order to fund performance by Southern Power as equipment purchaser under
certain contingencies. Southern Company has also guaranteed Southern Power
obligations totaling $6.7 million for the Company's construction of transmission
interconnection facilities to these plants.
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,
2002 were as follows:
Minimum
Year Obligations
- ---- ------------------
(in millions)
2003 $1,097
2004 764
2005 657
2006 564
2007 465
2008 and beyond 1,236
- -----------------------------------------------------------
Total $4,783
===========================================================
Additional commitments for coal and for nuclear fuel will be required to
supply the Company's future needs.
In addition, SCS acts as agent for the five operating companies, Southern
Power, and Southern GAS with regard to natural gas purchases. Natural gas
purchases (in dollars) are based on various indices at the actual time of
delivery; therefore, only the volume commitments are firm and disclosed in the
following chart. The committed volumes, as of December 31, 2002, are as follows:
II-127
NOTES (continued)
Georgia Power Company 2002 Annual Report
Year Natural Gas
- ---- -------------------
(MMBtu)
2003 18,588,990
2004 17,306,665
2005 17,143,446
2006 12,785,477
2007 4,587,102
- ------------------------------------------------------------
Total 70,411,680
============================================================
Purchased Power Commitments
The Company and an affiliate, Alabama Power, own equally all of the outstanding
capital stock of Southern Electric Generating Company (SEGCO), which owns
electric generating units with a total rated capacity of 1,020 megawatts, as
well as associated transmission facilities. The capacity of the units has been
sold equally to the Company and Alabama Power under a contract which, in
substance, requires payments sufficient to provide for the operating expenses,
taxes, debt service, and return on investment, whether or not SEGCO has any
capacity and energy available. The term of the contract extends automatically
for two-year periods, subject to either party's right to cancel upon two year's
notice. The Company's share of expenses included in purchased power from
affiliates in the Statements of Income is as follows:
2002 2001 2000
---------------------------------
(in millions)
Energy $53 $52 $57
Capacity 32 30 30
- --------------------------------------------------------------
Total $85 $82 $87
==============================================================
The Company has commitments regarding a portion of a 5 percent interest in
Plant Vogtle owned by Municipal Electric Authority of Georgia (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, $59 million, and $58 million in 2002, 2001, and 2000,
respectively. The current projected Plant Vogtle capacity payments are:
Year Capacity Payments
- ---- ----------------------
(in millions)
2003 $ 59
2004 57
2005 56
2006 54
2007 54
2008 and beyond 423
- ----------------------------------------------------------------
Total $ 703
================================================================
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 capacity obligations at
December 31, 2002 were as follows:
Non-
Year Affiliateed Affiliated
- ---- ----------------------------
(in millions)
2003 $ 123 $ 41
2004 183 45
2005 255 78
2006 268 86
2007 268 87
2008 and beyond 1,800 564
- --------------------------------------------------------------
Total $2,897 $ 901
==============================================================
Acting as an agent for all of Southern Company's operating companies,
Southern Power, and Southern GAS, SCS may enter into various types of wholesale
energy and natural gas contracts. Each of the operating companies, Southern
Power, and Southern GAS may be jointly and severally liable under these
agreements. The creditworthiness of Southern Power and Southern GAS is currently
inferior to the creditworthiness of the operating companies. Southern Company
has entered into keep-well agreements with each of the operating companies to
insure they will not subsidize or be responsible for any costs, losses,
liabilities, or damages resulting from the inclusion of Southern Power or
Southern GAS as a contracting party under these agreements.
Operating Leases
The Company has entered into various operating leases with various terms and
expiration dates. Rental expenses related to these operating leases totaled $35
II-128
NOTES (continued)
Georgia Power Company 2002 Annual Report
million for 2002, $14 million for 2001, and $16 million for 2000. At December
31, 2002, estimated minimum rental commitments for these noncancelable operating
leases were as follows:
Minimum Obligations
Year Rail Cars Other Total
- ---- --------------------------------------
(in millions)
2003 $ 14 $ 16 $ 30
2004 14 14 28
2005 12 11 23
2006 13 8 21
2007 12 8 20
2008 and beyond 67 23 90
- ---------------------------------------------------------------
Total $ 132 $ 80 $ 212
===============================================================
In addition to the rental commitments above, the Company has obligations upon
expiration of certain of the rail car leases with respect to the residual value
of the leased property. These leases expire in 2004 and 2010, and the Company's
maximum obligations are $13 million and $40 million, respectively. At the
termination of the leases, at the Company's option, the Company may either
exercise its purchase option or the property can be sold to a third party. The
Company expects that the fair market value of the leased property would
substantially reduce or eliminate the Company's payments under the residual
value obligation. A portion of the railcar lease obligations is shared with the
joint owners of plants Scherer and Wansley. Rental expenses related to the
railcar leases are fully recoverable through the fuel cost recovery clause as
ordered by the GPSC.
Guarantees
Prior to 1999, a subsidiary of Southern Company originated loans to residential
customers of the Company for heat pump purchases. These loans were sold to
Fannie Mae with recourse for any loan with payments outstanding over 120 days.
The Company is responsible for the repurchase of customers' delinquent loans. As
of December 31, 2002, the outstanding loans guaranteed by the Company were $14
million and loan loss reserves of $3.4 million have been recorded.
Alabama Power 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 has agreed to reimburse Alabama Power for the pro rata portion of such
obligation corresponding to Georgia Power's then proportionate ownership of
stock of SEGCO if Alabama Power is called upon to make such payment under its
guaranty.
As discussed earlier in this note under "Operating Leases," the Company has
entered into certain residual value guarantees related to rail car leases.
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 $300 million by
American Nuclear Insurers (ANI), 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 additional costs that would be incurred in obtaining
replacement power during a prolonged accidental outage at a member's nuclear
plant. Members can purchase this coverage, subject to a deductible waiting
period of between 8 to 26 weeks, with a maximum per occurrence per unit limit of
$490 million. After this deductible period, weekly indemnity payments would be
received until either the unit is operational or until the limit is exhausted in
approximately three years. Georgia Power purchases the maximum limit allowed
by NEIL subject to ownership limitations and has elected a 12 week waiting
period.
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 $40 million.
II-129
NOTES (continued)
Georgia Power Company 2002 Annual Report
Following the terrorist attacks of September 2001, both ANI and NEIL
confirmed that terrorist acts against commercial nuclear power stations would be
covered under their insurance. Both companies, however, revised their policy
terms on a prospective basis to include an industry aggregate for all terrorist
acts. The NEIL aggregate, which applies to all claims stemming from terrorism
within a 12 month duration, is $3.24 billion plus any amounts that would be
available through reinsurance or indemnity from an outside source. The ANI cap
is a $300 million shared industry aggregate.
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.
6. JOINT OWNERSHIP AGREEMENTS
Except as otherwise noted, the Company has contracted to operate and maintain
all jointly owned generating facilities. Georgia Power owns undivided interests
in plants Vogtle, Hatch, Scherer, and Wansley in varying amounts jointly with
Oglethorpe Power Corporation (OPC), the Municipal Electric Authority of Georgia,
the city of Dalton, Georgia, Florida Power & Light Company (FP&L), Jacksonville
Electric Authority (JEA), and Gulf Power. Under these agreements, the Company is
jointly and severally liable for third party claims related to these plants. In
addition, 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 who operates the plant. The
Company and Florida Power Corporation (FPC) jointly own a combustion turbine
unit (Intercession City) operated by FPC.
The Company includes its proportionate share of plant operating expenses in
the corresponding operating expenses in the Statements of Income.
At December 31, 2002, 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% $3,267 $1,779
Plant Hatch (nuclear) 50.1 884 665
Plant Wansley (coal) 53.5 305 156
Plant Scherer (coal)
Units 1 and 2 8.4 113 58
Unit 3 75.0 554 234
Plant McIntosh
Common Facilities 75.0 24 3
(combustion-turbine)
Rocky Mountain 25.4 169 82
(pumped storage)
Intercession City 33.3 12 1
(combustion-turbine)
- --------------------------------------------------------------------
7. LONG-TERM POWER SALES AGREEMENTS
The Company and the other operating companies of Southern Company, except
Savannah Electric, 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 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)
2002 $34 102
2001 26 102
2000 30 124
-------------------------------------
II-130
NOTES (continued)
Georgia Power Company 2002 Annual Report
Unit power from specific generating plants is being sold to FP&L, FPC, and
JEA. Under these agreements, approximately 103 megawatts of capacity is
scheduled to be sold annually for periods after 2002 with a minimum of three
years notice until the expiration of the contracts in 2010.
8. INCOME TAXES
At December 31, 2002, tax-related regulatory assets were $525 million and
tax-related regulatory liabilities were $208 million. The assets are
attributable to tax benefits flowed through to customers in prior years and to
taxes applicable to capitalized interest. 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:
2002 2001 2000
-------------------------------
Total provision for income taxes: (in millions)
Federal:
Current $261 $352 $342
Deferred 60 (46) (34)
- -----------------------------------------------------------------
321 306 308
- -----------------------------------------------------------------
State:
Current 31 61 48
Deferred 5 (8) (5)
Deferred investment tax
credits - 5 10
- -----------------------------------------------------------------
Total $357 $364 $361
===============================-=================================
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:
2002 2001
-------------------
(in millions)
Deferred tax liabilities:
Accelerated depreciation $1,779 $1,722
Property basis differences 623 660
Other 309 295
- -----------------------------------------------------------------
Total 2,711 2,677
- -----------------------------------------------------------------
Deferred tax assets:
Federal effect of state deferred taxes 90 88
Other property basis differences 170 178
Other deferred costs 214 257
Other 64 40
- -----------------------------------------------------------------
Total 538 563
- -----------------------------------------------------------------
Net deferred tax liabilities 2,173 2,114
Portion included in current assets 3 50
- ----------------------------------------------------------------
Accumulated deferred income taxes
in the Balance Sheets $2,176 $2,164
================================================================
In accordance with regulatory requirements, deferred investment tax credits
are amortized over the life of the related property with such amortization
normally applied as a credit to reduce depreciation in the Statements of Income.
Credits amortized in this manner amounted to $12 million in 2002 and $15 million
in both 2001 and 2000. At December 31, 2002, 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:
2002 2001 2000
-------------------------
Federal statutory rate 35% 35% 35%
State income tax, net of
federal deduction 2 4 4
Non-deductible book
depreciation 1 2 2
Other (1) (4) (2)
- --------------------------------------------------------------
Effective income tax rate 37% 37% 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. In
accordance with Internal Revenue Service regulations, each company is jointly
and severally liable for the tax liability.
II-131
NOTES (continued)
Georgia Power Company 2002 Annual Report
9. CAPITALIZATION
First Mortgage Bond Indenture
In 2002, the first mortgage bond indenture of Georgia Power was defeased by
paying to JPMorgan Chase Bank, the Trustee, an amount representing the last
outstanding obligations on the Company's first mortgage bonds. As a result of
the defeasance, there are no longer any first mortgage bond liens on the
Company's property and the Company no longer has to comply with the covenants
and restrictions of the first mortgage bond indenture.
Preferred Securities
Statutory trusts formed by the Company, of which the Company owns all the common
securities, have issued mandatorily redeemable preferred securities. The
following securities are currently outstanding:
Date of Maturity
Issue Amount Rate Notes Date
---------------------------------------------------------
(millions) % (millions)
Trust IV 2/1999 $200 6.850 $206 3/2029
Trust V 6/2002 440 7.125 454 3/2042
Trust VI 11/2002 300 4.875* 309 11/2042
* Issued at a five year initial fixed rate of 4.875 percent and, thereafter, at
fixed rates determined through remarketings for specific periods of varying
length or at floating rates determined by reference to 3-month LIBOR plus 3.05
percent.
The securities issued by Trusts I, II, and III were redeemed in 2002.
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.
Pollution Control Bonds
The Company has incurred obligations in connection with the sale by public
authorities of tax-exempt pollution control revenue bonds. The amount of
tax-exempt pollution control revenue bonds outstanding at December 31, 2002
was $1.7 billion.
Senior Notes
In 2002, the Company issued a total of $500 million of unsecured senior notes.
The proceeds of these issues were used to redeem higher cost long-term debt and
to reduce short-term borrowing.
Bank Credit Arrangements
At the beginning of 2003, the Company had unused credit arrangements with banks
totaling $1.175 billion expiring at April 18, 2003. Upon expiration, the $1.175
billion agreement provides the option of converting borrowings into a two-year
term loan. The agreement contains stated borrowing rates but also allows for
competitive bid loans. In addition, the agreement requires payment of commitment
fees based on the unused portions of the commitments or the maintenance of
compensating balances with the banks. Commitment fees are less than 1/8 of 1
percent for the Company. Compensating balances are not legally restricted from
withdrawal. An annual fee is also paid to the agent bank.
The credit arrangements contain covenants that limit the level of
indebtedness to capitalization to 65 percent. Not meeting these limits would
result in an event of default under the credit arrangements. In addition, the
credit arrangements contain cross default provisions to other indebtedness of
the Company that would trigger an event of default if the Company defaulted on
indebtedness over a specified threshold. The Company is currently in compliance
with all such covenants.
This $1.175 billion in unused credit arrangements provides liquidity
support to the Company's variable rate pollution control bonds. The amount of
variable rate pollution control bonds outstanding requiring liquidity support as
of December 31, 2002 was $422 million. In addition, the Company borrows under
uncommitted lines of credit with banks, through a $155 million extendible
commercial note program, and through a $750 million commercial paper program
that has the liquidity support of the committed bank credit arrangements. The
amount of extendible commercial notes and commercial paper outstanding at
II-132
NOTES (continued)
Georgia Power Company 2002 Annual Report
December 31, 2002 was $19 million and $358 million, respectively. The amount of
commercial paper outstanding at December 31, 2001 was $708 million. Commercial
paper is included in notes payable on the Balance Sheets.
Financial Instruments
The Company enters into interest rate swaps to hedge exposure to interest rate
changes. Swaps related to fixed rate securities are accounted for as fair value
hedges. Swaps related to variable rate securities or forecasted transactions are
accounted for as cash flow hedges. The swaps are generally structured to mirror
the terms of the hedged debt instruments; therefore, no material ineffectiveness
has been recorded in earnings. The gain or loss in fair value for cash flow
hedges is recorded in other comprehensive income and will be recognized in
earnings over the life of the hedged items. In 2002, the Company recognized
gains totaling $413 thousand upon settlement of certain cash flow hedges.
At December 31, 2002, the Company had interest rate swaps outstanding with
net deferred losses as follows:
Cash Flow Hedges
Weighted Average
Variable Fixed Fair
Rate Rate Notional Value
Maturity Received Paid Amount (Loss)
- ---------------------------------------------------------------
(in millions)
2003 * 4.76% $250 $(7)
*Rate has not been set
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, 2002 and 2001, the Company had a capitalized
lease obligation for its corporate headquarters building of $81 million with an
interest rate of 8.1 percent. 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 has been deferred and is being amortized to
expense as ordered by the GPSC. At both December 31, 2002 and 2001, the interest
and lease amortization deferred on the Balance Sheets was $54 million.
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:
2002 2001
------------------
(in millions)
Capital lease $ 2 $ 2
First mortgage bonds - 2
Pollution control bonds - 8
Senior notes 320 300
- ---------------------------------------------------------------
Total $322 $312
===============================================================
Serial maturities through 2007 applicable to total long-term debt are as
follows: $322 million in 2003; $2 million in 2004; $153 million in 2005; $153
million in 2006; and $303 million in 2007.
10. QUARTERLY FINANCIAL DATA
(UNAUDITED)
Summarized quarterly financial information for 2002 and 2001 is as follows:
Net Income
After
Operating Operating Dividends on
Quarter Ended Revenues Income Preferred Stock
- ---------------------------------------------------------------------
(in millions)
--------------------------------------------
March 2002 $ 1,007 $260 $127
June 2002 1,204 320 171
September 2002 1,517 498 271
December 2002 1,095 126 49
March 2001 $ 1,108 $249 $ 108
June 2001 1,259 322 163
September 2001 1,579 515 298
December 2001 1,020 126 41
- ---------------------------------------------------------------------
The Company's business is influenced by seasonal weather conditions.
II-133
SELECTED FINANCIAL AND OPERATING DATA 1998-2002
Georgia Power Company 2002 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------------
2002 2001 2000 1999 1998
- -----------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands) $4,822,460 $4,965,794 $4,870,618 $4,456,675 $4,738,253
Net Income after Dividends
on Preferred Stock (in thousands) $617,629 $610,335 $559,420 $541,383 $570,228
Cash Dividends
on Common Stock (in thousands) $542,900 $527,300 $549,600 $543,000 $536,600
Return on Average Common Equity (percent) 13.99 14.12 13.66 14.02 14.61
Total Assets (in thousands) $13,542,539 $13,611,087 $13,133,609 $12,361,860 $12,033,618
Gross Property Additions (in thousands) $883,968 $1,389,751 $1,078,163 $790,464 $499,053
- -----------------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $4,434,447 $4,397,485 $4,249,544 $3,938,210 $3,784,172
Preferred stock 14,569 14,569 14,569 14,952 15,527
Company obligated mandatorily
redeemable preferred securities 940,000 789,250 789,250 789,250 689,250
Long-term debt 3,109,619 2,961,726 3,041,939 2,688,358 2,744,362
- -----------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $8,498,635 $8,163,030 $8,095,302 $7,430,770 $7,233,311
===================================================================================================================================
Capitalization Ratios (percent):
Common stock equity 52.2 53.9 52.5 53.0 52.3
Preferred stock 0.2 0.2 0.2 0.2 0.2
Company obligated mandatorily
redeemable preferred securities 11.1 9.6 9.7 10.6 9.5
Long-term debt 36.5 36.3 37.6 36.2 38.0
- -----------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0 100.0 100.0 100.0
===================================================================================================================================
Security Ratings:
First Mortgage Bonds -
Moody's N/A A1 A1 A1 A1
Standard and Poor's N/A A A A+ A+
Fitch N/A AA- AA- AA- AA-
Preferred Stock -
Moody's Baa1 Baa1 a2 a2 a2
Standard and Poor's BBB+ BBB+ BBB+ A- A
Fitch 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
Fitch A+ A+ A+ A+ A+
===================================================================================================================================
Customers (year-end):
Residential 1,734,430 1,698,407 1,669,566 1,632,450 1,596,488
Commercial 250,993 244,674 237,977 229,524 221,180
Industrial 8,240 8,046 8,533 8,958 9,485
Other 3,328 3,239 3,159 3,060 3,034
- -----------------------------------------------------------------------------------------------------------------------------------
Total 1,996,991 1,954,366 1,919,235 1,873,992 1,830,187
===================================================================================================================================
Employees (year-end): 8,837 9,048 8,860 8,961 8,371
- -----------------------------------------------------------------------------------------------------------------------------------
N/A = Not Applicable.
II-134
SELECTED FINANCIAL AND OPERATING DATA 1998-2002 (continued)
Georgia Power Company 2002 Annual Report
- --------------------------------------------------------------------------------------------------------------------------------
2002 2001 2000 1999 1998
- --------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $ 1,600,438 $1,507,031 $ 1,535,684 $ 1,410,099 $ 1,486,699
Commercial 1,631,130 1,682,918 1,620,466 1,527,880 1,591,363
Industrial 1,004,288 1,106,420 1,154,789 1,143,001 1,170,881
Other 52,241 52,943 6,399 (30,892) 49,274
- --------------------------------------------------------------------------------------------------------------------------------
Total retail 4,288,097 4,349,312 4,317,338 4,050,088 4,298,217
Sales for resale - non-affiliates 270,678 366,085 297,643 210,104 259,234
Sales for resale - affiliates 98,323 99,411 96,150 76,426 81,606
- --------------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 4,657,098 4,814,808 4,711,131 4,336,618 4,639,057
Other revenues 165,362 150,986 159,487 120,057 99,196
- --------------------------------------------------------------------------------------------------------------------------------
Total $4,822,460 $4,965,794 $4,870,618 $4,456,675 $4,738,253
================================================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 22,144,559 20,119,080 20,693,481 19,404,709 19,481,486
Commercial 26,954,922 26,493,255 25,628,402 23,715,485 22,861,391
Industrial 25,739,785 25,349,477 27,543,265 27,300,355 27,283,147
Other 593,202 583,007 568,906 551,451 543,462
- --------------------------------------------------------------------------------------------------------------------------------
Total retail 75,432,468 72,544,819 74,434,054 70,972,000 70,169,486
Sales for resale - non-affiliates 8,069,375 8,110,096 6,463,723 5,060,931 6,438,891
Sales for resale - affiliates 3,962,559 3,133,485 2,435,106 1,795,243 2,038,400
- --------------------------------------------------------------------------------------------------------------------------------
Total 87,464,402 83,788,400 83,332,883 77,828,174 78,646,777
================================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 7.23 7.49 7.42 7.27 7.63
Commercial 6.05 6.35 6.32 6.44 6.96
Industrial 3.90 4.36 4.19 4.19 4.29
Total retail 5.68 6.00 5.80 5.71 6.13
Sales for resale 3.07 4.14 4.43 4.18 4.02
Total sales 5.32 5.75 5.65 5.57 5.90
Residential Average Annual
Kilowatt-Hour Use Per Customer 12,867 11,933 12,520 12,006 12,314
Residential Average Annual
Revenue Per Customer $929.90 $893.84 $929.11 $872.48 $939.73
Plant Nameplate Capacity
Ratings (year-end) (megawatts) 14,059 14,474 15,114 14,474 14,437
Maximum Peak-Hour Demand (megawatts):
Winter 11,873 11,977 12,014 11,568 11,959
Summer 14,597 14,294 14,930 14,575 13,923
Annual Load Factor (percent) 60.4 61.7 61.6 58.9 58.7
Plant Availability (percent):
Fossil-steam 80.9 88.5 86.1 84.3 86.0
Nuclear 88.8 94.4 91.5 89.3 91.6
- --------------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 59.5 58.5 62.3 63.0 62.3
Nuclear 16.2 18.1 17.4 18.0 18.3
Hydro 0.9 1.1 0.7 0.9 2.2
Oil and gas 0.3 0.4 1.8 1.6 2.2
Purchased power -
From non-affiliates 6.3 7.8 8.1 6.6 6.5
From affiliates 16.8 14.1 9.7 9.9 8.5
- --------------------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0 100.0 100.0
================================================================================================================================
II-135
GULF POWER COMPANY
FINANCIAL SECTION
II-136
MANAGEMENT'S REPORT
Gulf Power Company 2002 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 accounting principles generally
accepted in the United States 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 accounting 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.
Southern Company's audit committee of its board of directors, composed of
five independent directors, provides a broad overview of management's financial
reporting and control functions. Additionally, a committee of Gulf Power's board
of directors (composed of five outside directors) meets periodically with
management, the internal auditors, and the independent public accountants to
discuss auditing, internal controls, and compliance matters. The internal
auditors and independent public accountants have access to the members of these
committees 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 accounting principles generally
accepted in the United States.
/s/Thomas A. Fanning
Thomas A. Fanning
President
and Chief Executive Officer
/s/Ronnie R. Labrato
Ronnie R. Labrato
Vice President, Chief Financial Officer
and Comptroller
February 17, 2003
II-137
INDEPENDENT AUDITORS' REPORT
Gulf Power Company:
We have audited the accompanying balance sheet and statement of capitalization
of Gulf Power Company (a wholly owned subsidiary of Southern Company) as of
December 31, 2002, and the related statements of income, comprehensive income,
common stockholders' equity, and cash flows for the year then ended. These
financial statements are the responsibility of Gulf Power Company's management.
Our responsibility is to express an opinion on these financial statements based
on our audit. The financial statements of Gulf Power Company as of December 31,
2001, and for each of the two years then ended were audited by other auditors
who have ceased operations. Those auditors expressed an unqualified opinion on
those financial statements and included an explanatory paragraph that described
a change in the method of accounting for derivative instruments and hedging
activities in their report dated February 13, 2002.
We conducted our audit in accordance with auditing standards generally
accepted in the United States of America. 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 audit provides a
reasonable basis for our opinion.
In our opinion, the 2002 financial statements (pages II-152 to II-170)
present fairly, in all material respects, the financial position of Gulf Power
Company at December 31, 2002, and the results of its operations and its cash
flows for the year then ended in conformity with accounting principles
generally accepted in the United States of America.
/s/Deloitte & Touche LLP
February 17, 2003
Atlanta, Georgia
THE FOLLOWING REPORT OF INDEPENDENT ACCOUNTANTS IS A COPY OF THE REPORT
PREVIOUSLY ISSUED IN CONNECTION WITH THE COMPANY'S 2001 ANNUAL REPORT ON FORM
10-K AND HAS NOT BEEN REISSUED BY ARTHUR ANDERSEN LLP. SEE EXHIBIT 23(d)2 FOR
ADDITIONAL INFORMATION.
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, 2001 and 2000, 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, 2001. 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-129 through II-144)
referred to above present fairly, in all material respects, the financial
position of Gulf Power Company as of December 31, 2001 and 2000, and the results
of its operations and its cash flows for each of the three years in the period
ended December 31, 2001, in conformity with accounting principles generally
accepted in the United States.
As explained in Note 1 to the financial statements, effective January 1,
2001, Gulf Power Company changed its method of accounting for derivative
instruments and hedging activities.
/s/Arthur Andersen LLP
Atlanta, Georgia
February 13, 2002
II-138
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Gulf Power Company 2002 Annual Report
RESULTS OF OPERATIONS
Earnings
Gulf Power Company's 2002 net income after dividends on preferred stock was
$67.0 million, an increase of $8.7 million from the previous year. In 2001,
earnings were $58.3 million, up $6.5 million when compared to 2000. In 2000,
earnings were $51.8 million, down $1.9 million when compared with the prior
year. The improvement in earnings in 2002 is due primarily to higher operating
revenues related to an increase in base rates, offset somewhat by higher
operating expenses and higher financing costs primarily related to the
commercial operation of Plant Smith Unit 3 in April 2002. The increase in 2001
earnings was primarily a result of an increase in Allowance for Funds Used
During Construction (AFUDC) and lower interest expense. The decrease in 2000
earnings was primarily a result of expenses related to the discontinuance of the
Company's appliance sales division and higher interest expense. A condensed
income statement follows:
Increase (Decrease)
Amount From Prior Year
- ---------------------------------------------------------------
2002 2002 2001 2000
- ---------------------------------------------------------------
(in millions)
Operating revenues $820 $ 95 $ 11 $40
- ---------------------------------------------------------------
Fuel 274 73 (15) 7
Purchased power 63 (44) 24 26
Other operation
and maintenance 200 23 5 -
Depreciation
and amortization 77 9 1 2
Taxes other than
income taxes 61 6 (1) 4
- ---------------------------------------------------------------
Total operating
expenses 675 67 14 39
- ---------------------------------------------------------------
Operating income 145 28 (3) 1
Other income
and (expense) (41) (13) 10 (5)
Income taxes (37) (6) - 2
- ---------------------------------------------------------------
Net income $ 67 $ 9 $ 7 $ (2)
===============================================================
Revenues
Operating revenues increased in 2002 when compared to 2001 and 2000. The
following table summarizes the changes in operating revenues for the past three
years:
2002 2001 2000
-----------------------------------
(in thousands)
Retail - Prior Year $584,591 $548,640 $516,949
Change in -
Base Revenues 31,200 - (8,508)
Sales Growth 16,557 10,254 4,407
Weather 9,497 (5,699) 7,522
Fuel and other
cost recovery 23,991 31,396 28,270
- -----------------------------------------------------------------
Total retail 665,836 584,591 548,640
- -----------------------------------------------------------------
Sales for resale--
Non-affiliates 77,171 82,252 66,890
Affiliates 40,391 27,256 66,995
- -----------------------------------------------------------------
Total sales for resale 117,562 109,508 133,885
Other operating
revenues 37,069 31,104 31,794
- -----------------------------------------------------------------
Total operating
revenues $820,467 $725,203 $714,319
=================================================================
Percent change 13.1% 1.5% 6.0%
- -----------------------------------------------------------------
Retail revenues increased $81.2 million, or 13.9 percent in 2002, $36.0
million, or 6.6 percent in 2001, and $31.7 million, or 6.1 percent in 2000. The
significant factors driving these changes are shown in the table above. In
addition, see Note 3 to the financial statements under "Retail Revenue Sharing
Plan" for further information.
"Fuel and other cost recovery" includes: recovery provisions for fuel
expenses and the energy component of purchased power costs, energy conservation
costs, purchased power capacity costs, and environmental compliance costs.
Annually, the Company seeks recovery of projected costs plus any true-up amount
from prior periods. Approved rates are implemented each January. Therefore, 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 $117.6 million in 2002, an increase of $8.1 million, or
7.4 percent, from 2001 primarily due to increased energy sales for resale to
affiliates reflecting the commercial operation of the 574 MW Plant Smith Unit 3.
II-139
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2002 Annual Report
Sales for resale were $109.5 million in 2001, a decrease of $24.4 million, or
18.2 percent, from 2000 and $133.9 million in 2000, an increase of $5.4 million,
or 4.2 percent over 1999. These changes were primarily weather related. Sales to
affiliated companies vary from year to year depending on demand and the
availability and cost of generating resources at each company. These energy
sales do not have a significant impact on earnings.
Revenues from sales to utilities outside the service area under long-term
contracts consist of capacity and energy components. Capacity revenues reflect
the recovery of fixed costs and a return on investment under the contracts.
Energy is generally sold at variable cost. The capacity and energy components
under these long-term contracts were as follows:
2002 2001 2000
-----------------------------------
(in thousands)
Unit Power --
Capacity $19,898 $19,472 $20,270
Energy 28,565 27,579 21,922
- -------------------------------------------------------------
Total $48,463 $47,051 $42,192
=============================================================
Capacity revenues remained relatively unchanged during 2002, 2001, and 2000.
No significant declines in the amount of capacity are scheduled until the
termination of these contracts in 2010. See Note 6 to the financial statements
for additional information.
Other operating revenues for 2002 increased $6.0 million due primarily to a
$1.7 million settlement related to a power purchase agreement, a $3.3 million
increase in franchise fees, and $0.9 million increase in revenues from the
transmission of electricity to others.
Energy Sales
Kilowatt-hour sales for 2002 and the percent changes by year were as follows:
KWH Percent Change
------------------------------------------
2002 2002 2001 2000
------------------------------------------
(millions)
Residential 5,144 9.1% (1.5)% 7.1%
Commercial 3,553 4.0 1.2 4.9
Industrial 2,054 1.8 4.8 4.3
Other 21 - 10.5 -
-------
Total retail 10,772 5.9 0.6 5.8
Sales for resale
Non-affiliates 2,157 3.1 22.8 9.2
Affiliates 1,720 78.4 (49.8) (23.7)
-------
Total 14,649 10.7 (3.7) 0.7
==================================================================
The retail energy sales increases in 2002 and 2000 were primarily due to the
impact of weather on the residential and commercial sectors. An increase in
energy sales for resale to non-affiliates of 3.1 percent in 2002, 22.8 percent
in 2001, and 9.2% in 2000, is 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 depending on demand and availability
and cost of generating resources at each company.
Expenses
Total operating expenses in 2002 increased $67.0 million, or 11 percent, over
the amount recorded in 2001 due primarily to higher fuel and maintenance costs.
In 2001, total operating expenses increased $13.5 million, or 2.3 percent,
compared to 2000 due primarily to higher purchased power expenses and
maintenance expenses. In 2000, total operating expenses increased $39.5 million,
or 7.1 percent, from the prior year due primarily to higher fuel and purchased
power expenses.
Fuel expense in 2002, when compared to 2001, increased $73.2 million, or 36.5
percent, due primarily to the commercial operation of Plant Smith Unit 3
beginning in April 2002. In 2001, fuel expenses decreased $15.1 million, or 7.0
percent, when compared to 2000 as a result of decreased generation. In 2000,
fuel expenses increased $6.7 million, or 3.2 percent, as a result of an increase
in average fuel costs.
The amount and sources of generation and the average cost of fuel per net
kilowatt-hour generated were as follows:
2002 2001 2000
------------------------------
Total generation
(millions of kilowatt-hours) 13,142 11,423 12,866
Sources of generation (percent)
Coal 81.8 99.0 98.2
Gas 18.2 1.0 1.8
Average cost of fuel per net
kilowatt-hour generated
(cents)-- 2.08 1.76 1.68
- ------------------------------------------------------------- ----------
Purchased power expenses decreased in 2002 by $43.2 million, or 40.7 percent,
from 2001 primarily due to a decrease in purchased power from non-affiliated
companies. This decrease in expenses from non-affiliates is mainly attributable
II-140
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2002 Annual Report
to additional generating capacity within the Southern system in 2002 including
the Company's Plant Smith Unit 3. Purchased power expenses for 2001 increased
from 2000 by $23.8 million, or 28.8 percent, due primarily to an increase in
purchased power from affiliate companies. Purchased power expenses for 2000
increased by $25.5 million, or 44.7 percent, due primarily to a higher demand
for energy.
Purchases of energy from affiliates will vary from year to year depending on
demand and the availability and cost of generating resources at each company.
These purchases have little impact on earnings.
Depreciation and amortization expense increased $8.8 million, or 12.9
percent, in 2002 primarily due to the commercial operation of Plant Smith Unit 3
in April 2002. Depreciation and amortization expense increased $1.3 million, or
2.0 percent, in 2001 and $2.3 million, or 3.5 percent, in 2000 due to an
increase in depreciable property. The increases in 2001 and 2000 were also due
to the amortization of a portion of a regulatory asset, which was allowed in the
current retail revenue sharing plan. See Note 3 to the financial statements
under "Retail Revenue Sharing Plan" for further information.
Allowance for equity funds used during construction in 2002 was $3.0 million
due primarily to the completion of Plant Smith Unit 3, which began construction
in 2000. See Note 1 to the financial statements under "Allowance for Funds Used
During Construction and Interest Capitalized" for further information.
Interest expense increased $6.4 million, or 25.6 percent, in 2002 due
primarily to the issuance of $60 million of senior notes in August 2001, $75
million of senior notes in October 2001, and $45 million of senior notes in
January 2002. These financings were primarily used to finance the construction
of Plant Smith Unit 3. In 2001, interest expense decreased $3.1 million, or 10.9
percent, due primarily to higher allowance for debt funds used during
construction related to the Company's Plant Smith Unit 3, as well as lower
interest rates on notes payable and variable rate pollution control bonds. In
2000, interest expense increased $1.2 million, or 4.6 percent, due primarily to
the issuance of $50 million of senior notes in August 1999.
Effects of Inflation
The Company is subject to rate regulation based on the recovery of historical
costs. In addition, the income tax laws are based on 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
General
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. The major factors include regulatory matters and the ability
to achieve energy sales growth.
Future earnings in the near term will depend, in part, upon growth in energy
sales, which is subject to a number of factors. Traditionally, these factors
have included the rate of economic growth in the Company's service area,
weather, competition, changes in contracts with neighboring utilities, the
elasticity of demand, and energy conservation practiced by the Company's
customers.
The Company 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 Florida Public Service Commission (FPSC).
In September 2001 the Company filed a request with the FPSC for a base rate
increase of approximately $70 million, the majority of which was related to the
Plant Smith Unit 3 combined cycle facility which was placed in service in April
2002. In May 2002 the FPSC approved a retail base rate increase of $53.2 million
effective June 7, 2002.
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MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2002 Annual Report
In accordance with Financial Accounting Standards Board (FASB) Statement No.
87, Employers' Accounting for Pensions, the Company recorded non-cash pre-tax
pension income of approximately $5.6 million in 2002. Future pension income is
dependent on several factors including trust earnings and changes to the plan.
Current estimates indicate a reversal of recording pension income to recording
pension expense as early as 2006. Postretirement benefit costs for the Company
were $4.5 million in 2002 and are expected to continue to trend upward. A
portion of pension income and postretirement benefit costs are capitalized based
on construction-related labor charges. For more information regarding pension
and postretirement benefits, see Note 2 to the financial statements.
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 in
Financial Condition under "Environmental Matters." Also, Florida legislation
adopted in 1993 and amended in 2002 provides for recovery of prudent
environmental compliance costs and is discussed in Note 3 to the financial
statements under "Environmental Cost Recovery."
Industry Restructuring
The electric utility industry in the United States is continuing to evolve as a
result of regulatory and competitive factors. Among the primary agents of change
was 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 power plants for a utility's large industrial and commercial
customers where retail access is allowed and sell energy to other utilities.
Also, electricity sales for resale rates were affected by numerous new energy
suppliers, including power marketers and brokers.
This past year merchant energy companies and traditional electric utilities
with significant energy marketing and trading activities came under severe
financial pressures. Many of these companies have completely exited or
drastically reduced all energy marketing and trading activities and sold foreign
and domestic electric infrastructure assets. The Company has not experienced any
material financial impact regarding its limited energy trading operations
through Southern Company Services (SCS).
Although the Energy Act does not provide for retail customer access, it has
been a major catalyst for recent restructuring and consolidations taking place
within the utility industry. Numerous federal and state initiatives to promote
wholesale and retail competition are in varying stages. Among other things,
these initiatives allow retail customers in some states to choose their
electricity provider. 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 discussed in
Florida, none have been enacted. Enactment could require numerous issues to be
resolved, including significant ones relating to recovery of any stranded
investments, full cost recovery of energy produced, and other issues related to
the energy crisis that occurred in California.
In 2000, Florida's Governor appointed a study commission to look at the
state's electric industry, studying issues ranging from current and future
reliability of electric and natural gas supply, retail and wholesale
competition, environmental impacts of energy supply, conservation, and tax
issues. The study commission's final report, entitled "Florida...Energy Wise,"
was presented in December 2001 to the Governor and the Legislature. The five key
areas addressed by the report were Energy Efficiency, Adequate and Reliable
Supply of Energy, Improvement of Energy Infrastructure, Preservation of the
Environment, and Utilization of New Technologies and Renewable Resources.
Changes were recommended within the wholesale energy market only. For changes to
occur, they will have to be drafted and voted into law by the Legislature. No
legislation of this type was voted on in 2002. The effects of any proposed
changes cannot presently be determined but could have a material effect on the
Company's 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.
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MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2002 Annual Report
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.
The FPSC has approved a revised rule for investor-owned utilities engaging in
power plant construction subject to the Florida Electrical Power Plant Siting
Act (PPSA) to govern the process for selecting such generation projects. This
new rule is aimed at creating a more transparent process accessible to a greater
number of bidders. The revisions require a utility that intends to build a
project subject to the PPSA to first issue a request for proposals (RFP) that
meets the requirements of the revised rule, including a more detailed
description of the methodology and criteria that will be used to evaluate the
response. Also, respondents that have not been eliminated from further
consideration must be given an opportunity to revise their proposals if the
utility intends to revise its cost estimates on which the RFP was based. The
revised rule also provides a mechanism for expedited dispute resolution and
places restrictions on the level of costs a utility may recover if, at the
conclusion of the RFP process, the FPSC certifies the utility's own self-build
option as the most cost effective generation alternative identified through the
process. The staff of the legislature's Joint Administrative Procedures
Committee (JAPC) has filed a letter with the FPSC that raises some concerns with
the proposed rule. The FPSC cannot file the rule for adoption until JAPC's
comments have been addressed, therefore, the effective date for this new rule
has not yet been established.
The FPSC, in collaboration with the Florida Department of Environmental
Protection (FDEP), was directed by the Florida Legislature to prepare a report
on renewable energy. A final report was prepared by the FPSC and FDEP in January
2003. This report describes various renewable and green energy options. The
report provided the FPSC, the FDEP, and the state Legislature with information
on current and potential technologies, costs, feasibility, and status of current
renewable technologies within the State of Florida. The report does not provide
any formal policy recommendations with respect to renewable energy but is
intended to provide the legislature and policymakers a sound starting point if
they consider new legislation in this area. While the Company is actively
pursuing a renewable energy portfolio that may be incorporated into its offering
to its customers, the pursuit of a mandatory renewable portfolio standard or
non-by-passable public benefits charge by the State could add additional costs
to the Company's operations and affect the Company's competitive position.
FERC Matters
In December 1999, the FERC issued its final rule on Regional Transmission
Organizations (RTOs). The order encouraged utilities owning transmission systems
to form RTOs on a voluntary basis. Southern Company has submitted a series of
status reports informing the FERC of progress toward the development of a
Southeastern RTO. In these status reports, Southern Company explained that it is
developing a for-profit RTO known as SeTrans with a number of non-jurisdictional
cooperative and public power entities. In 2001, Entergy Corporation and Cleco
Power joined the SeTrans development process. In 2002, the sponsors of SeTrans
established a Stakeholder Advisory Committee, which will participate in the
development of the RTO, and held public meetings to discuss the SeTrans
proposal. On October 10, 2002, the FERC granted Southern Company's and other
SeTrans sponsors' petition for a declaratory order regarding the governance
structure and the selection process for the Independent System Administrator
(ISA) of the SeTrans RTO. The FERC also provided guidance on other issues
identified in the petition. The SeTrans sponsors announced the selection of ESB
International, Ltd. (ESBI) to be the preferred ISA candidate. Should
negotiations with this candidate successfully conclude with final agreement
among the parties, the SeTrans sponsors intend to seek any state and federal
regulatory or other approvals necessary for formation of the SeTrans RTO and the
approval of ESBI to serve in the capacity of the SeTrans ISA. The creation of
SeTrans is not expected to have a material impact on the Company's financial
statements; however, the outcome of this matter cannot now be determined.
In July 2002, the FERC issued a notice of proposed rulemaking regarding open
access transmission service and standard electricity market design. The
proposal, if adopted, would among other things: (1) require transmission assets
of jurisdictional utilities to be operated by an independent entity; (2)
establish a standard market design; (3) establish a single type of transmission
service that applies to all customers; (4) assert jurisdiction over the
transmission component of bundled retail service; (5) establish a generation
reserve margin; (6) establish bid caps for a day ahead and spot energy markets;
II-143
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2002 Annual Report
and (7) revise the FERC policy on the pricing of transmission expansions.
Comments on certain aspects of the proposal have been submitted by Southern
Company. Any impact of this proposal on the Company will depend on the form in
which final rules may be ultimately adopted; however the Company's revenues,
expenses, assets, and liabilities could be adversely affected by changes in the
transmission regulatory structure in its regional power market.
Accounting Policies
Critical Policy
The Company's significant accounting policies are described in Note 1 to the
financial statements. The Company's only critical accounting policy involves
rate regulation. 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 Standards
Derivatives
Effective January 2001, the Company adopted FASB Statement No. 133, Accounting
for Derivative Instruments and Hedging Activities, as amended. In October 2002,
the Emerging Issues Task Force (EITF) of the FASB announced accounting changes
related to energy trading contracts in Issue No. 02-3. In October 2002, the
Company prospectively adopted the EITF's requirement to reflect the impact of
certain energy trading contracts on a net basis. This change had no material
impact on the Company's income statement. Another change also required certain
energy trading contracts to be accounted for on an accrual basis effective
January 2003. This change had no impact on the Company's current accounting
treatment.
Asset Retirement Obligations
Prior to January 2003, the Company accrued for the ultimate cost of retiring
most long-lived assets over the life of the related asset through depreciation
expense. FASB Statement No. 143 establishes new accounting and reporting
standards for legal obligations associated with the ultimate cost of retiring
long-lived assets. The present value of the ultimate cost for an asset's future
retirement must be recorded in the period in which the liability is incurred.
The cost must be capitalized as part of the related long-lived asset and
depreciated over the asset's useful life. Additionally, Statement No. 143 does
not permit non-regulated companies to continue accruing future retirement costs
for long-lived assets that the Company does not have a legal obligation to
retire. For more information regarding the impact of adopting this standard
effective January 1, 2003, see Note 1 to the financial statements under
"Regulatory Assets and Liabilities" and "Depreciation and Amortization."
Guarantees
In November 2002, the FASB issued Interpretation No. 45, Accounting and
Disclosure Requirements for Guarantees. This interpretation requires disclosure
of certain direct and indirect guarantees as reflected in Note 4 to the
financial statements. In addition, it requires recognition of a liability at
inception for any new or modified guarantees issued after December 31, 2002. The
adoption of this new standard had no material impact on the Company's financial
statements.
FINANCIAL CONDITION
Overview
During 2002, gross property additions were $106.6 million. Funds for the
Company's property additions were provided by operating activities, capital
contributions, and additional financings. See the Statements of Cash Flows for
additional information.
Credit Rating Risk
The Company does not have any credit agreements that would require material
changes in payment schedules or terminations as a result of a credit rating
downgrade.
Exposure to Market Risks
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 manage the volatility attributable to these exposures, the Company nets the
exposures to take advantage of natural offsets and enters into various
II-144
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2002 Annual Report
derivative transactions for the remaining exposures pursuant to the Company's
policies in areas such as counterparty exposure and hedging practices. Company
policy is that derivatives are to be used primarily for hedging purposes.
Derivative positions are monitored using techniques that include market
valuation and sensitivity analysis.
The weighted average rate on variable long-term debt outstanding at December
31, 2002 was 1.43 percent. If the Company sustained a 100 basis point change in
interest rates for all variable rate long-term debt, the change would affect
annualized interest expense by approximately $0.83 million at December 31, 2002.
See Note 1 to the financial statements for additional information. The Company
is not aware of any facts or circumstances that would significantly affect such
exposures in the near term.
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 and, to a lesser extent,
similar contracts for gas purchases. At December 31, 2002, exposure from these
activities was not material. The fair value of changes in derivative energy
trading contracts and year-end valuations are as follows:
Changes in Fair Value
- --------------------------------------------------------------
2002 2001
- --------------------------------------------------------------
(in thousands)
Contracts beginning of year $(110) $110
Contracts realized or settled 150 (100)
New contracts at inception - -
Changes in valuation techniques - -
Current period changes 2,296 (120)
- --------------------------------------------------------------
Contracts end of year $2,336 $(110)
==============================================================
Source of Year-End Valuation Prices
- --------------------------------------------------------
Total Maturity
Fair Value --------------------
Year 1 1-3 Years
- --------------------------------------------------------------
(in thousands)
Actively quoted $2,336 $3,176 $(840)
External sources - - -
Models and other
methods - - -
- --------------------------------------------------------------
Contracts end of year $2,336 $3,176 $(840)
==============================================================
Unrealized gains and losses from mark to market adjustments on contracts
related to fuel hedging programs are recorded as regulatory assets and
liabilities. Realized gains and losses from these programs are included in fuel
expense and are recovered through the Company's fuel cost recovery clause. Gains
and losses on contracts that do not represent hedges are recognized in the
income statement as incurred. At December 31, 2002, the fair value of derivative
energy contracts was reflected in the financial statements as follows:
Amounts
- ---------------------------------------------------------------
(in thousands)
Regulatory liabilities, net $2,322
Other comprehensive income -
Net income 14
- ---------------------------------------------------------------
Total fair value $2,336
===============================================================
Approximately $0.12 million and $0.05 million of gains were recognized in
income in 2002 and 2001, respectively. The Company is exposed to market-price
risk in the event of nonperformance by parties to the derivative energy
contracts. The Company's policy is to enter into agreements with counterparties
that have investment grade credit ratings by Moody's and Standard & Poor's or
with counterparties who have posted collateral to cover potential credit
exposure. . Therefore, the Company does not anticipate market risk exposure from
nonperformance by its counterparties. For additional information, see Note 1 to
the financial statements under "Financial Instruments."
Financing Activities
In 2002, the Company issued $45 million of Senior Notes primarily to finance
certain construction costs for Plant Smith Unit 3. Also in 2002, the Company
refinanced a total of $55 million of pollution control bonds. In 2001, the
Company sold $135 million of senior notes and $30 million of trust preferred
securities and used the proceeds to retire $30 million of first mortgage bonds
and for Plant Smith Unit 3 construction.
Composite financing rates for the years 2000 through 2002 as of year end were
as follows:
2002 2001 2000
-----------------------------
Composite interest rate on
long-term debt 5.3% 5.6% 6.2%
Composite rate on
trust preferred securities 6.9% 7.2% 7.3%
Composite preferred stock
dividend rate 5.1% 5.1% 5.1%
- -----------------------------------------------------------------
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MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2002 Annual Report
The composite interest rates on long-term debt decreased in 2002 due to the
refinancing of certain pollution control bonds at lower interest rates. The
composite rate on trust preferred securities decreased in 2002 due to
refinancing the 7.625% issue with flexible trust preferred securities at a five
year initial fixed rate of 5.60%.
Capital Requirements for Construction
The Company's gross property additions, including those amounts related to
environmental compliance, are budgeted at $414 million for the three years
beginning in 2003 ($108 million in 2003, $150 million in 2004, and $156 million
in 2005). These amounts include $34 million, $52 million, and $47 million in
2003, 2004, and 2005, respectively, for capital expenditures related to
environmental controls at Plant Crist as part of an agreement with the FDEP to
reduce nitrogen oxide (NOx) emissions. The FPSC authorized the Company to
recover the costs related to these environmental projects through the
Environmental Cost Recovery Clause. See further discussion under Environmental
Matters and Note 4 to the financial statements under "Construction Program." The
remaining capital expenditures are 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 the following:
business conditions; environmental regulations; FERC rules and transmission
regulations; load projections; the cost and efficiency of construction labor,
equipment, and materials; and the cost of capital.
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.
Future note maturities, operating lease obligations, and purchase
commitments - discussed in notes 4 and 8 to the financial statements -
are as follows:
2003 2004 2005
- ----------------------------------------------------------------
(in millions)
Notes 60 50 0
Operating leases 2 2 2
- ----------------------------------------------------------------
Purchase commitments
Fuel 113 90 92
Purchased power 1 1 1
- --------------------------------------------------------------
Long-term service
agreements 7 7 7
- --------------------------------------------------------------
Environmental Matters
New Source Review Enforcement Actions
In November 1999, the Environmental Protection Agency (EPA) brought a civil
action in the U.S. District Court in Georgia against Alabama Power, Georgia
Power, and SCS. The complaint alleges violations of the 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 operating companies a notice of violation related to ten generating
facilities, including the five facilities mentioned previously and the Company's
Plants Crist and Scherer. For additional information, see Note 5 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 the Company,
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
control equipment when performing maintenance and construction at coal burning
plants constructed or under construction prior to 1978. The U.S. District Court
in Georgia granted Alabama Power's motion to dismiss for lack of jurisdiction in
Georgia and granted SCS's motion to dismiss on the grounds that it neither owned
II-146
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2002 Annual Report
nor operated the generating units involved in the proceedings. The court granted
the EPA's motion to add Savannah Electric as a defendant, but denied the motion
to add the Company and Mississippi Power based on lack of jurisdiction. As
directed by the court, the EPA re-filed its amended complaint limiting claims to
those brought against Georgia Power and Savannah Electric. The EPA also re-filed
its claims against Alabama Power in the U.S. District Court in Alabama. It has
not re-filed against the Company, Mississippi Power, or SCS.
The Alabama Power, Georgia Power, and Savannah Electric cases have been
stayed since the spring of 2001, pending a ruling by the U.S. Court of Appeals
for the Eleventh Circuit in the appeal of a very similar New Source Review
enforcement action against the Tennessee Valley Authority (TVA). The TVA appeal
involves many of the same legal issues raised against Alabama Power, Georgia
Power, and Savannah Electric. Because the outcome of the TVA appeal could have a
significant adverse impact on Alabama Power and Georgia Power, both companies
have been parties to that case as well. In February 2003, the U.S. District
Court in Alabama extended the stay of the EPA litigation proceeding in Alabama
until the earlier of May 6, 2003, or a ruling by the U.S. Court of Appeals for
the Eleventh Circuit in the related litigation involving TVA. On August 21,
2002, the U.S. District Court in Georgia denied the EPA's motion to reopen the
Georgia case. The denial was without prejudice to the EPA to refile the motion
at a later date, which the EPA has not done at this time.
The Company believes that it has 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.
Environmental Statutes and Regulations
The Company's operations are subject to extensive regulation by state and
federal environmental agencies under a variety of statutes and regulations
governing environmental media, including air, water, and land resources.
Compliance with these environmental requirements will involve significant costs,
a major portion of which is expected to be recovered through existing ratemaking
provisions. There is no assurance, however, that all such costs will, in fact,
be recovered.
Compliance with the federal Clean Air Act and resulting regulations have been
and will continue to be, a significant focus for the Company. The Title IV acid
rain provisions of the Clean Air Act, for example, required significant
reductions in sulfur dioxide and nitrogen oxide emissions. Compliance was
required in two phases -- Phase I, effective in 1995 and Phase II, effective in
2000. Construction expenditures associated with Phase I totaled approximately
$42 million for the Company. Phase II sulfur dioxide compliance was required in
2000 and did not have a material impact on the Company.
In 1993, the Florida Legislature adopted legislation that allows a utility to
petition the FPSC for specific recovery of prudent environmental compliance
costs that are not being recovered through base rates or any other recovery
mechanism. This legislation was amended in 2002 to allow specific recovery of
costs incurred as a result of an agreement between the Company and the FDEP for
the purpose of ensuring compliance with ozone ambient air quality standards
adopted by the EPA. 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 EPA revised the national ambient air quality standards for
ozone and particulate matter. These revisions made the standards significantly
more stringent. In the subsequent litigation of these standards, the U.S.
Supreme Court found the EPA's implementation program for the new ozone standard
unlawful and remanded it to the EPA for further rulemaking. The EPA is expected
to propose implementation rules designed to address the court's concerns in 2003
and issue final implementation rules in 2004. The remaining legal challenges to
the new standards, which were pending before the U.S. Court of Appeals, District
of Columbia Circuit, have been resolved.
Based on recommendations from the State, EPA is expected to designate areas
of Florida as attainment or nonattainment for the new ozone and particulate
standards in April 2004. In August 2002, the Company entered into an agreement
II-147
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2002 Annual Report
with the FDEP calling for NOx emission reductions at Plant Crist to help ensure
attainment of the new standards in the Pensacola area. Under the agreement, the
Company will install Selective Catalytic Reduction controls and a new
precipitator on Crist Unit 7 by 2005. In addition, the Company will retire Crist
Unit 1 in 2003 and Units 2 and 3 by 2006. Costs for implementation of the
agreement have been approved for recovery under the Environmental Cost Recovery
Clause.
The EPA has also announced plans to issue a proposed Regional Transport Rule
for the fine particulate matter standard by the end of 2003 and to finalize the
rule in 2005. This rule would likely require year-round sulfur dioxide and
nitrogen oxide emission reductions from power plants as early as 2010. It is not
possible at this time to determine the effect such a rule would have on the
Company.
Further reductions in sulfur dioxide could also be required under the EPA's
Regional Haze rules. The Regional Haze rules require states to establish Best
Available Retrofit Technology (BART) standards for certain sources that
contribute to regional haze. The Company has a number of plants that could be
subject to these rules. The EPA regional haze program calls for states to submit
State Implementation Plans in 2007 and 2008 that contain emission reduction
strategies for achieving progress toward the visibility improvement goal. In
2002, however, the U.S. Court of Appeals for the District of Columbia Circuit,
vacated and remanded the BART provisions of the federal Regional Haze rules to
the EPA for further rulemaking. Because new BART rules have not been developed
and state visibility assessments are only beginning, it is not possible to
determine the effect of these rules on the Company at this time.
The EPA's Compliance Assurance Monitoring (CAM) regulations under Title V of
the Clean Air Act require that monitoring be performed to ensure compliance with
emissions limitations on an ongoing basis. The regulations require certain
facilities with Title V operating permits to develop and submit a CAM plan to
the appropriate permitting authority upon applying for renewal of the facility's
Title V operating permit. The Company will be applying for renewal of its Title
V operating permits between 2003 and 2005, and a number of the plants will
likely be subject to CAM requirements for at least one pollutant, in most cases,
particulate matter. The Company is in the process of developing CAM plans, which
could indicate a need for improved particulate matter controls at affected
facilities. Because the plans are still in the early stages of development, the
Company cannot determine the extent to which improved controls could be required
or the costs associated with any necessary improvements. Actual ongoing
monitoring costs are expensed as incurred and are not material for any period
presented.
In December 2000, having completed its utility studies for mercury and other
hazardous air pollutants (HAPS), the EPA issued a determination that an emission
control program for mercury and, perhaps, other HAPS is warranted. The program
is being developed under the Maximum Achievable Control Technology provisions of
the Clean Air Act. The EPA currently plans to issue proposed rules regulating
mercury emissions from electric utility boilers by the end of 2003, and those
regulations are scheduled to be finalized by the end of 2004. Compliance could
be required as early as 2007. Because the rules have not yet been proposed, the
costs associated with compliance cannot be determined at this time.
In December 2002, the EPA issued final and proposed revisions to the New
Source Review program under the Clean Air Act. In February 2003, several
northeastern states petitioned the D.C. Circuit Court for a stay of the final
rules. The proposed rules are open to public comment and may be revised before
being finalized by the EPA. If fully implemented, these proposed and final
regulations could affect the applicability of the New Source Review provisions
to activities at the Company's facilities. In any event, any final regulations
must be adopted by the states in the Company's service area in order to apply to
the Company's facilities. The effect of these proposed and final rules cannot be
determined at this time.
Several major bills to amend the Clean Air Act to impose more stringent
emissions limitations have been proposed. Three of these, the Bush
Administration's Clear Skies Act, the Clean Power Act of 2002, and the Clean Air
Planning Act of 2002 proposed to further limit power plant emissions of sulfur
dioxide, nitrogen oxides, and mercury. The latter two bills also proposed to
limit emissions of carbon dioxide. None of these bills were enacted into law in
the 107th Congress. Similar bills have been, and are anticipated to be
introduced this year. The Bush Administration's Clear Skies Act was recently
II-148
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2002 Annual Report
reintroduced and President Bush has stated that it will be a high priority for
the Administration. Other bills already introduced include the Climate
Stewardship Act of 2003, which proposes capping greenhouse gas emissions. The
cost impacts of such legislation would depend upon the specific requirements
enacted.
Domestic efforts to limit greenhouse gas emissions have been spurred by
international discussions surrounding the Framework Convention on Climate Change
and, specifically, the Kyoto Protocol, which proposes international constraints
on the emissions of greenhouse gases. The Bush Administration does not support
U.S. ratification of the Kyoto Protocol or other mandatory carbon dioxide
reduction legislation and has instead announced a new voluntary climate
initiative which seeks an 18 percent reduction by 2012 in the rate of greenhouse
gas emissions relative to the dollar value of the U.S. economy. The Company is
involved in a voluntary electric utility industry sector climate change
initiative, in partnership with the government. Because this initiative is still
under development, it is not possible to determine the effect on the Company at
this time.
The Company must comply with other environmental laws and regulations that
cover the handling and disposal of hazardous waste and releases of hazardous
substances. Under these various laws and regulations, the Company could incur
substantial costs to clean up properties; however, such costs are expected to be
recovered through the Environmental Cost Recovery Clause. The Company conducts
studies to determine the extent of any required cleanup and has recognized in
its financial statements the costs to clean up known sites. The Company expensed
$1.2 million, $1.2 million, and $1.3 million for cleanup and ongoing monitoring
in 2002, 2001, and 2000, respectively. The Company may be liable for a portion
or all required cleanup costs for additional sites that may require
environmental remediation. See Note 3 to the financial statements for further
information.
Under the Clean Water Act, the EPA is developing new rules aimed at reducing
impingement and entrainment of fish and fish larvae at cooling water intake
structures that will require numerous biological studies and, perhaps, retrofits
to some intake structures at existing power plants. The new rule was proposed in
February 2002 and will be finalized by August 2004. The impact of any new
standards will depend on the development and implementation of applicable
regulations.
Also, under the Clean Water Act, the EPA and the FDEP are developing total
maximum daily loads (TMDLs) for certain impaired waters. Establishment of
maximum loads by the EPA or the FDEP may result in lowering permit limits for
various pollutants and a requirement to take additional measures to control
non-point source pollution (e.g. storm water runoff) at facilities discharging
into waters for which TMDLs are established. Because the effect on the Company
will depend on the actual TMDLs and permit limitations established by the
implementing agency, it is not possible to determine the effect on the Company
at this time.
The EPA and state environmental regulatory agencies are reviewing and
evaluating various other matters including limits on pollutant discharges to
impaired waters, hazardous waste disposal requirements, and other regulatory
matters. The impact of any new standards will depend on the development and
implementation of applicable regulations.
Several major pieces of environmental legislation are periodically 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; the Emergency Planning & Community Right-to-Know Act; and the
Endangered Species Act.
Compliance with possible additional federal or state legislation related to
global climate change, electromagnetic fields, and other environmental and
health concerns could also significantly affect the Company. The impact of any
new legislation, or changes to existing legislation, could affect many areas of
the Company's operations. The full impact of any such changes cannot be
determined at this time.
II-149
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2002 Annual Report
Sources of Capital
The Company plans 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, the Company has various
internal and external sources of liquidity. At the beginning of 2003, the
Company had approximately $13.3 million of cash and cash equivalents and unused
committed lines of credit with banks to meet its short-term cash needs. In
addition, the Company has significant cash flow from operating activities.
At the beginning of 2003, the Company had used none of its available credit
arrangements. Bank credit arrangements are as follows:
Expires
---------------------------
Total Unused 2003 2004 & beyond
- ---------------------------------------------------------------
(in millions)
$66.3 $66.3 $66.3 $ -
- ---------------------------------------------------------------
See Note 8 to the financial statements under "Bank Credit Arrangements" and
the Statements of Cash Flows for additional information.
The Company may also meet short-term cash needs through a Southern Company
subsidiary organized to issue and sell commercial paper and extendible
commercial notes at the request and for the benefit of the Company and the other
Southern Company operating companies. At December 31, 2002, the Company had
outstanding $8.5 million of commercial paper.
The Company historically has relied on issuances of first mortgage bonds and
preferred stock, in addition to pollution control bonds issued for its benefit
by public authorities, to meet its long-term external financing requirements.
The Company has no restrictions on the amounts of unsecured indebtedness it may
incur. However, in order to issue first mortgage bonds or preferred stock, the
Company 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 2002 Annual Report contains forward looking and historical
information. Forward looking information includes, among other things,
statements concerning projected retail sales growth and scheduled completion of
new generation. In some cases, forward-looking statements can be identified by
terminology such as "may," "will," "could," "should," "expects," "plans,"
"anticipates," "believes," "estimates," "projects," "predicts," "potential," or
"continue" or the negative of these terms or other comparable terminology. The
Company cautions that there are various important factors that could cause
actual results to differ materially from those indicated in the forward-looking
statements; accordingly, there can be no assurance that such indicated results
will be realized. These factors include the impact of recent and future federal
and state regulatory change, including legislative and regulatory initiatives
regarding deregulation and restructuring of the electric utility industry, and
also changes in environmental and other laws and regulations to which the
Company is subject, as well as changes in application of existing laws and
regulations; current and future litigation; the effects, extent, and timing of
the entry of additional competition in the markets in which the Company
operates; the impact of fluctuations in commodity prices, interest rates, and
customer demand; state and federal rate regulations; political, legal, and
economic conditions and developments in the United States; internal
restructuring or other restructuring options that may be pursued; potential
business strategies, including acquisitions or dispositions of assets
or businesses, which cannot be assured to be completed or beneficial to the
Company; the ability of counterparties of the Company to make payments as and
when due; the effects of, and changes in, economic conditions in the areas in
which the Company operates, including the current soft economy; the direct or
indirect effects on the Company's business resulting from the terrorist
incidents on September 11, 2001, or any similar such incidents or responses to
such incidents; financial market conditions and the results of financing
II-150
MANAGEMENTS DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2002 Annual Report
efforts; the ability of the Company to obtain additional generating capacity
at competitive prices; weather and other natural phenomena; and other factors
discussed elsewhere herein and in other reports (including the Form 10-K) filed
from time to time by the Company with the Securities and Exchange Commission.
II-151
STATEMENTS OF INCOME
For the Years Ended December 31, 2002, 2001, and 2000
Gulf Power Company 2002 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------------
2002 2001 2000
- ----------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Revenues:
Retail sales $665,836 $584,591 $548,640
Sales for resale --
Non-affiliates 77,171 82,252 66,890
Affiliates 40,391 27,256 66,995
Other revenues 37,069 31,104 31,794
- ----------------------------------------------------------------------------------------------------------------------------------
Total operating revenues 820,467 725,203 714,319
- ----------------------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
Fuel 273,860 200,633 215,744
Purchased power --
Non-affiliates 23,797 65,585 73,846
Affiliates 39,201 40,660 8,644
Other 124,654 117,394 117,146
Maintenance 75,421 60,193 56,281
Depreciation and amortization 77,014 68,218 66,873
Taxes other than income taxes 61,033 55,261 55,904
- ----------------------------------------------------------------------------------------------------------------------------------
Total operating expenses 674,980 607,944 594,438
- ----------------------------------------------------------------------------------------------------------------------------------
Operating Income 145,487 117,259 119,881
Other Income and (Expense):
Allowance for equity funds used during construction 2,980 5,373 160
Interest income 572 1,258 1,137
Interest expense, net of amounts capitalized (31,452) (25,034) (28,085)
Distributions on preferred securities of subsidiary (8,524) (6,477) (6,200)
Other income (expense), net (4,666) (2,663) (4,286)
- ----------------------------------------------------------------------------------------------------------------------------------
Total other income and (expense) (41,090) (27,543) (37,274)
- ----------------------------------------------------------------------------------------------------------------------------------
Earnings Before Income Taxes 104,397 89,716 82,607
Income taxes 37,144 31,260 30,530
- ----------------------------------------------------------------------------------------------------------------------------------
Earnings Before Cumulative Effect of 67,253 58,456 52,077
Accounting Change
Cumulative effect of accounting change--
less income taxes of $42 - 68 -
- ----------------------------------------------------------------------------------------------------------------------------------
Net Income 67,253 58,524 52,077
Dividends on Preferred Stock 217 217 234
- ----------------------------------------------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred Stock $ 67,036 $ 58,307 $ 51,843
==================================================================================================================================
The accompanying notes are an integral part of these financial statements.
II-152
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2002, 2001, and 2000
Gulf Power Company 2002 Annual Report
- -------------------------------------------------------------------------------------------------------------------------------
2002 2001 2000
- -------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Activities:
Net income $ 67,253 $ 58,524 $ 52,077
Adjustments to reconcile net income
to net cash provided from operating activities --
Depreciation and amortization 82,230 72,320 69,915
Deferred income taxes 9,619 3,394 (12,516)
Pension, postretirement, and other employee benefits (8,170) 511 (2,983)
Other, net 5,756 (2,315) 13,669
Changes in certain current assets and liabilities --
Receivables, net (28,173) 15,991 (20,212)
Fossil fuel stock 10,464 (30,887) 13,101
Materials and supplies (5,982) 176 1,055
Other current assets (14,178) (29,735) 8,945
Accounts payable 19,168 (7,289) 15,924
Taxes accrued 1,117 (4,560) 81
Other current liabilities (4,251) (2,627) 10,698
- -------------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities 134,853 73,503 149,754
- -------------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (106,624) (274,668) (95,807)
Cost of removal net of salvage (7,978) (5,620) (3,902)
Other (9,745) 10,910 (530)
- -------------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities (124,347) (269,378) (100,239)
- -------------------------------------------------------------------------------------------------------------------------------
Financing Activities:
Increase (decrease) in notes payable, net (58,831) 44,311 (12,000)
Proceeds --
Pollution control bonds 55,000 - -
Senior notes 45,000 135,000 -
Preferred securities 40,000 30,000 -
Capital contributions from parent company 43,809 72,484 12,222
Redemptions --
First mortgage bonds - (30,000) -
Pollution control bonds (55,000) - -
Senior notes (454) (862) (1,853)
Payment of preferred stock dividends (217) (217) (234)
Payment of common stock dividends (65,500) (53,275) (59,000)
Other (3,279) (3,703) (22)
- -------------------------------------------------------------------------------------------------------------------------------
Net cash provided from (used for) financing activities 528 193,738 (60,887)
- -------------------------------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents 11,034 (2,137) (11,372)
Cash and Cash Equivalents at Beginning of Period 2,244 4,381 15,753
- -------------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ 13,278 $ 2,244 $ 4,381
===============================================================================================================================
Supplemental Cash Flow Information:
Cash paid during the period for --
Interest (net of $1,392, $2,510, and $440 capitalized for
2002, 2001, and 2000, respectively $39,604 $30,813 $32,277
Income taxes (net of refunds) 28,320 33,349 42,252
- -------------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
II-153
BALANCE SHEETS
At December 31, 2002 and 2001
Gulf Power Company 2002 Annual Report
- ---------------------------------------------------------------------------------------------------------------------
Assets 2002 2001
- ---------------------------------------------------------------------------------------------------------------------
(in thousands)
Current Assets:
Cash and cash equivalents $ 13,278 $ 2,244
Receivables --
Customer accounts receivable 48,609 38,898
Unbilled revenues 28,077 25,215
Under recovered regulatory clause revenues 29,549 24,912
Other accounts and notes receivable 6,618 4,316
Affiliated companies 8,678 2,689
Accumulated provision for uncollectible accounts (889) (1,342)
Fossil fuel stock, at average cost 37,191 47,655
Materials and supplies, at average cost 34,840 28,857
Prepaid taxes 12,704 -
Other 14,134 12,662
- ---------------------------------------------------------------------------------------------------------------------
Total current assets 232,789 186,106
- ---------------------------------------------------------------------------------------------------------------------
Property, Plant, and Equipment:
In service 2,248,156 1,951,512
Less accumulated provision for depreciation 946,408 912,581
- ---------------------------------------------------------------------------------------------------------------------
1,301,748 1,038,931
Construction work in progress 35,708 264,525
- ---------------------------------------------------------------------------------------------------------------------
Total property, plant, and equipment 1,337,456 1,303,456
- ---------------------------------------------------------------------------------------------------------------------
Other Property and Investments 10,157 7,049
- ---------------------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets:
Deferred charges related to income taxes 18,798 16,766
Prepaid pension costs 36,298 29,980
Unamortized debt issuance expense 3,900 3,036
Unamortized premium on reacquired debt 14,052 14,518
Other 20,379 12,222
- ---------------------------------------------------------------------------------------------------------------------
Total deferred charges and other assets 93,427 76,522
- ---------------------------------------------------------------------------------------------------------------------
Total Assets $1,673,829 $1,573,133
=====================================================================================================================
The accompanying notes are an integral part of these financial statements.
II-154
BALANCE SHEETS
At December 31, 2002 and 2001
Gulf Power Company 2002 Annual Report
- -----------------------------------------------------------------------------------------------------------------------
Liabilities and Stockholder's Equity 2002 2001
- -----------------------------------------------------------------------------------------------------------------------
(in thousands)
Current Liabilities:
Securities due within one year $ 60,000 $ -
Notes payable 28,479 87,311
Accounts payable --
Affiliated 26,395 18,202
Other 39,685 38,308
Customer deposits 16,047 14,506
Taxes accrued --
Income taxes 10,718 8,162
Other 9,170 8,053
Interest accrued 7,875 8,305
Vacation pay accrued 5,044 4,725
Other 3,933 11,777
- -----------------------------------------------------------------------------------------------------------------------
Total current liabilities 207,346 199,349
- -----------------------------------------------------------------------------------------------------------------------
Long-term debt (See accompanying statements) 452,040 467,784
- -----------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 167,689 161,968
Deferred credits related to income taxes 29,692 28,293
Accumulated deferred investment tax credits 22,289 24,056
Employee benefits provisions 39,656 41,508
Other 46,376 26,045
- -----------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 305,702 281,870
- -----------------------------------------------------------------------------------------------------------------------
Company obligated mandatorily redeemable preferred
securities of subsidiary trusts holding company junior
subordinated notes (See accompanying statements) 155,000 115,000
- -----------------------------------------------------------------------------------------------------------------------
Preferred stock (See accompanying statements) 4,236 4,236
- -----------------------------------------------------------------------------------------------------------------------
Common stockholder's equity (See accompanying statements) 549,505 504,894
- -----------------------------------------------------------------------------------------------------------------------
Total Liabilities and Stockholder's Equity $1,673,829 $1,573,133
=======================================================================================================================
Commitments and Contingent Matters (See notes)
- ------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
II-155
STATEMENTS OF CAPITALIZATION
At December 31, 2002 and 2001
Gulf Power Company 2002 Annual Report
- ------------------------------------------------------------------------------------------------------------------------------
2002 2001 2002 2001
- ------------------------------------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
Long Term Debt:
First mortgage bonds --
6.50% to 6.875% due 2006 $ 55,000 $ 55,000
- ------------------------------------------------------------------------------------------------------------------------------
Total first mortgage bonds 55,000 55,000
- ------------------------------------------------------------------------------------------------------------------------------
Long-term notes payable --
4.69% due August 1, 2003 60,000 60,000
7.05% due August 15, 2004 50,000 50,000
6.00% to 7.50% due 2012-2038 186,757 142,211
- ------------------------------------------------------------------------------------------------------------------------------
Total long-term notes payable 296,757 252,211
- ------------------------------------------------------------------------------------------------------------------------------
Other long-term debt --
Pollution control revenue bonds --
Collateralized:
5.25% due April 1, 2006 12,075 12,075
5.50% to 5.80% due 2023-2026 61,625 96,625
Non-collateralized:
4.80% due 2028 13,000 -
Variable rates (1.30% to 1.85% at 1/1/03)
due 2022-2037 82,930 60,930
- ------------------------------------------------------------------------------------------------------------------------------
Total other long-term debt 169,630 169,630
- ------------------------------------------------------------------------------------------------------------------------------
Unamortized debt premium (discount), net (9,347) (9,057)
- ------------------------------------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
requirement -- $27.9 million) 512,040 467,784
Less amount due within one year 60,000 -
- ------------------------------------------------------------------------------------------------------------------------------
Long-term debt excluding amount due within one year 452,040 467,784 38.9% 42.9%
- ------------------------------------------------------------------------------------------------------------------------------
Cumulative Preferred Stock:
$100 par value
4.64% 1,250 1,250
5.16% 1,357 1,357
5.44% 1,629 1,629
- ------------------------------------------------------------------------------------------------------------------------------
Total (annual dividend requirement -- $0.2 million) 4,236 4,236 0.4% 0.4%
- ------------------------------------------------------------------------------------------------------------------------------
Company Obligated Mandatorily
Redeemable Preferred Securities:
$25 liquidation value --
5.60% 40,000 -
7.00% 45,000 45,000
7.375% 30,000 30,000
7.625% 40,000 40,000
- ------------------------------------------------------------------------------------------------------------------------------
Total (annual distribution requirement -- $10.7 million) 155,000 115,000 13.4% 10.5%
- ------------------------------------------------------------------------------------------------------------------------------
Common Stockholder's Equity:
Common stock, without par value --
Authorized and outstanding -
992,717 shares in 2002 and 2001 38,060 38,060
Paid-in capital 349,769 305,960
Premium on preferred stock 12 12
Retained earnings 162,398 160,862
Accumulated other comprehensive income (loss) (734) -
- ------------------------------------------------------------------------------------------------------------------------------
Total common stockholder's equity 549,505 504,894 47.3% 46.2%
- ------------------------------------------------------------------------------------------------------------------------------
Total Capitalization $1,160,781 $1,091,914 100.0% 100.0%
==============================================================================================================================
The accompanying notes are an integral part of these financial statements.
II-156
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
For the Years Ended December 31, 2002, 2001, and 2000
Gulf Power Company 2002 Annual Report
- ---------------------------------------------------------------------------------------------------------------------------------
Premium on Other
Common Paid-In Preferred Retained Comprehensive
Stock Capital Stock Earnings Income (loss) Total
- ---------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Balance at December 31, 1999 $38,060 $221,254 $12 $162,987 $ - $422,313
Net income after dividends on preferred stock - - - 51,843 - 51,843
Capital contributions from parent company - 12,222 - - - 12,222
Cash dividends on common stock - - - (59,000) - (59,000)
- ---------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2000 38,060 233,476 12 155,830 - 427,378
Net income after dividends on preferred stock - - - 58,307 58,307
Capital contributions from parent company - 72,484 - - - 72,484
Cash dividends on common stock - - - (53,275) - (53,275)
- ---------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2001 38,060 305,960 12 160,862 - 504,894
Net income after dividends on preferred stock - - - 67,036 - 67,036
Capital contributions from parent company - 43,809 - - - 43,809
Other comprehensive income (loss) - - - - (734) (734)
Cash dividends on common stock - - - (65,500) - (65,500)
- ---------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2002 $38,060 $349,769 $12 $162,398 $(734) $549,505
=================================================================================================================================
The accompanying notes are an integral part of these financial statements.
STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2002, 2001, and 2000
Gulf Power Company 2002 Annual Report
- --------------------------------------------------------------------------------------------------------------------------
2002 2001 2000
- --------------------------------------------------------------------------------------------------------------------------
(in thousands)
Net income after dividends on preferred stock $67,036 $58,307 $51,843
- --------------------------------------------------------------------------------------------------------------------------
Other comprehensive income (loss):
Changes in additional minimum pension liability, net (734) - -
of tax of $(461)
- --------------------------------------------------------------------------------------------------------------------------
Total other comprehensive income (loss) (734) - -
- -------------------------------------------------------------------------------------------------------------------------
Comprehensive Income $66,302 $58,307 $51,843
==========================================================================================================================
The accompanying notes are an integral part of these financial statements.
II-157
NOTES TO FINANCIAL STATEMENTS
Gulf Power Company 2002 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING
POLICIES
General
Gulf Power Company (the Company) is a wholly owned
subsidiary of Southern Company, which is the parent company of five operating
companies, Southern Power Company (Southern Power), a system service company
(SCS), Southern Communications Services (Southern LINC), Southern Company Gas
(Southern GAS), Southern Company Holdings (Southern Holdings), Southern Nuclear
Operating Company (Southern Nuclear), Southern Telecom, and other direct and
indirect subsi diaries. The operating companies - Alabama Power, Georgia Power,
the Company, Mississippi Power, and Savannah Electric - provide electric service
in four southeastern states. Southern Power was established in 2001 to
construct, own, and manage Southern Company's competitive generation assets and
sell electricity at market-based rates in the wholesale market. Contracts among
the operating companies and Southern Power - related to jointly owned generating
facilities, interconnecting transmission lines, or 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 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 Telecom
provides fiber and cable services within the southeast. Southern GAS, which
began operation in August 2002, is a competitive retail natural gas marketer
serving customers in Georgia. Southern Holdings is an intermediate holding
subsidiary for Southern Company's investments in leveraged leases, alternative
fuel products, and an energy services business. Southern Nuclear provides
services to Southern Company's nuclear power plants.
Southern Company is registered as a holding company under the Public Utility
Holding Company Act of 1935 (PUHCA). Both Southern Company and its subsidiaries
are subject to the regulatory provisions of the PUHCA. The Company is also
subject to regulation by the FERC and the Florida Public Service Commission
(FPSC). The Company follows accounting principles generally accepted in the
United States and complies with the accounting policies and practices prescribed
by its respective regulatory commissions. The preparation of financial
statements in conformity with accounting principles generally accepted in the
United States 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.
Affiliate Transactions
The Company has an agreement with SCS under which the following services are
rendered to the Company at direct or allocated cost: general and design
engineering, purchasing, accounting and statistical analysis, finance and
treasury, tax, information resources, marketing, auditing, insurance and pension
administration, human resources, systems and procedures, and other services with
respect to business and operations and power pool transactions. Costs for these
services amounted to $49 million, $45 million, and $44 million during 2002,
2001, and 2000, respectively. Cost allocation methodologies used by SCS are
approved by the SEC and management believes they are reasonable.
The operating companies (including the Company), Southern Power, and Southern
GAS may jointly enter into various types of wholesale energy, natural gas and
certain other contracts, either directly or through SCS as agent. Each
participating company may be jointly and severally liable for the obligations
incurred under these agreements. The Company has agreements with Georgia Power
and Mississippi Power under which the Company owns a portion of Plant Scherer
and Plant Daniel. Georgia Power operates Plant Scherer and Mississippi Power
operates Plant Daniel. The Company reimbursed Georgia Power $4.5 million and
Mississippi Power $16.6 million in 2002 for its proportionate share of related
expenses. See Note 4 under "Lease Agreements" and Note 5 for additional
information.
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
II-158
NOTES (continued)
Gulf Power Company 2002 Annual Report
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:
2002 2001
------------------------
(in thousands)
Deferred income tax charges $ 18,798 $ 16,766
Deferred loss on reacquired
debt 14,052 14,518
Environmental remediation 14,428 7,163
Vacation pay 5,044 4,725
Accumulated provision for
property damage (15,418) (13,565)
Deferred income tax credits (29,692) (28,293)
Fuel-hedging liabilities (2,322) -
Other regulatory assets 2,859 2,272
Other regulatory liabilities (3,277) (5,245)
- -----------------------------------------------------------------
Total $ 4,472 $ (1,659)
=================================================================
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. All regulatory assets and liabilities
are reflected in rates.
See "Depreciation and Amortization" for information regarding regulatory
assets and liabilities created as a result of the January 1, 2003 adoption of
FASB Statement No. 143, Accounting for Asset Retirement Obligations.
Revenues, Regulatory Cost Recovery Clauses, and Fuel Costs
Revenues are recognized as services are rendered. Unbilled revenues are accrued
at the end of each fiscal period.
Fuel costs are expensed as the fuel is used. The Company's retail electric
rates include provisions to annually adjust billings for fluctuations in fuel
costs, the energy component of purchased power costs, and certain other costs.
The Company 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.
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.
Depreciation and Amortization
Depreciation of the original cost of plant in service is provided primarily by
using composite straight-line rates, which approximated 3.9 percent in 2002, 3.7
percent in 2001, and 3.8 percent in 2000. 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. Prior
to January 2003, in accordance with regulatory requirements, the Company
followed the industry practice of accruing for the ultimate cost of retiring
most long-lived assets over the life of the related asset as part of the annual
depreciation expense provision.
In January 2003, the Company adopted FASB Statement No. 143, Accounting for
Asset Retirement Obligations. Statement No. 143 establishes new accounting and
reporting standards for legal obligations associated with the ultimate cost of
retiring long-lived assets. The present value of ultimate costs for an asset's
future retirement must be recorded in the period in which the liability is
incurred. The cost must be capitalized as part of the related long-lived asset
and depreciated over the asset's useful life.
There was no cumulative effect adjustment to net income resulting from the
adoption of Statement No. 143. The Company expects to receive an accounting
order from the FPSC to defer the transition adjustment; therefore, the Company
recorded a related regulatory asset of $0.9 million to reflect the Company's
regulatory treatment of these costs under Statement No. 71. The initial
Statement No. 143 liability the Company recognized was $4.0 million, of which
$1.9 million was removed from the accumulated depreciation reserve. The amount
capitalized to property, plant, and equipment was $1.2 million.
II-159
NOTES (continued)
Gulf Power Company 2002 Annual Report
The liability recognized under Statement No. 143 to retire long-lived assets
primarily relates to the Company's combustion turbines at its Pea Ridge
facility, various landfill sites, ash ponds, and a barge unloading dock. The
Company has also identified retirement obligations related to certain
transmission and distribution facilities. However, a liability for the removal
of these transmission and distribution assets will not be recorded because no
reasonable estimate can be made regarding the timing of any related retirements.
The Company will continue to recognize in the income statement their ultimate
removal costs in accordance with its regulatory treatment. Any difference
between costs recognized under Statement No. 143 and those reflected in rates
will be recognized as either a regulatory asset or liability. It is estimated
that this annual difference will be approximately $0.1 million. Management
believes that the actual removal costs will be recoverable in rates over time.
Statement No. 143 does not permit non-regulated companies to continue
accruing future retirement costs for long-lived assets they do not have a legal
obligation to retire. However, in accordance with the regulatory treatment of
these costs, the Company will continue to recognize the removal costs for these
other obligations in their depreciation rates. As of January 1, 2003, the amount
included in the accumulated depreciation reserve that represents a regulatory
liability for these costs was approximately $143 million.
Allowance for Funds Used During Construction and
Interest Capitalized
In accordance with regulatory treatment, the Company records Allowance for Funds
Used During Construction (AFUDC) on construction projects. AFUDC represents the
estimated debt and equity costs of capital funds that are necessary to finance
the construction of new regulated 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 2002, 2001, and 2000 the average AFUDC rates were 7.35
percent, 7.35 percent, and 7.27 percent, respectively. AFUDC, net of taxes, as a
percentage of net income after dividends on preferred stock was 5.72 percent,
11.86 percent, and 0.83 percent, respectively for, 2002, 2001, and 2000.
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.
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 interest capitalized and/or 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.
Impairment of Long-Lived Assets and Intangibles
The Company evaluates long-lived assets for impairment 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
either a specific regulatory disallowance or 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 the
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 re-evaluated when circumstances or events change.
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-160
NOTES (continued)
Gulf Power Company 2002 Annual Report
Financial Instruments
The Company uses derivative financial instruments to limit exposure to
fluctuations in the prices of certain fuel purchases, and electricity purchases
and sales. All derivative financial instruments are recognized as either assets
or liabilities and are measured at fair value. Substantially all of the
Company's bulk energy purchases and sales contracts are derivatives. However, in
many cases, these contracts qualify as normal purchases and sales and are
accounted for under the accrual method. Other contracts qualify as cash flow
hedges of anticipated transactions. This results in the deferral of related
gains and losses in other comprehensive income or regulatory assets or
liabilities as appropriate until the hedged transactions occur. Any
ineffectiveness is recognized currently in net income. Contracts that do not
qualify for the normal purchase and sale exception and that do not meet the
hedge requirements are marked to market through current period income and are
recorded on a net basis in the Statements of Income.
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.
Other 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, 2002 $512,040 $531,133
At December 31, 2001 $467,784 $474,911
Capital trust preferred
securities:
At December 31, 2002 $155,000 $156,853
At December 31, 2001 $115,000 $114,898
- --------------------------------------------------------------
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.
Stock Options
Southern Company provides non-qualified stock options to a large segment of the
Company's employees ranging from line management to executives. The Company
accounts for its stock-based compensation plans in accordance with Accounting
Principles Board Opinion No. 25. Accordingly, no compensation expense has been
recognized because the exercise price of all options granted equaled the
fair-market value on the date of grant. When options are exercised, the Company
receives a capital contribution from Southern Company equivalent to the related
income tax benefit.
Comprehensive Income
Comprehensive income - consisting of net income and changes in additional
minimum pension liability, net of income taxes - is presented in the financial
statements. The objective of comprehensive income 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.
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 a provision
account. The accumulated provision of $0.7 million and $1.3 million at December
31, 2002 and 2001, respectively, is included in other current liabilities in the
accompanying Balance Sheets. For further information see Note 3 under "Personal
Injury Litigation."
II-161
NOTES (continued)
Gulf Power Company 2002 Annual Report
Provision for Property Damage
The Company provides for the cost of repairing damages from major storms and
other uninsured property damages. This includes the cost of major storms and
other damages to its transmission and distribution lines and the cost of
uninsured damages to its generation facilities and other property. The expense
of such damages is charged to the provision account. At December 31, 2002 and
2001, the accumulated provision for property damage was $15.5 million and $13.6
million respectively, and is included in other deferred credits in the
accompanying balance sheets. The FPSC approved annual accrual to the accumulated
provision for property damage is $3.5 million, with a target level for the
accumulated provision account between $25.1 and $36.0 million. The FPSC had also
given the Company the flexibility to increase its annual accrual amount above
$3.5 million at the Company's discretion. The Company accrued $3.5 million in
2002, $4.5 million in 2001, and $3.5 million in 2000 to the accumulated
provision for property damage. The Company had a net charge of $1.6 million to
the provision account in 2002 and had a net credit of $(0.3) million to the
provision account in 2001 related to insurance proceeds that exceeded actual
claims. In 2000, the Company charged $0.3 million to the provision account.
2. RETIREMENT BENEFITS
The Company has a defined benefit, trusteed, non-contributory pension plan that
covers substantially all regular employees. The Company also provides certain
non-qualified benefit plans for a selected group of management and highly
compensated 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. In late 2000, as well as in
2002, the Company adopted several pension and postretirement benefit plan
changes that had the effect of increasing benefits to both current and future
retirees.
Plan assets consist primarily of domestic and international equities, global
fixed income securities, real estate, and private equity investments. The
measurement date for plan assets and obligations is September 30 for each year.
The weighted average rates assumed in the actuarial calculations for both the
pension plan and postretirement benefits plan were:
2002 2001 2000
- ------------------------------------------------------------------
Discount 6.50% 7.50% 7.50%
Annual salary increase 4.00% 5.00% 5.00%
Long-term return on
plan assets 8.50% 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
---------------------------
2002 2001
- ---------------------------------------------------------------
(in thousands)
Balance at beginning of year $169,251 $153,214
Service cost 4,910 4,703
Interest cost 12,394 11,644
Benefits paid (8,395) (8,105)
Actuarial (gain)/loss and
employee transfers, net 2,672 (195)
Amendments - 7,997
Other 4,155 (7)
- --------------------------------------------------------------
Balance at end of year $184,987 $169,251
==============================================================
Plan Assets
---------------------------
2002 2001
- ---------------------------------------------------------------
(in thousands)
Balance at beginning of year $233,706 $283,266
Actual return on plan assets (15,694) (40,841)
Benefits paid (7,934) (7,758)
Employee transfers 1,088 (961)
- ---------------------------------------------------------------
Balance at end of year $211,166 $233,706
===============================================================
II-162
NOTES (continued)
Gulf Power Company 2002 Annual Report
The accrued pension costs recognized in the Balance Sheets
were as follows:
2002 2001
- -------------------------------------------------------------
(in thousands)
Funded status $26,179 $64,455
Unrecognized transition
obligation (2,161) (2,832)
Unrecognized prior
service cost 14,874 11,689
Unrecognized net gain (6,589) (47,038)
4th quarter cash flow
adjustment 85 90
- -------------------------------------------------------------
Prepaid asset, net 32,388 26,364
Portion included in
benefit obligations 3,910 3,616
- -------------------------------------------------------------
Total Prepaid asset recognized
in the Balance Sheets $36,298 $29,980
=============================================================
In 2002 amounts recognized in the Balance Sheets for accumulated other
comprehensive income and intangible assets were $1.2 million and $0.9 million.
In 2001, the amount recognized for intangible assets was $1.2 million.
Components of the pension plan's net periodic cost were as follows:
2002 2001 2000
- ----------------------------------------------------------------
Service cost $ 4,910 $ 4,703 $ 4,367
Interest cost 12,394 11,644 10,695
Expected return on
plan assets (20,431) (19,312) (17,504)
Recognized net gain (2,746) (3,072) (2,582)
Net amortization 298 165 (235)
- ----------------------------------------------------------------
Net pension income $ (5,575) $ (5,872) $ (5,259)
===============================================================
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
-------------------------
2002 2001
- -------------------------------------------------------------
(in thousands)
Balance at beginning of year $54,337 $50,025
Service cost 948 983
Interest cost 3,992 3,886
Benefits paid (1,984) (1,823)
Amendments - 3,412
- -------------------------------------------------------------
Actuarial (gain)/loss 6,382 (2,146)
- -------------------------------------------------------------
Balance at end of year $63,675 $54,337
=============================================================
Plan Assets
-----------------------
2002 2001
- -----------------------------------------------------------
(in thousands)
Balance at beginning of year $11,632 $13,388
Actual return on plan assets (793) (1,830)
Employer contributions 2,038 1,897
Benefits paid (1,984) (1,823)
- -----------------------------------------------------------
Balance at end of year $10,893 $11,632
===========================================================
The accrued postretirement costs recognized in the Balance
Sheets were as follows:
2002 2001
- -------------------------------------------------------------
(in thousands)
Funded status $(52,782) $(42,705)
Unrecognized transition
obligation 3,656 4,012
Unrecognized prior
service cost 5,349 5,695
Unrecognized net loss 9,530 1,235
Fourth quarter contributions 581 386
- -------------------------------------------------------------
Accrued liability recognized
in the Balance Sheets $(33,666) $(31,377)
=============================================================
II-163
NOTES (continued)
Gulf Power Company 2002 Annual Report
Components of the postretirement plan's net periodic cost
were as follows:
2002 2001 2000
- -----------------------------------------------------------------
Service cost $ 948 $ 983 $ 896
Interest cost 3,991 3,886 3,515
Expected return on
plan assets (1,100) (1,037) (901)
Transition obligation 356 356 355
Prior service cost 346 299 159
Recognized net (gain)/loss
(19) (18) 13
- -----------------------------------------------------------------
Net post-retirement cost $ 4,522 $ 4,469 $4,037
=================================================================
An additional assumption used in measuring the accumulated postretirement
benefit obligations was a weighted average medical care cost trend rate of 9.25
percent for 2002, decreasing gradually to 5.25 percent through the year 2010,
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, 2002 as follows (in thousands):
1 Percent
Increase Decrease
- ---------------------------------------------------------------
Benefit obligation $4,846 $4,293
Service and interest costs $381 $325
===============================================================
Employee Savings Plan
The Company also sponsors a 401(k) defined contribution plan covering
substantially all employees. The Company provides a 75 percent matching
contribution up to 6 percent of an employee's base salary. Total matching
contributions made to the plan for the years 2002, 2001, and 2000 were $2.5
million, $2.3 million, and $2.2 million, respectively.
3. CONTINGENCIES AND REGULATORY
MATTERS
General Litigation Matters
The Company is subject to certain claims and legal actions arising in the
ordinary course of business. The Company's business activities are also subject
to extensive governmental regulation related to public health and the
environment. Litigation over environmental issues and claims of various types,
including property damage, personal injury, and citizen enforcement of
environmental requirements, has increased generally throughout the United
States. In particular, personal injury claims for damages caused by alleged
exposure to hazardous materials have become more frequent.
The ultimate outcome of such litigation currently filed against the Company
cannot be predicted at this time; however, after consultation with legal
counsel, management does not anticipate that the liabilities, if any, arising
from such proceedings would have a material adverse effect on the Company's
financial statements.
Environmental Cost Recovery
In 1993, the Florida Legislature adopted legislation for an Environmental Cost
Recovery Clause (ECRC), which allows an electric 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. Such environmental
costs include operation and maintenance expense, emission allowance expense,
depreciation, and a return on invested capital.
This legislation was amended in 2002 to allow recovery of costs incurred as a
result of an agreement between the Company and FDEP for the purpose of ensuring
compliance with ozone ambient air quality standards adopted by the EPA. During
2002, 2001, and 2000, the Company recorded ECRC revenues of $10.8 million, $10.0
million, and $9.9 million, respectively.
At December 31, 2002, the Company's liability for the estimated costs of
environmental remediation projects for known sites was $14.4 million. These
estimated costs are expected to be expended from 2003 through 2012. These
projects have been approved by the FPSC for recovery through the ECRC discussed
above. Therefore, the Company recorded $1.3 million in current assets and
current liabilities and $13.1 million in deferred assets and deferred
liabilities representing the future recoverability of these costs.
Environmental Protection Agency Litigation
In November 1999, the EPA brought a civil action in the U.S. District Court
against Alabama Power, Georgia Power, and SCS. The complaint alleges violations
II-164
NOTES (continued)
Gulf Power Company 2002 Annual Report
of the 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 operating companies 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 5 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 the Company, 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 control equipment when performing maintenance and
construction at coal burning plants constructed or under construction prior to
1978. On August 1, 2000 the U.S. District Court in Georgia granted Alabama
Power's motion to dismiss for lack of jurisdiction in Georgia and granted SCS's
motion to dismiss on the grounds that it neither owned nor operated the
generating units involved in the proceedings. The court granted the EPA's motion
to add Savannah Electric as a defendant, but denied the motion to add the
Company and Mississippi Power based on lack of jurisdiction. As directed by the
court, the EPA re-filed its amended complaint limiting claims to those brought
against Georgia Power and Savannah Electric. Also, the EPA re-filed its claims
against Alabama Power in the U.S. District Court in Alabama. It has not re-filed
its claims against the Company, Mississippi Power, or SCS.
The Alabama Power, Georgia Power, and Savannah Electric cases have been
stayed since the spring of 2001, pending a ruling by the U.S. Court of Appeals
for the Eleventh Circuit in the appeal of a very similar New Source Review
enforcement action against the Tennessee Valley Authority (TVA). The TVA appeal
involves many of the same legal issues raised by the actions against Alabama
Power, Georgia Power, and Savannah Electric. Because the outcome of the TVA
appeal could have a significant adverse impact on Alabama Power and Georgia
Power, both companies have been parties to that case as well. In February 2003,
the U.S. District Court in Alabama extended the stay of the EPA litigation
proceeding in Alabama until the earlier of May 6, 2003 or a ruling by the U.S.
Court of Appeals for the Eleventh Circuit in the related litigation involving
TVA. On August 21, 2002, the U.S. District Court in Georgia denied the EPA's
motion to reopen the Georgia case. The denial was without prejudice to the EPA
to refile the motion at a later date, which the EPA has not done at this time.
The Company believes that it has 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.
Personal Injury Litigation
On January 28, 2003 a jury in Escambia County, Florida returned a verdict of $3
million against the Company arising out of an alleged electrical injury
sustained by the plaintiff in January 1999 while inside his apartment. If the
verdict is not overturned, the plaintiff will also be entitled to recover
attorney's fees. The Company intends to seek a new trial; however, if the
Company is not successful in obtaining a new trial, it intends to pursue an
appeal. The ultimate outcome of this matter cannot now be determined but is not
expected to have a material impact on the Company's financial statements.
Right of Way Litigation
In 2002, certain subsidiaries of Southern Company, including the Company,
Georgia Power, Mississippi Power, Savannah Electric, and Southern Telecom
(collectively, defendants), were named as defendants in numerous lawsuits
brought by landowners regarding the installation and use of fiber optic cable
over defendants' rights of way located on the landowners' property. The
plaintiffs' lawsuits claim that defendants may not use or sublease to third
parties some or all of the fiber optic communications lines on the rights of way
II-165
NOTES (continued)
Gulf Power Company 2002 Annual Report
that cross the plaintiffs' properties, and that such actions by defendants
exceed the easements or other property rights held by defendants. The plaintiffs
assert claims for, among other things, trespass and unjust enrichment. The
plaintiffs seek compensatory and punitive damages and injunctive relief.
Defendants believe that the plaintiffs' claims are without merit. An adverse
outcome in these matters could result in substantial judgments; however, the
final outcome of these matters cannot now be determined.
Retail Rate Case
In September 2001 the Company filed a request with the FPSC for a base rate
increase of approximately $70 million, the majority of which was related to the
Plant Smith Unit 3 combined cycle facility which was placed in service in April
2002. In May 2002, the FPSC approved a retail base rate increase of $53.2
million effective June 7, 2002.
Retail Revenue Sharing Plan
In October 1999, the Office of Public Counsel, the Coalition for Equitable
Rates, the Florida Industrial Power Users Group, and the Company jointly filed a
petition with the FPSC that included a reduction to retail base rates of $10
million annually and provided for revenues to be shared within set ranges for
1999 through 2002. Customers received two-thirds of any revenue within the
sharing range and the Company retained one-third. The stipulation also included
authorization for the Company, at its discretion, to accrue up to an additional
$5 million to the property insurance reserve and $1 million to amortize a
regulatory asset related to the corporate office. The FPSC approved stipulation
became effective in November 1999.
The Company recorded revenues subject to refund (with interest) of $1.5
million in 2001 and $7.2 million in 2000. No refund was required in 2002.
In addition to the refund, the Company amortized $1.0 million of the
regulatory asset related to the corporate office and accrued an additional $1.0
million to the property insurance reserve in 2001. The sharing plan expired
April 21, 2002.
4. COMMITMENTS
Construction Program
The Company is engaged in a continuous construction program, the cost of which
is currently estimated to total $108 million in 2003, $150 million in 2004, and
$156 million in 2005. 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, 2002 significant purchase commitments were outstanding in
connection with the construction program.
Included in the amounts above, the Company has budgeted $34 million, $52
million, and $47 million in 2003, 2004, and 2005, respectively, for capital
expenditures related to environmental controls at Plant Crist as part of an
agreement with the FDEP to reduce NOx emissions. The FPSC authorized the Company
to recover the costs related to these environmental projects through the
Environmental Cost Recovery Clause. The Company's remaining construction program
is related to maintaining and upgrading the transmission, distribution, and
generating facilities.
Long-Term Service Agreements
The Company has entered into a Long-Term Service Agreement (LTSA) with General
Electric (GE) for the purpose of securing maintenance support for combined cycle
and combustion turbine generating facilities. In summary, the LTSA stipulates
that GE will perform all planned inspections on the covered equipment, which
includes the cost of all labor and materials. GE is also obligated to cover the
costs of unplanned maintenance on the covered equipment subject to a limit
specified in the contract.
In general, the LTSA is in effect through two major inspection cycles of the
unit. Scheduled payments to GE are made at various intervals based on actual
operating hours of the unit. Total payment to GE under this agreement for
facilities owned is currently estimated at $96.5 million over approximately 13
II-166
NOTES (continued)
Gulf Power Company 2002 Annual Report
years. However, the LTSA contains various cancellation provisions at the option
of the Company.
Payments made to GE prior to the performance of any planned inspections are
recorded as a prepayment in the Balance Sheets. Inspection costs are capitalized
or charged to expense based on the nature of the work performed.
Fuel Commitments
To supply a portion of the fuel requirements of its generating plants, the
Company has entered into contract commitments for the procurement of fuel. In
some cases, these contracts contain provisions for price escalations, minimum
purchase levels, and other financial commitments. Total estimated obligations at
December 31, 2002 were as follows:
Year Fuel
---- ----------------
(in millions)
2003 $113
2004 90
2005 92
2006 93
2007 95
2008 and thereafter 312
----------------------------------------------------------
Total commitments $795
==========================================================
In addition, SCS acts as an agent for the five operating companies, Southern
Power, and Southern GAS with regard to natural gas purchases. Natural gas
purchases (in dollars) are based on various indices at the actual time of
delivery; therefore, only the volume commitments are firm. The Company's
committed volumes are allocated based on usage projections as of December 31 as
follows:
Year Natural Gas
----- ----------------
(MMBtu)
2003 24,879,611
2004 15,595,381
2005 5,758,513
2006 3,696,035
2007 1,235,291
--------------------------------------------------------
Total commitments 51,164,831
========================================================
Additional commitments for fuel will be required to supply the Company's
future needs.
Acting as an agent for all of Southern Company's operating companies,
Southern Power and Southern GAS, SCS may enter into various types of wholesale
energy and natural gas contracts. Each of the operating companies, Southern
Power, and Southern GAS may be jointly and severally liable under these
agreements. The creditworthiness of Southern Power and Southern GAS is currently
inferior to the creditworthiness of the operating companies. Southern Company
has entered into keep-well agreements with each of the operating companies to
insure it will not subsidize or be responsible for any costs, losses,
liabilities, or damages resulting from the inclusion of Southern Power or
Southern GAS as a contracting party under these agreements.
Lease Agreements
The Company has operating lease agreements with various terms and expiration
dates. Total operating lease expenses were $2.1 million, $1.9 million, and $2.4
million for 2002, 2001, and 2000, respectively.
At December 31, 2002, estimated minimum rental commitments for noncancelable
operating leases were as follows:
Year Amounts
---- ---------------
(in thousands)
2003 $2,141
2004 2,150
2005 2,165
2006 2,042
2007 2,038
2008 and thereafter 10,190
------------------------------------------------------------
Total commitments $20,726
============================================================
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 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.
II-167
NOTES (continued)
Gulf Power Company 2002 Annual Report
The Company, as a joint owner of Plant Daniel, is responsible for one half of
the lease costs. The lease commitments above include the railcar lease amounts.
The lease costs are charged to fuel inventory and are allocated to fuel expense
as the fuel is used. These expenses are then recovered through the Company's
fuel cost recovery clause. The Company's share of the lease costs charged to
fuel inventories was $1.9 million in 2002 and $1.9 million in 2001. The annual
amounts for 2003 through 2007 are expected to be $1.9 million, $1.9 million,
$2.0 million, $2.0 million, and $2.0 million, respectively, and after 2007 are
expected to total $10.2 million.
Guarantees
Prior to 1999, a subsidiary of Southern Company originated loans to residential
customers of the operating companies for heat pump purchases. These loans were
sold to Fannie Mae with recourse for any loan with payments outstanding over 120
days. The Company is responsible for the repurchase of its customers' delinquent
loans. As of December 31, 2002, the outstanding loans guaranteed by the Company
totaled $1 million and a loan loss reserve of $0.2 million has been recorded.
5. JOINT OWNERSHIP AGREEMENTS
The Company and Mississippi Power jointly own Plant Daniel Unit No. 1 and Unit
No. 2, which together represent capacity of 1,000 MWs. Plant Daniel is a
generating plant located in Jackson County, Mississippi. In accordance with the
operating agreement, Mississippi Power acts as the Company's agent with respect
to the construction, operation, and maintenance of these units.
The Company and Georgia Power jointly own the 818 MW capacity Plant Scherer
Unit No. 3. Plant Scherer is a generating plant located near Forsyth, Georgia.
In accordance with the operating agreement, Georgia Power acts as the Company's
agent with respect to the construction, operation, and maintenance of the unit.
The Company's pro rata share of expenses related to both plants is included
in the corresponding operating expense accounts in the Statements of Income.
At December 31, 2002, the Company's percentage ownership and its investment
in these jointly owned facilities were as follows:
Plant Plant
Scherer Daniel Unit
Unit No. 3 Nos. 1 & 2
(coal) (coal)
-----------------------------
(in thousands)
Plant In Service $187,768(1) $232,272
Accumulated Depreciation $77,476 $119,655
Construction Work in Progress $258 $3,512
Ownership 25% 50%
- ------------------------------------------------------------------
(1) Includes net plant acquisition adjustment.
6. LONG-TERM POWER SALES AGREEMENTS
The Company and the other operating affiliates have long-term contractual
agreements for the sale of capacity to certain non-affiliated utilities located
outside the system's service area. The unit power sales agreements are fixed 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 $19.9 million in 2002, $19.5 million in 2001, and $20.3 million in 2000.
Unit power from specific generating plants of Southern Company is currently
being sold to Florida Power Corporation (FPC), Florida Power & Light Company
(FP&L), and Jacksonville Electric Authority (JEA). Under these agreements, 210
megawatts of net dependable capacity were sold by the Company during 2002. Sales
will remain close to that level, unless reduced by FP&L, FPC, and JEA with a
minimum of three years notice, until the expiration of the contracts in 2010.
7. INCOME TAXES
At December 31, 2002, the tax-related regulatory assets to be recovered from
customers were $ 18.8 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, 2002,
the tax-related regulatory liabilities to be credited to customers were $29.7
II-168
NOTES (continued)
Gulf Power Company 2002 Annual Report
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:
2002 2001 2000
------------------------------------
(in thousands)
Total provision for income taxes:
Federal--
Current $24,474 $24,207 $37,250
Deferred 7,936 2,568 (11,159)
- --------------------------------------------------------------------
32,410 26,775 26,091
- --------------------------------------------------------------------
State--
Current 3,051 3,701 5,796
Deferred 1,683 826 (1,357)
- --------------------------------------------------------------------
4,734 4,527 4,439
- --------------------------------------------------------------------
Total $37,144 $31,302 $30,530
====================================================================
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:
2002 2001
---------------------------
(in thousands)
Deferred tax liabilities:
Accelerated depreciation $188,879 $179,071
Other 28,377 27,328
- ---------------------------------------------------------------------
Total 217,256 206,399
- ---------------------------------------------------------------------
Deferred tax assets:
Federal effect of state deferred taxes 9,421 9,009
Postretirement benefits 10,826 9,379
Other 18,396 17,881
- ---------------------------------------------------------------------
Total 38,643 36,269
- ---------------------------------------------------------------------
Net deferred tax liabilities 178,613 170,130
Less current portion, net (10,924) (8,162)
- ---------------------------------------------------------------------
Accumulated deferred income
taxes in the Balance Sheets $167,689 $161,968
=====================================================================
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 $1.8 million in 2002, $1.7 million in 2001, and 1.9
million in 2000. At December 31, 2002, 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:
2002 2001 2000
----------------------------
Federal statutory rate 35% 35% 35%
State income tax,
net of federal deduction 3 4 4
Non-deductible book
depreciation 1 1 1
Difference in prior years'
deferred and current tax rate (2) (2) (2)
Other, net (1) (3) (1)
- ----------------------------------------------------------------
Effective income tax rate 36% 35% 37%
================================================================
The Company and the other subsidiaries of Southern Company file a
consolidated federal tax return. Under a joint consolidated income tax
agreement, each subsidiary's current and deferred tax expense is computed on a
stand-alone basis. In accordance with Internal Revenue Service regulations, each
company is jointly and severally liable for the tax liability.
8. CAPITALIZATION
Preferred Securities
Statutory business trusts formed by the Company, of which the Company owns all
the common securities, have issued mandatorily redeemable preferred securities.
The following securities are currently outstanding:
Date of Maturity
Issue Amount Rate Notes Date
---------------------------------------------------
(millions) (millions)
Trust I 01/1997 $40 7.625 $41 12/2036
Trust II 01/1998 45 7.000 46 12/2037
Trust III 11/2001 30 7.375 31 09/2041
Trust IV 12/2002 40 5.600* 41 11/2042
* Issued to redeem the 7.625 percent Trust I preferred securities in January
2003 at a five year initial fixed rate of 5.60 percent and, thereafter, at
fixed rates determined through remarketings for specific periods of varying
length or at floating rates determined by reference to 3-month LIBOR plus
3.49%.
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
II-169
NOTES (continued)
Gulf Power Company 2002 Annual Report
preferred securities. The Trusts are subsidiaries of the Company and accordingly
are consolidated in the Company's financial statements.
Securities Due Within One Year
At December 31, 2002, the Company had an improvement fund requirement of
$550,000. 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 cash, reacquiring bonds, or by pledging additional property equal to
1 and 2/3 times the requirement.
The sinking fund requirements of first mortgage bonds were satisfied by
certifying property additions in 2002 and 2001. It is anticipated that the 2003
requirement will be satisfied by certifying property additions. Sinking fund
requirements and/or maturities through 2007 applicable to long-term debt are as
follows: $60.6 million in 2003; $50.6 million in 2004; $0.6 million in 2005;
$37.6 million in 2006; and $0.3 million in 2007.
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, 2002, retained earnings of $127 million were
restricted against the payment of cash dividends on common stock under the terms
of the mortgage indenture.
Bank Credit Arrangements
At December 31, 2002, the Company had $66.3 million of lines of credit with
banks subject to renewal the following year, all of which remained unused. The
$66.3 million in committed lines of credit provide liquidity support for Gulf's
commercial paper program and for $3.9 million of daily 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.
Certain credit arrangements contain covenants that limit the level of
indebtedness to capitalization to 65 percent. Not meeting these limits would
result in an event of default under the credit arrangements. In addition,
certain credit arrangements contain cross default provisions to other
indebtedness that would trigger an event of default if the borrower defaulted on
indebtedness over a specified threshold. The cross default provisions are
restricted only to indebtedness of the Company. The Company is currently in
compliance with all such covenants. Borrowings under unused credit arrangements
totaling $20 million would be prohibited if the Company experiences a material
adverse change (as defined in such arrangements).
The Company borrows through a commercial paper program that has the liquidity
support of committed bank credit arrangements and through an extendible
commercial note program. The amount of commercial paper outstanding at December
31, 2002 was $8.5 million.
In addition, the Company has bid-loan facilities with five major money center
banks that total $50 million, with none committed at December 31, 2002.
Assets Subject to Lien
The Company'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.
9. QUARTERLY FINANCIAL DATA (Unaudited)
Summarized quarterly financial data for 2002 and 2001 are as follows:
Net Income
Operating Operating After Dividends
Quarter Ended Revenues Income on Preferred Stock
- ----------------------------------------------------------------------
(in thousands)
March 2002 $160,933 $24,493 $11,717
June 2002 209,987 31,174 13,487
September 2002 245,601 65,661 33,979
December 2002 203,946 24,159 7,853
March 2001 $165,029 $24,785 $10,196
June 2001 180,430 30,702 14,770
September 2001 226,616 45,504 26,657
December 2001 153,128 16,268 6,684
- ----------------------------------------------------------------------
The Company's business is influenced by seasonal weather conditions and the
timing of rate changes, among other factors.
II-170
SELECTED FINANCIAL AND OPERATING DATA 1998-2002
Gulf Power Company 2002 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------------
2002 2001 2000 1999 1998
- ----------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands) $820,467 $725,203 $714,319 $674,099 $650,518
Net Income after Dividends
on Preferred Stock (in thousands) $67,036 $58,307 $51,843 $53,667 $56,521
Cash Dividends
on Common Stock (in thousands) $65,500 $53,275 $59,000 $61,300 $57,200
Return on Average Common Equity (percent) 12.72 12.51 12.20 12.63 13.20
Total Assets (in thousands) $1,673,829 $1,573,133 $1,315,496 $1,308,495 $1,267,901
Gross Property Additions (in thousands) $106,624 $274,668 $95,807 $69,798 $69,731
- ----------------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $549,505 $504,894 $427,378 $422,313 $427,652
Preferred stock 4,236 4,236 4,236 4,236 4,236
Company obligated mandatorily
redeemable preferred securities 155,000 115,000 85,000 85,000 85,000
Long-term debt 452,040 467,784 365,993 367,449 317,341
- ----------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $1,160,781 $1,091,914 $882,607 $878,998 $834,229
==================================================================================================================================
Capitalization Ratios (percent):
Common stock equity 47.3 46.2 48.4 48.0 51.3
Preferred stock 0.4 0.4 0.5 0.5 0.5
Company obligated mandatorily
redeemable preferred securities 13.4 10.5 9.6 9.7 10.2
Long-term debt 38.9 42.9 41.5 41.8 38.0
- ----------------------------------------------------------------------------------------------------------------------------------
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+ AA- AA-
Fitch A+ A+ AA- AA- AA-
Preferred Stock -
Moody's Baa1 Baa1 a2 a2 a2
Standard and Poor's BBB+ BBB+ BBB+ A- A
Fitch 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
Fitch A A A+ A+ A+
==================================================================================================================================
Customers (year-end):
Residential 333,757 327,128 321,731 315,240 307,077
Commercial 49,411 48,654 47,666 47,728 46,370
Industrial 281 270 280 267 257
Other 474 468 442 316 268
- ----------------------------------------------------------------------------------------------------------------------------------
Total 383,923 376,520 370,119 363,551 353,972
==================================================================================================================================
Employees (year-end): 1,339 1,309 1,327 1,339 1,328
- ----------------------------------------------------------------------------------------------------------------------------------
II-171
SELECTED FINANCIAL AND OPERATING DATA 1998-2002 (continued)
Gulf Power Company 2002 Annual Report
- -------------------------------------------------------------------------------------------------------------------------------
2002 2001 2000 1999 1998
- -------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $365,693 $313,165 $302,210 $279,238 $279,621
Commercial 207,960 188,759 177,047 167,305 163,207
Industrial 89,385 81,719 74,095 68,222 71,119
Other 2,798 948 (4,712) 2,184 2,113
- -------------------------------------------------------------------------------------------------------------------------------
Total retail 665,836 584,591 548,640 516,949 516,060
Sales for resale - non-affiliates 77,171 82,252 66,890 62,354 61,893
Sales for resale - affiliates 40,391 27,256 66,995 66,110 42,642
- -------------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 783,398 694,099 682,525 645,413 620,595
Other revenues 37,069 31,104 31,794 28,686 29,923
- -------------------------------------------------------------------------------------------------------------------------------
Total $820,467 $725,203 $714,319 $674,099 $650,518
===============================================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 5,143,802 4,716,404 4,790,038 4,471,118 4,437,558
Commercial 3,552,931 3,417,427 3,379,449 3,222,532 3,111,933
Industrial 2,053,668 2,018,206 1,924,749 1,846,237 1,833,575
Other 21,496 21,208 18,730 19,296 18,952
- -------------------------------------------------------------------------------------------------------------------------------
Total retail 10,771,897 10,173,245 10,112,966 9,559,183 9,402,018
Sales for resale - non-affiliates 2,156,741 2,093,203 1,705,486 1,561,972 1,341,990
Sales for resale - affiliates 1,720,240 962,892 1,916,526 2,511,983 1,758,150
- -------------------------------------------------------------------------------------------------------------------------------
Total 14,648,878 13,229,340 13,734,978 13,633,138 12,502,158
===============================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 7.11 6.64 6.31 6.25 6.30
Commercial 5.85 5.52 5.24 5.19 5.24
Industrial 4.35 4.05 3.85 3.70 3.88
Total retail 6.18 5.75 5.43 5.41 5.49
Sales for resale 3.03 3.58 3.70 3.15 3.37
Total sales 5.35 5.25 4.97 4.73 4.96
Residential Average Annual
Kilowatt-Hour Use Per Customer 15,510 14,497 14,992 14,318 14,577
Residential Average Annual
Revenue Per Customer $1,100.35 $962.57 $945.87 $894.18 $918.56
Plant Nameplate Capacity
Ratings (year-end) (megawatts) 2,809 2,188 2,188 2,188 2,188
Maximum Peak-Hour Demand (megawatts):
Winter 2,182 2,106 2,154 2,085 2,040
Summer 2,454 2,223 2,285 2,161 2,146
Annual Load Factor (percent) 55.3 57.5 55.4 55.2 55.3
Plant Availability Fossil-Steam (percent): 90.6 90.1 85.2 87.2 87.6
- -------------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 69.8 81.2 87.8 89.8 89.2
Gas 15.5 1.0 1.6 2.5 2.0
Purchased power -
From non-affiliates 4.6 6.5 7.6 5.9 5.5
From affiliates 10.1 11.3 3.0 1.8 3.3
- -------------------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0 100.0 100.0
===============================================================================================================================
II-172
MISSISSIPPI POWER COMPANY
FINANCIAL SECTION
II-173
MANAGEMENT'S REPORT
Mississippi Power Company 2002 Annual Report
The management of Mississippi Power Company (the Company) has prepared - and is
responsible for - the financial statements and related information included in
this report. These statements were prepared in accordance with accounting
principles generally accepted in the United States 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 accounting records
reflect only authorized transactions of the Company. Limitations exist in any
system of internal controls, however, based on 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.
Southern Company's audit committee of its board of directors, composed of
five independent directors, provides a broad overview of management's financial
reporting and control functions. Additionally, a committee of the Company's
board of directors, composed of four outside directors, meets periodically with
management, the internal auditors, and the independent public accountants to
discuss auditing, internal controls, and compliance matters. The internal
auditors and independent public accountants have access to the members of these
committees 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 the Company in conformity with accounting principles generally accepted in
the United States.
/s/Michael D. Garrett
Michael D. Garrett
President and Chief Executive Officer
/s/Michael W. Southern
Michael W. Southern
Vice President, Treasurer and
Chief Financial Officer
February 17, 2003
II-174
INDEPENDENT AUDITOR'S REPORT
Mississippi Power Company:
We have audited the accompanying balance sheet and statement of capitalization
of Mississippi Power Company (a wholly owned subsidiary of Southern Company) as
of December 31, 2002, and the related statements of income, comprehensive
income, common stockholder's equity, and cash flows for the year then ended.
These financial statements are the responsibility of Mississippi Power Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audit. The financial statements of Mississippi Power
Company as of December 31, 2001, and for each of the two years then ended were
audited by other auditors who have ceased operations. Those auditors expressed
an unqualified opinion on those financial statements and included an explanatory
paragraph that described a change in the method of accounting for derivative
instruments and hedging activities in their report dated February 13, 2002.
We conducted our audit in accordance with auditing standards generally
accepted in the United States of America. 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 audit provides a
reasonable basis for our opinion.
In our opinion, the 2002 financial statements (pages II-189 to II-209)
present fairly, in all material respects, the financial position of Mississippi
Power Company at December 31, 2002, and the results of its operations and its
cash flows for the year then ended, in conformity with accounting principles
generally accepted in the United States of America.
/s/Deloitte & Touche LLP
Atlanta, Georgia
February 17, 2003
THE FOLLOWING REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS IS A COPY OF THE REPORT
PREVIOUSLY ISSUED IN CONNECTION WITH THE COMPANY'S 2001 ANNUAL REPORT ON FORM
10-K AND HAS NOT BEEN REISSUED BY ARTHUR ANDERSEN LLP. SEE EXHIBIT 23(e)2 FOR
ADDITIONAL INFORMATION.
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, 2001 and 2000, 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, 2001. 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-160 through II-176)
referred to above present fairly, in all material respects, the financial
position of Mississippi Power Company as of December 31, 2001 and 2000, and the
results of its operations and its cash flows for each of the three years in the
period ended December 31, 2001, in conformity with accounting principles
generally accepted in the United States.
As explained in Note 1 to the financial statements, effective January 1,
2001, Mississippi Power Company changed its method of accounting for derivative
instruments and hedging activities.
/s/ Arthur Andersen LLP
Atlanta, Georgia
February 13, 2002
II-175
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Mississippi Power Company 2002 Annual Report
RESULTS OF OPERATIONS
Earnings
Mississippi Power Company's net income after dividends on preferred stock of
$73.0 million in 2002 and $63.9 million in 2001 increased $9.1 million and $8.9
million, respectively, from the prior year. The 2002 increase in net income was
primarily attributable to the retail and wholesale rate increases in late 2001
and early 2002, respectively, and lower interest expense. The increase in net
income for 2001 was due primarily to the commercial operation of Plant Daniel
Units 3 and 4 and lower interest costs. The Company's 2000 net income after
dividends on preferred stock of $55 million was relatively unchanged from the
prior year.
A condensed income statement for 2002 including the change by year is as
follows:
Increase (Decrease)
Amount From Prior Year
- ------------------------------------------------------------------
2002 2002 2001 2000
- -------------------------------------------------------------------
(in thousands)
Operating revenues $824,165 $ 28,100 $ 108,463 $54,598
- -------------------------------------------------------------------
Fuel 282,393 4,447 86,819 18,441
Purchased power 51,333 (43,911) (11,895) 36,052
Other operation
and maintenance 232,013 41,015 23,193 (4,571)
Depreciation
and amortization 57,638 3,561 3,802 1,069
Taxes other than
income taxes 55,518 10,552 (3,720) 793
- -------------------------------------------------------------------
Total operating
expenses 678,895 15,664 98,199 51,784
- -------------------------------------------------------------------
Operating income 145,270 12,436 10,264 2,814
Other income
(expense), net (26,378) 2,036 4,828 (2,412)
Less --
Income taxes (45,879) (5,346) (6,177) (239)
- -------------------------------------------------------------------
Net Income $ 73,013 $ 9,126 $ 8,915 $ 163
===================================================================
Revenues
Details of the Company's operating revenues in 2002 and the prior
two years are as follows:
Amount
--------------------------------------
2002 2001 2000
--------------------------------------
(in thousands)
Retail - prior year $489,153 $498,551 $469,434
Change in --
Base rates 38,143 - -
Sales growth 566 (1,048) (11,510)
Weather 3,533 (1,953) 7,167
Fuel cost recovery
and other 5,432 (6,397) 33,460
- -----------------------------------------------------------------
Total retail 536,827 489,153 498,551
- -----------------------------------------------------------------
Sales for resale --
Non-affiliates 224,275 204,623 145,931
Affiliates 46,314 85,652 27,915
- -----------------------------------------------------------------
Total sales for resale 270,589 290,275 173,846
- -----------------------------------------------------------------
Other electric
operating revenues 16,749 16,637 15,205
- -----------------------------------------------------------------
Total electric
operating revenues $824,165 $796,065 $687,602
=================================================================
Percent change 3.5% 15.8% 8.6%
- -----------------------------------------------------------------
Total retail revenues for 2002 increased approximately 9.7 percent when
compared to 2001, primarily due to a retail rate increase which took effect in
January 2002 and, to a lesser extent, higher kilowatt-hour energy sales
resulting from colder winter weather. See Note 3 to the financial statements
under "2001 Retail Rate Case" for additional information. Retail revenues for
2001 reflected a 1.9 percent decrease from 2000 due to lower energy sales to
residential, commercial, and industrial customers as a result of mild weather
and a slowdown in manufacturing activity in the Company's service territory.
Retail revenues for 2000 reflected a 6.2 percent increase over the prior year
due to increased fuel revenues and a positive weather impact.
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.
Sales for resale to non-affiliates are influenced by the non-affiliate
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
II-176
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2002 Annual Report
southeastern Mississippi. Energy sales to these utilities increased 8.0 percent
in 2002, decreased 3.7 percent in 2001 and increased 10.9 percent in 2000, with
the related revenues increasing 19.8 percent, decreasing 2.4 percent and
increasing 10.8 percent, respectively. The customer demand experienced by these
utilities is determined by factors very similar to those of the Company.
Revenues from sales for resale to non-affiliates increased in 2002 and 2001,
primarily as the result of a new power sales contract associated with Plant
Daniel Units 3 and 4 that began in June 2001 as well as colder winter months
during 2002. Revenues from sales for resale to non-affiliates increased in 2000
as a result of off system sale transactions that were generally offset by
corresponding purchase transactions. These transactions had no significant
impact on net income.
Energy sales to affiliated companies within the Southern Company electric
system, as well as purchases, will 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.
Kilowatt-hour (KWH) sales for 2002 and percent change by year were as
follows:
KWH Percent Change
2002 2002 2001 2000
------------------------------------------------------------------
(in millions)
Residential 2,300 6.3% (5.4)% 1.7%
Commercial 2,902 2.1 (1.5) 1.3
Industrial 4,162 (2.7) (2.3) (0.7)
Other 40 - (0.3) 2.5
--------
Total retail 9,404 0.1 (2.8) 0.5
Sales for Resale
Non-Affiliated 5,380 7.4 36.4 12.9
Affiliated 1,587 (46.3) 552.3 (16.2)
--------
Total 16,371 (5.3) 26.0 2.8
==================================================================
Total retail kilowatt-hour sales increased slightly in 2002 due to colder
than average winter weather, which primarily affects residential sales. In
addition, commercial sales increased 2.1 percent due primarily to growth in the
health, education and retail sales areas. Industrial sales fell 2.7 percent in
2002 due to an economic downturn in the Company's service area. In 2001,
residential sales decreased 5.4 percent due to unusually mild weather in the
Company's service area. The commercial sales and industrial sales in 2001
decreased 1.5 percent and 2.3 percent, respectively, due to an economic
slowdown. Total retail kilowatt-hour sales increased slightly in 2000, primarily
as a result of weather impacts. Kilowatt-hour sales for non-affiliated sales for
resale increased in 2002 and 2001 due to the increased demand from these
customers and the commercial operation of Plant Daniel Units 3 and 4 in May
2001.
Expenses
Total operating expenses were $679 million in 2002, reflecting an increase of
2.4 percent over the prior year. The increase was due primarily to the increase
in fuel expense, the increase in maintenance expense due to planned outages at
Plant Watson and Plant Daniel and a full year of rental expense for Plant Daniel
Units 3 and 4. In 2001, total operating expenses increased by 17.4 percent over
the prior year due primarily to the commercial operation and related lease of
Plant Daniel Units 3 and 4 beginning in May 2001. See Note 8 to the financial
statements under "Lease Agreements" for additional information. In 2000, total
operating expenses increased by 10.1 percent over the prior year due primarily
to higher fuel and purchased power expenses.
Fuel costs are the single largest expense for the Company. Fuel expenses
for 2002, 2001 and 2000 increased 1.6 percent, 45.4 percent and 10.7 percent,
respectively. The increase for 2002 was due to a fuel hedging loss, which is
approved for recovery by the Mississippi Public Service Commission (MPSC)
through the energy cost management plan (ECM). The 2001 increase was due to
increased generation including Plant Daniel Units 3 and 4 and a higher average
cost of fuel. The 2000 increase was due to increased generation and a higher
average cost of fuel.
In 2002, purchased power expense decreased 46.1 percent when compared to
2001. This decrease resulted from both lower prices and lower purchase
requirements, primarily due to the commercial operation of Plant Daniel Units 3
and 4 beginning in May 2001. In 2001, purchased power expenses decreased 11.1
percent primarily due to the commercial operation of Plant Daniel Units 3 and 4
and the expiration of non-affiliated purchase power contracts in 2000. In 2000,
purchased power expenses increased 51.0 percent primarily due to an increase in
off-system purchases used to meet off-system sales commitments. These
transactions had no significant effect on earnings.
II-177
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2002 Annual Report
The amount and sources of generation and the average cost of fuel per net
kilowatt-hour generated were as follows:
2002 2001 2000
- ----------------------------------------------------------------
Total generation
(millions of kilowatt hours) 15,079 15,770 11,688
Sources of generation
(percent) --
Coal 57 59 83
Gas 43 41 17
Average cost of fuel per net
kilowatt-hour generated
(cents) -- 2.03 1.89 1.80
- ----------------------------------------------------------------
Other operation expenses increased 17.4 percent in 2002 primarily due to
lease payments associated with the commercial operation of Plant Daniel Units 3
and 4 and higher labor related expenses. In 2001, other operation expense
increased 17.2 percent primarily due to an increase in other production expenses
resulting from the commercial operation of Plant Daniel Units 3 and 4. In 2000,
other operation expense decreased 8.2 percent primarily due to decreases in
expenses related to labor costs, legal costs and services provided by SCS.
Maintenance expense in 2002 increased 31.2 percent primarily due to scheduled
maintenance performed at Plant Watson and Plant Daniel, while maintenance
expense in 2001 increased 6.5 percent as a result of the commercial operation of
Plant Daniel Units 3 and 4. Maintenance expense in 2000 increased 12 percent
primarily due to additional scheduled maintenance. Depreciation and amortization
expense increased 6.6 percent and 7.6 percent in 2002 and 2001, respectively,
due to a growth in plant investment and amortization of the Company's regulatory
asset related to the recovery of environmental compliance costs. See Note 3 to
the financial statements under "Environmental Compliance Overview Plan" for
further information. In 2000, depreciation expense increased 2.2 percent due to
growth in plant investment and new depreciation rates, which became effective
January 2000.
Taxes other than income taxes increased 23.5 percent in 2002 due to
additional property taxes related to the Plant Daniel Units 3 and 4 and higher
municipal franchise taxes. These taxes decreased 7.6 percent in 2001 due to
reductions in certain ad valorem tax rates. These taxes increased 1.7 percent in
2000 due to higher municipal franchise taxes resulting from higher retail
revenues. Interest on long-term debt decreased in 2002 and 2001 as a result of
lower interest rates on debt outstanding.
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 costs does not recognize this economic loss nor the
partially offsetting gain that arises through financing facilities with
fixed-money obligations, such as long-term debt and preferred securities. Any
recognition of inflation by regulatory authorities is reflected in the rate of
return allowed in the Company's approved electric rates.
Future Earnings Potential
General
The results of continuing operations for the past three years are not
necessarily indicative of future earnings potential. The level of the Company's
future earnings depends on numerous factors. A major factor is a stable
regulatory environment and the Company's ability to achieve energy sales growth
while containing costs. Expenses are subject to constant review and cost control
programs. The Company is also maximizing invested capital and minimizing the
need for additional capital by refinancing outstanding obligations, managing the
size of its fuel stockpile, raising generating plant availability and
efficiency, and aggressively controlling its construction budget.
In the near term, future earnings will depend upon growth in energy sales,
which is subject to a number of factors. These factors include weather,
competition, changes in contracts with neighboring utilities, energy
conservation practiced by customers, the elasticity of demand, and the rate of
economic growth in the Company's service area. The Company anticipates somewhat
slower growth in energy sales as the tourism industry stabilizes within its
service area. In addition to tourism, the healthcare and retail trade sectors
will provide most of the anticipated energy growth for the commercial class of
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2002 Annual Report
customers, while shipbuilding, food products, and the U.S. government will
provide much of the basis for anticipated growth in the industrial sector.
The Company currently operates as a vertically integrated utility providing
electricity to customers within its traditional service area located in
southeastern Mississippi. Prices for electricity provided by the Company to
retail customers are set by the MPSC under cost-based regulatory principles. The
Federal Energy Regulatory Commission (FERC) regulates the Company's wholesale
rate schedules, wholesale power sales contracts, and wholesale transmission
services.
In August 2001, the Company filed a request with the MPSC to increase
annual retail rate revenues by approximately $46.4 million. In connection with
this request, the MPSC suspended the semi-annual evaluations under Performance
Evaluation Plan (PEP). In December 2001, the MPSC approved an increase of
approximately $39 million, which took effect in January 2002. Additionally, the
MPSC ordered the Company to reactivate the semi-annual evaluations under PEP,
beginning with the 12-month period ending December 31, 2002. PEP will remain in
effect until the MPSC modifies, suspends or terminates the plan. In May 2002,
the MPSC issued an order adopting new return on equity models to be used in the
PEP process. The new models are very similar to those that established the $39
million rate increase authorized in December 2001 and were incorporated into the
PEP evaluation filing for the period ending December 31, 2002. See Note 3 to the
financial statements under "Retail Rate Adjustment Plans" for additional
information.
In February 2002, the Company reached an agreement with certain of its
wholesale customers to increase its wholesale tariff rates effective June 1,
2002. The FERC accepted the settlement agreement and placed the new tariff rates
in effect without modification. The settlement agreement results in an annual
increase in revenues of approximately $10.5 million, the adoption of an ECM
provision, and the cost allocation of Plant Daniel Units 3 and 4, similar to the
plans approved by the Company's retail jurisdiction.
In accordance with Financial Accounting Standards Board (FASB) Statement
No. 87, Employers' Accounting for Pensions, the Company recorded non-cash
pension income, before taxes, of approximately $2.5 million. Future pension
income is dependent on several factors including trust earnings and changes to
the plan. Current estimates indicate a reversal of recording pension income to
recording pension expense by as early as 2005. Postretirement benefit costs for
the Company were $4 million in 2002 and are expected to continue to trend
upward. A portion of pension income and postretirement benefit costs is
capitalized based on construction-related labor charges. These costs are
components of the Company's regulated rates and do not have a significant effect
on net income. For more information, see Note 2 to the financial statements.
The Company has a power sale contract with a subsidiary of Dynegy, Inc.
(Dynegy). Dynegy is currently experiencing liquidity problems and its credit
rating is now below investment grade. Minimum capacity revenues under this
contract average approximately $21 million annually through May 2011. Dynegy has
provided a letter of credit expiring in April 2003 totaling $26 million -
approximately 15 months of capacity payments - to the Company. The letter of
credit can be drawn in the event of a default under the agreement or the failure
to renew the letter of credit prior to expiration. In the event of such a
default, and if the Company is unable to resell that capacity into the market,
future earnings could be affected. The outcome cannot now be determined.
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,
regulations, and litigation could affect earnings if such costs are not fully
recovered. The Clean Air Act and other important environmental items are
discussed later in Financial Condition under "Environmental Matters."
Industry Restructuring
The electric utility industry in the United States is continuing to evolve 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
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2002 Annual Report
IPPs to build power plants for a utility's large industrial and commercial
customers where retail access is allowed and sell energy to other utilities.
Also, electricity sales for resale rates are affected by numerous potential new
energy suppliers, including power marketers and brokers.
In 2002, merchant energy companies and traditional electric utilities with
significant energy marketing and trading activities came under severe financial
pressures. Many of these companies have completely exited or drastically reduced
all energy marketing and trading activities and sold foreign and domestic
electric infrastructure assets. The Company has not experienced any material
financial impact regarding its limited energy trading operations through SCS.
Although the Energy Act does not provide for 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 to promote
wholesale and retail competition are in various stages. Among other things,
these initiatives allow retail customers in some states to choose their
electricity provider. As these initiatives materialize, the structure of the
utility industry could radically change. In May 2000, the MPSC ordered that its
docket reviewing restructuring of the electric industry in the State of
Mississippi be suspended. The MPSC found that retail competition may not be in
the public interest at this time and ordered that no further formal hearings
would be held on this subject. It also found that the current regulatory
structure produced reliable low cost power and "should not be changed without
clear and convincing demonstration that change would be in the public interest."
The MPSC will continue to monitor retail and wholesale restructuring activities
throughout the United States and reserves its right to order further formal
hearings on the matter should new evidence demonstrate that retail competition
would be in the public interest and all customers could receive a reduction in
the total cost of their electric service. If the MPSC decides to hold future
restructuring hearings on this matter, enactment could require numerous issues
to be resolved, including recovery of any stranded investments, full cost
recovery of energy produced, and other issues related to the energy crisis that
occurred in California.
Continuing to be a low-cost producer could provide significant
opportunities to increase market share and profitability in markets that evolve
with changing regulation. Conversely, unless the Company remains a low-cost
producer and provides quality service, the Company's energy sales growth could
be limited, and this could significantly erode earnings.
FERC Matters
In December 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. Southern Company and its operating companies,
including the Company, have submitted a series of status reports informing the
FERC of progress toward the development of a Southeastern RTO. In these status
reports, Southern Company explained that it is developing a for-profit RTO known
as SeTrans with a number of non-jurisdictional cooperative and public power
entities. In 2001, Entergy Corporation and Cleco Power joined SeTrans
development process. In 2002, the sponsors of SeTrans established a Stakeholder
Advisory Committee, which will participate in the development of the RTO, and
held public meetings to discuss the SeTrans proposal. On October 10, 2002, the
FERC granted Southern Company's and other SeTrans' sponsors petition for a
declaratory order regarding the governance structure and the selection process
for the Independent System Administrator (ISA) of the SeTrans RTO. The FERC also
provided guidance on other issues identified in the petition. The SeTrans
sponsors announced the selection of ESB International, Ltd. (ESBI) to be the
preferred ISA candidate. Should negotiations with this candidate successfully
conclude with final agreement among the parties, the SeTrans sponsors intend to
seek any state and federal regulatory or other approvals necessary for formation
of the SeTrans RTO and the approval of ESBI to serve in the capacity of the
SeTrans ISA. The creation of SeTrans is not expected to have a material impact
on the Company's financial statements; however, the outcome of this matter
cannot now be determined.
In July 2002, the FERC issued a notice of proposed rulemaking regarding
open access transmission service and standard electricity market design. The
proposal, if adopted, would among other things: (1) require transmission assets
of jurisdictional utilities to be operated by an independent entity; (2)
establish a standard market design; (3) establish a single type of transmission
service that applies to all customers; (4) assert jurisdiction over the
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2002 Annual Report
transmission component of bundled retail service; (5) establish a generation
reserve margin; (6) establish bid caps for a day ahead and spot energy markets;
and (7) revise the FERC policy on the pricing of transmission expansions.
Comments on certain aspects of the proposal have been submitted by Southern
Company. Any impact of this proposal on the Company will depend on the form in
which final rules may be ultimately adopted; however, the Company's revenues,
expenses, assets, and liabilities could be adversely affected by changes in the
transmission regulatory structure in its regional power market.
In January 2002, the FERC began conducting an investigation to determine
whether the cost of debt and the cost of preferred stock reflected in the amount
charged under the Transmission Facilities Agreement between Entergy Corp. and
the Company, when considered in light of other aspects of the contract, yield an
overall just and reasonable rate. The hearing is scheduled for September 2003.
The Company believes that it is in full compliance with the terms of the
contract, which has been in place since 1982, and does not believe that the FERC
investigation will have a significant impact on the Company's financial results.
However, the outcome of the FERC's investigation cannot be predicted.
Accounting Policies
Critical Policies
The Company's significant accounting policies are described in Note 1 to the
financial statements. The Company's most critical accounting policy involves
rate regulation. 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 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.
Additionally, the Company accounts for its lease agreement with Escatawpa
Funding, Limited Partnership (Escatawpa) as an operating lease. Under this
agreement, Escatawpa, a special purpose entity, is owner-lessor of the
combined-cycle generating units at the Company's Plant Daniel. The Company does
not consolidate this entity since parties unrelated to the Company have made
substantive residual equity capital investments in excess of 3 percent.
Recently, FASB Interpretation No. 46, Consolidation of Variable Interest
Entities, was issued. Under Interpretation No. 46, Escatawpa is a variable
interest entity, which the Company, as primary beneficiary, would be required to
consolidate, including both the leased asset and related debt, as of July 1,
2003. Unless the Escatawpa arrangement is restructured to comply with
Interpretation No. 46, the Company would recognize a cumulative effect
adjustment of approximately $13 million, net of tax, related to depreciation.
The Company's current operating lease arrangement with Escatawpa has been
reviewed and approved by the MPSC and is reflected and approved for recovery in
both its retail and wholesale rate jurisdictions. Consolidation of the leased
asset and related debt or restructuring this arrangement could require the
Company to seek additional regulatory review. The Company will continue to
analyze the impact of Interpretation No. 46 and its regulatory and restructuring
options. See "Financial Condition - Off-Balance Sheet Financing Arrangements"
herein and Note 8 to the financial statements under "Lease Agreements" for
additional information.
New Accounting Standards
Derivatives
- -----------
Effective January 2001, the Company adopted FASB Statement No. 133, Accounting
for Derivative Instruments and Hedging Activities, as amended. In October 2002,
the Emerging Issues Task Force (EITF) of the FASB announced accounting changes
related to energy trading contracts in Issue No. 02-03. In October 2002, the
Company prospectively adopted the EITF's requirements to reflect the impact of
certain energy trading contracts on a net basis. This change had no material
impact on the Company's income statement. Another change also required certain
energy trading contracts to be accounted for on an accrual basis effective
January 2003. This change had no impact on the Company's current accounting
treatment.
Asset Retirement Obligations
- ----------------------------
Prior to January 2003, the Company accrued for the ultimate cost of retiring
most long-lived assets over the life of the related asset through depreciation
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2002 Annual Report
expense. FASB Statement No. 143, Accounting for Asset Retirement Obligations,
establishes new accounting and reporting standards for legal obligations
associated with the ultimate cost of retiring long-lived assets. The present
value of the ultimate costs for an asset's future retirement must be recorded in
the period in which the liability is incurred. The cost must be capitalized as
part of the related long-lived asset and depreciated over the asset's useful
life. Additionally, Statement No. 143 does not permit non-regulated companies to
continue accruing future retirement costs for long-lived assets that they do not
have a legal obligation to retire. For more information regarding the impact of
adopting this standard effective January 1, 2003, see Note 1 to the financial
statements under "Regulatory Assets and Liabilities" and "Depreciation and
Amortization."
Guarantees
- ----------
In November 2002, the FASB issued Interpretation No. 45, Accounting and
Disclosure Requirements for Guarantees. This interpretation requires disclosure
of certain direct and indirect guarantees as reflected in Note 8 to the
financial statements under "Lease Agreements." Also, the interpretation requires
recognition of a liability at inception for certain new or modified guarantees
issued after December 31, 2002. The adoption of Interpretation No. 45 in January
2003 did not have a material impact on the financial statements.
FINANCIAL CONDITION
Overview
The principal change in the Company's financial condition during 2002 was the
addition of approximately $67 million to utility plant. See the Statements of
Cash Flows for additional information.
Off-Balance Sheet Financing Arrangements
In 1999, the Company signed an Agreement for Lease and a Lease Agreement with
Escatawpa. These agreements called for the Company to design and construct, as
agent for Escatawpa, a 1,064 megawatt natural gas combined cycle facility at the
Company's Plant Victor J. Daniel Facility (the Facility). In May 2001, the
Facility was completed, placed into commercial operation and the initial 10-year
lease term began. The completion cost was approximately $370 million. The lease
provides for a residual value guarantee (approximately 71 percent of the
completion cost) by the Company that is due upon termination of the lease in
certain circumstances. The lease also includes a purchase and renewal option
based on the completion cost of the Facility. The Company is required to
amortize approximately 10 percent of the initial completion cost over the
initial ten year period. Eighteen months prior to the end of the initial lease,
the Company may elect to renew for another 10 years. If the Company elects to
renew the lease, the agreement calls for the Company to amortize an additional
17 percent of the initial completion cost over the renewal period. Upon
termination of the lease, at the Company's option, the Company may either
exercise its purchase option or the Facility can be sold to a third party. The
Company expects that the fair market value of the Facility would substantially
reduce or eliminate the payment under the residual value guarantee. In 2002 and
2001, the Company recognized approximately $26 million and $18 million,
respectively, in lease expense which includes approximately $3.5 million and
$2.4 million, respectively, related to the amortization of the initial
completion cost.
Credit Rating Risk
The Company does not have any credit agreements that would require material
changes in payment schedules or terminations as a result of a credit rating
downgrade. There are certain fixed-price physical gas purchase contracts that
could require collateral - but not accelerated payment - in the event of a
credit rating change to below investment grade; however, at December 31, 2002,
this exposure was immaterial.
Market Price Risk
Due to cost-based rate regulations, the Company has limited exposure to market
volatility in interest rates, commodity fuel prices, and prices of electricity.
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. Company
policy is that derivatives are to be used primarily for hedging purposes.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2002 Annual Report
Derivative positions are monitored using techniques that include market
valuation and sensitivity analysis.
The weighted average rate on variable long-term debt outstanding at
December 31, 2002 was 1.6 percent. Based on the Company's overall variable rate
long-term debt exposure at December 31, 2002, a near-term 100 basis point change
in interest rates would not materially affect the Company's financial
statements. See Note 1 to the financial statements under "Financial Instruments"
for additional information. In addition, the Company is not aware of any facts
or circumstances that would significantly affect such exposures in the near
term.
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. At December 31, 2002,
exposure from these activities was not material to the Company's financial
statements. Fair value of changes in energy contracts and year-end valuations
are as follows:
Change in Fair Value
- -------------------------------------------------------------
2002 2001
- ------------------------------------------------------------
(in thousands)
Contracts beginning of
year $(3,830) $ 112
Contracts realized or
settled (1,562) (101)
Current period changes 18,256 (3,841)
- -------------------------------------------------------------
Contracts end of year $12,864 $(3,830)
============================================================
At December 31, 2002, all of these contracts are actively quoted and mature
within one year. These contracts are related to fuel hedging programs under
which unrealized gains and losses from mark to market adjustments are recorded
as regulatory assets and liabilities. Realized gains and losses from these
programs are included in fuel expense and are recovered through the Company's
fuel cost recovery clauses. Gains and losses on contracts that do not represent
hedges are recognized in the Statements of Income as incurred. For the years
ended December 31, 2002 and 2001, these amounts were not material. See Note 1 to
the financial statements under "Financial Instruments" for additional
information.
Financing Activity
During 2002, the Company continued a program to retire higher-cost debt and
replace these securities with lower-cost capital. See the Statements of Cash
Flows for further details. As a result, composite financing rates have decreased
as follows:
2002 2001 2000
-----------------------------
Composite interest rate on
long-term debt 4.10% 4.60% 6.41%
Composite preferred stock
dividend rate 6.33% 6.33% 6.33%
Composite interest rate on
preferred securities 7.20% 7.75% 7.75%
------------------------------------------------------------
In February 2003, the Company redeemed $33 million of 7.45% first mortgage
bonds, originally due in 2023, and $850,000 of 5.8% pollution control issuance
bonds, originally due in 2007.
Capital Structure
The Company's ratio of common equity to total capitalization, excluding
long-term debt due within one year, decreased from 62.1 percent in 2001 to 62.5
percent at December, 31 2002.
Capital Requirements for Construction
The Company's projected construction expenditures for the next three years total
$237 million ($76 million in 2003, $86 million in 2004, and $75 million in
2005). The major emphasis within the construction program will be on the upgrade
of existing facilities. Actual construction costs may vary from this estimate
because of changes in such factors as: business conditions; environmental
regulations; FERC rules and transmission regulations; load projections; the cost
and efficiency of construction labor, equipment, and materials; and the cost of
capital. In addition, there can be no assurances that costs related to capital
expenditures will be fully recovered.
Other Capital Requirements
In addition to the funds required for the Company's construction program,
approximately $115 million will be required by the end of 2004 for present
sinking fund requirements and maturities of long-term debt. The Company plans to
continue, when economically feasible, to retire higher cost debt and preferred
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2002 Annual Report
stock and replace these obligations with lower-cost capital if market conditions
permit.
The capital requirements, lease obligations, and purchase commitments -
discussed in Notes 4 and 8 to the financial statements - are as follows:
2003 2004 2005
- ----------------------------------------------------------------
(in thousands)
Bonds -
First mortgage $33,350 $ - $ -
Pollution control 850 25 25
Senior notes 35,000 80,000 -
Lease obligations 28,000 27,800 27,500
Purchase commitments
fuel 191,000 74,000 6,000
Other post retirement
benefits 330 330 330
- ----------------------------------------------------------------
Sources of Capital
At the beginning of 2003, the Company had not used any of its available credit
arrangements. Credit arrangements are as follows:
Expires
----------------------------------
Total Unused 2003 2004 & Beyond
- -----------------------------------------------------------------
(in millions)
$97.5 $97.5 $97.5 -
- -----------------------------------------------------------------
In addition to these arrangements, to meet short-term cash needs and
contingencies, the Company had approximately $63 million of cash and cash
equivalents as well as significant cash flow from operating activities. See the
Statement of Cash Flows and Note 7 to the financial statements under "Bank
Credit Arrangements" for additional information.
The Company may also meet short-term cash needs through a Southern Company
subsidiary organized to issue and sell commercial paper and extendible
commercial notes at the request and for the benefit of the Company and the other
Southern Company operating companies. At December 31, 2002, the Company had no
outstanding commercial paper or extendible commercial notes.
At December 31, 2002, the Company's current liabilities exceed current
assets because of scheduled maturity of $35 million in senior notes and the
redemption in February 2003 of the 7.45% First Mortgage Bonds in the amount of
$33.4 million and the 5.80% Pollution Control Bonds in the amount of $850,000.
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
issuance of unsecured debt and preferred securities, in addition to pollution
control revenue bonds issued for the Company's benefit by public authorities.
The Company has no restrictions on the amounts of unsecured indebtedness it
may incur. However, the Company is required to meet certain coverage
requirements specified in its mortgage indenture and corporate charter to issue
new first mortgage bonds and preferred stock. The Company's coverage ratios are
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.
Environmental Matters
New Source Review Enforcement Actions
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 SCS. The complaint alleges violations of the 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 operating companies 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, Savannah Electric, and the Company 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
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2002 Annual Report
violation allege that the utilities had 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 U.S. District Court in Georgia granted Alabama Power's motion to
dismiss for lack of jurisdiction in Georgia and granted the system service
company's motion to dismiss on the grounds that it neither owned nor operated
the generating units involved in the proceedings. The court granted the EPA's
motion to add Savannah Electric as a defendant, but it denied the motion to add
Gulf Power and the Company based on lack of jurisdiction over those companies.
As directed by the court, the EPA re-filed its amended complaint limiting claims
to those brought against Georgia Power and Savannah Electric. Also, the EPA
re-filed its claims against Alabama Power in the U.S. District Court in Alabama.
It has not re-filed against Gulf Power, SCS, or the Company. The Alabama Power,
Georgia Power, and Savannah Electric cases have been stayed since the spring of
2001, pending a ruling by the U.S. Court of Appeals for the Eleventh Circuit in
the appeal of a very similar New Source Review enforcement action against the
Tennessee Valley Authority (TVA). The TVA appeal involves many of the same legal
issues raised by the actions against Alabama Power, Georgia Power, and Savannah
Electric. Because the outcome of the TVA appeal could have a significant adverse
impact on Alabama Power and Georgia Power, both companies have been parties to
that case as well. In February 2003, the U.S. District Court in Alabama extended
the stay of the EPA litigation proceeding in Alabama until the earlier of May 6,
2003 or a ruling by the U.S. Court of Appeals for the Eleventh Circuit in the
related litigation involving TVA. On August 21, 2002, the U.S. District Court in
Georgia denied the EPA's motion to reopen the Georgia case. The denial was
without prejudice to the EPA to refile the motion at a later date, which the EPA
has not done at this time.
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 establish legal
precedent that eventually 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.
Environmental Statutes and Regulations
The Company's operations are subject to extensive regulation by state and
federal environmental agencies under a variety of statutes and regulations
governing environmental media, including air, water, and land resources.
Compliance with these environmental requirements will involve significant costs,
a major portion of which is expected to be recovered through existing ratemaking
provisions. There is no assurance, however, that all such costs will, in fact,
be recovered.
Compliance with the federal Clean Air Act and resulting regulations has
been and will continue to be, a significant focus for the Company. The Title IV
acid rain provisions of the Clean Air Act, for example, required significant
reductions in sulfur dioxide and nitrogen oxide emissions. Compliance was
required in two phases - Phase I, effective in 1995 and Phase II, effective in
2000. Construction expenditures associated with Phase I were $65 million and
Phase II cost did not have a material impact on the company.
In September 1998, the EPA issued regional nitrogen oxide reduction rules
to the states for implementation. Compliance is required by May, 31, 2004 for
most states, including Alabama. The final rules affect 21 states that do not
include Mississippi. The EPA is presently evaluating whether or not to bring an
additional 15 states, including Mississippi, under this regional nitrogen oxide
rule.
The Company'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. The Company's management
believes that the ECO Plan provides for recovery of the Clean Air Act costs;
however, there can be no assurance that all Clean Air Act Costs will be
recovered. See Note 3 to the financial statements under "Environmental
Compliance Overview Plan" for additional information.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2002 Annual Report
In July 1997, the EPA revised the national ambient air quality standards
for ozone and fine particulate matter. These revisions made the standards
significantly more stringent. In the subsequent litigation of these standards,
the U.S. Supreme Court found the EPA's implementation program for the new ozone
standard unlawful and remanded it to the EPA for further rulemaking. The EPA is
expected to propose implementation rules designed to address the court's
concerns in 2003 and issue final implementation rules in 2004. The remaining
legal challenges to the new standards, which were pending before the U.S. Court
of Appeals, District of Columbia Circuit, have been resolved.
The EPA plans to designate areas as attainment or nonattainment with the
new eight-hour ozone standard by April 2004 and with the new fine particulate
standard by December 2004. Based on the most recent air monitoring data, it is
likely that the three coastal counties of Mississippi would initially be in
attainment with the new eight-hour average ozone standard and the fine
particulate matter standard. The impact of any new standards will depend on the
development and implementation of applicable regulations.
The EPA has also announced plans to issue a proposed Regional Transport
Rule for the fine particulate matter standard by the end of 2003 and to finalize
the rule in 2005. This rule would likely require year-round sulfur dioxide and
nitrogen oxide emission reductions from power plants as early as 2010. It is not
possible at this time to determine the effect such a rule would have on the
Company.
Further reductions in sulfur dioxide could also be required under the EPA's
Regional Haze rules. The Regional Haze rules require states to establish Best
Available Retrofit Technology (BART) standards for certain sources that
contribute to regional haze. The Company has two plants that could be subject to
these rules. The EPA regional haze program calls for the State of Mississippi to
submit State Implementation Plans that contain emission reduction strategies for
achieving progress toward the visibility improvement goal. The State of
Mississippi is on schedule to accomplish this by December 2007. In 2002,
however, the U.S. Court of Appeals for the District of Columbia Circuit vacated
and remanded the BART provisions of the federal Regional Haze rules to the EPA
for further rulemaking. Because new BART rules have not been developed, it is
not possible to determine the effect of these rules on the company at this time.
The EPA's Compliance Assurance Monitoring (CAM) regulations under Title V
of the Clean Air Act require that monitoring be performed to ensure compliance
with emissions limitations on an ongoing basis. The regulations require certain
facilities with Title V operating permits to develop and submit a CAM plan to
the appropriate permitting authority upon applying for renewal of the facility's
Title V operating permit. The Company will be applying for renewal of certain
Title V operating permits beginning in 2003. The Company is in the process of
developing CAM plans, which could indicate a need for improved particulate
matter controls at affected facilities. Because the plans are still in the early
stages of development, the Company cannot determine the extent to which improved
controls could be required or the costs associated with any necessary
improvements. Actual ongoing monitoring costs are expensed as incurred and are
not material for any period presented.
In December 2000, having completed its utility studies for mercury and
other hazardous air pollutants (HAPS), the EPA issued a determination that an
emission control program for mercury and, perhaps, other HAPS is forthcoming.
The program is being developed under the Maximum Achievable Control Technology
provisions of the Clean Air Act. The EPA currently plans to issue proposed rules
regulating mercury emissions from electric utility boilers by the end of 2003,
and those regulations are scheduled to be finalized by the end of 2004.
Compliance could be required as early as 2007. Because the rules have not yet
been proposed, the costs associated with compliance cannot be determined at this
time.
In December 2002, the EPA issued final and proposed revisions to the New
Source Review program under the Clean Air Act. In February 2003, several
northeastern states petitioned the D.C. Circuit Court for a stay of the final
rules. The proposed rules are open to public comment and may be revised before
being finalized by the EPA. If fully implemented, these proposed and final
regulations could affect the applicability of the New Source Review provisions
II-186
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2002 Annual Report
to activities at the Company's facilities. In any event, any final regulations
must be adopted by the state of Mississippi in order to apply to the Company's
facilities. The effect of these proposed and final rules cannot be determined at
this time.
Several major bills to amend the Clean Air Act to impose more stringent
emissions limitations have been proposed. Three of these, the Bush
Administration's Clear Skies Act, the Clean Power Act of 2002, and the Clean Air
Planning Act of 2002, proposed to further limit power plant emissions of sulfur
dioxide, nitrogen oxides, and mercury. The latter two bills also proposed to
limit emissions of carbon dioxide. None of these bills were enacted into law in
the 107th Congress. Similar bills have been, and are anticipated to be,
introduced in 2003. The Bush Administration's Clear Skies Act was recently
reintroduced, and President Bush has stated that it will be high priority for
the Administration. Other bills already introduced include the Climate
Stewardship Act of 2003, which proposes capping greenhouse gas emissions. The
cost impacts of such legislation would depend upon the specific requirements
enacted.
Domestic efforts to limit greenhouse gas emissions have been spurred by
international discussions surrounding the Framework Convention on Climate Change
and, specifically, the Kyoto Protocol, which proposes international constraints
on the emissions of greenhouse gases. The Bush Administration does not support
U.S. ratification of the Kyoto Protocol or other mandatory carbon dioxide
reduction legislation and has instead announced a new voluntary climate
initiative which seeks an 18 percent reduction by 2012 in the rate of greenhouse
gas emissions relative to the dollar value of the U.S. economy. The Company is
involved in a voluntary electric utility industry sector climate change
initiative in partnership with the government. Because this initiative is still
under development, it is not possible to determine the effect on the Company at
this time.
The Company must comply with other environmental laws and regulations that
cover the handling and disposal of hazardous waste and release of hazardous
substances. Under these various laws and regulations, the Company could incur
costs to clean up properties. However, such costs are expected to be recovered
through the ECO Plan. The Company conducts studies to determine the extent of
any required clean up and have recognized in the financial statements the costs
to clean up known sites. Should remediation be determined to be probable,
reasonable estimates of costs to clean up such sites are developed and
recognized in the financial statements.
Under the Clean Water Act, the EPA is developing new rules aimed at
reducing impingement and entrainment of fish and fish larvae at cooling water
intake structures that will require numerous biological studies, and perhaps,
retrofits to some intake structures at existing power plants. The new rule was
proposed in February 2002 and will be finalized by February 2004. The impact of
any new standards will depend on the development and implementation of
applicable regulations.
Also, under the Clean Water Act, the EPA and Mississippi Department of
Environmental Quality (MDEQ) are developing total maximum daily loads (TMDLs)
for certain impaired waters. Establishment of maximum loads by the EPA or state
agencies may result in lowering permit limits for various pollutants and a
requirement to take additional measures to control non-point source pollution
(e.g. storm water runoff) at facilities discharging into waters for which TMDLs
are established. It is not possible to determine the effect on the Company at
this time.
The EPA and MDEQ are reviewing and evaluating various other matters
including limits on pollutant discharges to impaired waters, hazardous waste
disposal requirements, and other regulatory matters. 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; the Emergency Planning and Community Right-to-Know Act; and the
Endangered Species Act.
Compliance with possible additional federal or state legislation related to
global climate change, electromagnetic fields, and other environmental and
health concerns could also significantly affect the Company. The impact of any
II-187
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2002 Annual Report
new legislation, or changes to existing legislation could affect many areas of
the Company's operations. However, the full impact of any such changes cannot be
determined at this time.
Cautionary Statement Regarding Forward-Looking
Information
This Annual Report includes forward-looking statements in addition to historical
information. Forward-looking information includes, among other things,
statements concerning projected sales growth and scheduled completion of new
generation. In some cases, forward-looking statements can be identified by
terminology such as "may," "will," "should," "could," "expects," "plans,"
"anticipates," "believes," "estimates," "predicts," "projects," "potential," or
"continue" or the negative of these terms or other comparable terminology. The
Company cautions that there are various important factors that could cause
actual results to differ materially from those indicated in the forward-looking
statements; accordingly, there can be no assurance that such indicated results
will be realized. These factors include the impact of recent and future federal
and state regulatory change, including legislative and regulatory initiatives
regarding deregulation and restructuring of the electric utility industry and
also changes in environmental and other laws and regulations to which the
Company is subject, as well as changes in application of existing laws and
regulations; current and future litigation; the effects, extent and timing of
the entry of additional competition in the markets of the Company; the impact of
fluctuations in commodity prices, interest rates, and customer demand; state and
federal rate regulations; political, legal, and economic conditions and
developments in the United States; internal restructuring or other restructuring
options that may be pursued; potential business strategies, including
acquisitions or dispositions of assets or businesses, which cannot be assured to
be completed or beneficial to the Company; the ability of counterparties of the
Company to make payments as and when due; the effects of, and changes in,
economic conditions in the areas in which the Company operates, including the
current soft economy; the direct or indirect effects on the Company's business
resulting from the terrorist incidents on September 11, 2001, or any similar
such incidents or responses to such incidents; financial market conditions and
the results of financing efforts; the ability of the Company to obtain
additional generating capacity at competitive prices; weather and other natural
phenomena; and other factors discussed elsewhere herein and in other reports
(including Form 10-K) filed from time to time by the Company with the Securities
and Exchange Commission.
II-188
STATEMENTS OF INCOME
For the Years Ended December 31, 2002, 2001, and 2000
Mississippi Power Company 2002 Annual Report
- ---------------------------------------------------------------------------------------------------------------------------
2002 2001 2000
- ---------------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Revenues:
Retail sales $536,827 $489,153 $498,551
Sales for resale --
Non-affiliates 224,275 204,623 145,931
Affiliates 46,314 85,652 27,915
Other revenues 16,749 16,637 15,205
- ---------------------------------------------------------------------------------------------------------------------------
Total operating revenues 824,165 796,065 687,602
- ---------------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
Fuel 282,393 277,946 191,127
Purchased power --
Non-affiliates 18,550 41,254 56,082
Affiliates 32,783 53,990 51,057
Other 158,354 134,845 115,055
Maintenance 73,659 56,153 52,750
Depreciation and amortization 57,638 54,077 50,275
Taxes other than income taxes 55,518 44,966 48,686
- ---------------------------------------------------------------------------------------------------------------------------
Total operating expenses 678,895 663,231 565,032
- ---------------------------------------------------------------------------------------------------------------------------
Operating Income 145,270 132,834 122,570
Other Income and (Expense):
Interest income 655 369 347
Interest expense (18,650) (23,568) (28,101)
Distributions on preferred securities of subsidiary (3,016) (2,712) (2,712)
Other income (expense), net (3,354) (532) (647)
- ---------------------------------------------------------------------------------------------------------------------------
Total other income and (expense) (24,365) (26,443) (31,113)
- ---------------------------------------------------------------------------------------------------------------------------
Earnings Before Income Taxes 120,905 106,391 91,457
Income taxes 45,879 40,533 34,356
- ---------------------------------------------------------------------------------------------------------------------------
Earnings Before Cumulative Effect of 75,026 65,858 57,101
Accounting Change
Cumulative effect of accounting change--
less income taxes of $43 thousand - 70 -
- ---------------------------------------------------------------------------------------------------------------------------
Net Income 75,026 65,928 57,101
Dividends on Preferred Stock 2,013 2,041 2,129
- ---------------------------------------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred Stock $ 73,013 $ 63,887 $ 54,972
===========================================================================================================================
The accompanying notes are an integral part of these financial statements.
II-189
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2002, 2001, and 2000
Mississippi Power Company 2002 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------------
2002 2001 2000
- -----------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Activities:
Net income $ 75,026 $ 65,928 $ 57,101
Adjustments to reconcile net income
to net cash provided from operating activities --
Depreciation and amortization 61,930 58,105 54,638
Deferred income taxes and investment tax credits, net (3,404) (9,718) 752
Pension, postretirement, and other employee benefits 730 (2,467) (4,801)
Other, net 2,017 4,349 3,054
Changes in certain current assets and liabilities --
Receivables, net 6,120 (7,796) (3,231)
Fossil fuel stock 4,186 (20,269) 14,577
Materials and supplies 1,160 (1,529) (1,056)
Other current assets (13,346) 138 520
Accounts payable 18,487 53,462 1,309
Taxes accrued 3,160 4,695 3,169
Other current liabilities 34,770 6,977 (737)
- -----------------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities 190,836 151,875 125,295
- -----------------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (67,460) (61,193) (81,211)
Cost of removal net of salvage (9,987) (3,042) (5,718)
Other (3,471) 54 (3,435)
- -----------------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities (80,918) (64,181) (90,364)
- -----------------------------------------------------------------------------------------------------------------------------------
Financing Activities:
Increase (decrease) in notes payable, net (15,973) (40,027) (1,500)
Proceeds --
Pollution control bonds 42,625 - -
Senior notes 80,000 - 100,000
Preferred securities 35,000 - -
Capital contributions from parent company 18,025 73,095 12,659
Redemptions --
First mortgage bonds (650) (36,000) -
Pollution control bonds (42,645) (20) (20)
Senior notes (80,550) (21,001) (1,385)
Other long-term debt - - (80,000)
Preferred securities (35,000) - -
Payment of preferred stock dividends (2,013) (2,041) (2,129)
Payment of common stock dividends (63,500) (50,200) (54,700)
Other (1,492) (81) (498)
- -----------------------------------------------------------------------------------------------------------------------------------
Net cash provided from (used for) financing activities (66,173) (76,275) (27,573)
- -----------------------------------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents 43,745 11,419 7,358
Cash and Cash Equivalents at Beginning of Period 18,950 7,531 173
- -----------------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ 62,695 $ 18,950 $7,531
===================================================================================================================================
Supplemental Cash Flow Information:
Cash paid during the period for --
Interest $17,743 $28,126 $30,570
Income taxes (net of refunds) 44,088 45,761 33,276
- -----------------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
II-190
BALANCE SHEETS
At December 31, 2002 and 2001
Mississippi Power Company 2002 Annual Report
- ---------------------------------------------------------------------------------------------------------------------------------
Assets 2002 2001
- ---------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Current Assets:
Cash and cash equivalents $ 62,695 $ 18,950
Receivables --
Customer accounts receivable 31,136 30,254
Unbilled revenues 18,434 17,946
Under recovered regulatory clause revenues 27,233 15,086
Other accounts and notes receivable 8,056 26,068
Affiliated companies 20,674 22,569
Accumulated provision for uncollectible accounts (718) (856)
Fossil fuel stock, at average cost 27,303 31,489
Materials and supplies, at average cost 22,063 23,223
Assets from risk management activities 13,061 71
Deferred income tax assets 18,675 8,819
Other 7,469 7,112
- ---------------------------------------------------------------------------------------------------------------------------------
Total current assets 256,081 200,731
- ---------------------------------------------------------------------------------------------------------------------------------
Property, Plant, and Equipment:
In service 1,786,378 1,741,499
Less accumulated provision for depreciation 722,231 698,681
- ---------------------------------------------------------------------------------------------------------------------------------
1,064,147 1,042,818
Construction work in progress 34,065 38,253
- ---------------------------------------------------------------------------------------------------------------------------------
Total property, plant, and equipment 1,098,212 1,081,071
- ---------------------------------------------------------------------------------------------------------------------------------
Other Property and Investments 1,768 1,900
- ---------------------------------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets:
Deferred charges related to income taxes 12,617 13,394
Prepaid pension costs 14,993 11,171
Unamortized debt issuance expense 4,304 4,396
Unamortized premium on reacquired debt 7,776 6,719
Other 16,415 20,821
- ---------------------------------------------------------------------------------------------------------------------------------
Total deferred charges and other assets 56,105 56,501
- ---------------------------------------------------------------------------------------------------------------------------------
Total Assets $1,412,166 $1,340,203
=================================================================================================================================
The accompanying notes are an integral part of these financial statements.
II-191
BALANCE SHEETS
At December 31, 2002 and 2001
Mississippi Power Company 2002 Annual Report
- ---------------------------------------------------------------------------------------------------------------------------------
Liabilities and Stockholder's Equity 2002 2001
- ---------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Current Liabilities:
Securities due within one year $69,200 $ 80,020
Notes payable - 15,973
Accounts payable --
Affiliated 22,396 16,642
Other 91,710 82,072
Customer deposits 6,855 6,540
Taxes accrued --
Income taxes 12,042 14,981
Other 41,464 35,282
Interest accrued 6,562 5,079
Vacation pay accrued 5,782 5,810
Regulatory clauses over recovery 35,680 13,296
Other 8,504 12,040
- ---------------------------------------------------------------------------------------------------------------------------------
Total current liabilities 300,195 287,735
- ---------------------------------------------------------------------------------------------------------------------------------
Long-term debt (See accompanying statements) 243,715 233,753
- ---------------------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 146,631 138,913
Deferred credits related to income taxes 20,798 23,626
Accumulated deferred investment tax credits 21,054 22,268
Employee benefits provisions 49,869 45,827
Other 45,142 29,592
- ---------------------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 283,494 260,226
- ---------------------------------------------------------------------------------------------------------------------------------
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) 517,953 491,680
- ---------------------------------------------------------------------------------------------------------------------------------
Total Liabilities and Stockholder's Equity $1,412,166 $1,340,203
=================================================================================================================================
Commitments and Contingent Matters (See notes)
- ---------------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
II-192
STATEMENTS OF CAPITALIZATION
At December 31, 2002 and 2001
Mississippi Power Company 2002 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------------
2002 2001 2002 2001
- -----------------------------------------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
Long-Term Debt:
First mortgage bonds --
Maturity Interest Rates
-------- --------------
June 1, 2023 7.45% $ 33,350 $ 34,000
December 1, 2025 6.875% 30,000 30,000
- -----------------------------------------------------------------------------------------------------------------------------------
Total first mortgage bonds 63,350 64,000
- -----------------------------------------------------------------------------------------------------------------------------------
Long-term notes payable --
6.05% due May 1, 2003 35,000 35,000
6.75% due June 30, 2038 51,628 52,178
Adjustable rates (1.51% at 1/1/03)
due 2004 80,000 80,000
- -----------------------------------------------------------------------------------------------------------------------------------
Total long-term notes payable 166,628 167,178
- -----------------------------------------------------------------------------------------------------------------------------------
Other long-term debt --
Pollution control revenue bonds --
Collateralized:
5.80% due October 1, 2007 850 870
5.65% due November 1, 2023 - 25,875
Non-collateralized:
Variable rates (1.75% to 1.85% at 1/1/03)
due 2020-2028 82,695 56,820
- -----------------------------------------------------------------------------------------------------------------------------------
Total other long-term debt 83,545 83,565
- -----------------------------------------------------------------------------------------------------------------------------------
Unamortized debt premium (discount), net (608) (970)
- -----------------------------------------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
requirement -- $14.5 million) 312,915 313,773
Less amount due within one year 69,200 80,020
- -----------------------------------------------------------------------------------------------------------------------------------
Long-term debt excluding amount due within one year $243,715 $233,753 29.5% 29.5%
- -----------------------------------------------------------------------------------------------------------------------------------
II-193
STATEMENTS OF CAPITALIZATION (continued)
At December 31, 2002 and 2001
Mississippi Power Company 2002 Annual Report
- -------------------------------------------------------------------------------------------------------------------------------
2002 2001 2002 2001
- -------------------------------------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
Company Obligated Mandatorily
Redeemable Preferred Securities:(See notes)
$25 liquidation value --
7.20% $ 35,000 $ -
7.75% - 35,000
- -------------------------------------------------------------------------------------------------------------------------------
Total (annual distribution requirement -- $2.5 million) 35,000 35,000 4.2 4.4
- -------------------------------------------------------------------------------------------------------------------------------
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 3.8 3.9
- -------------------------------------------------------------------------------------------------------------------------------
Common Stockholder's Equity:
Common stock, without par value --
Authorized - 1,130,000 shares
Outstanding - 1,121,000 shares in 2001 and 2000 37,691 37,691
Paid-in capital 285,280 267,256
Premium on preferred stock 326 326
Retained earnings 195,920 186,407
Accumulated other comprehensive income (loss) (1,264) -
- -------------------------------------------------------------------------------------------------------------------------------
Total common stockholder's equity 517,953 491,680 62.5 62.1
- -------------------------------------------------------------------------------------------------------------------------------
Total Capitalization $828,477 $792,242 100.0% 100.0%
===============================================================================================================================
The accompanying notes are an integral part of these financial statements.
II-194
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
For the Years Ended December 31, 2002, 2001, and 2000
Mississippi Power Company 2002 Annual Report
- ---------------------------------------------------------------------------------------------------------------------------------
Premium on Other
Common Paid-In Preferred Retained Comprehensive
Stock Capital Stock Earnings Income (loss) Total
- ---------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Balance at December 31, 1999 $37,691 $181,502 $326 $172,449 $ - $391,968
Net income after dividends on preferred stock - - - 54,972 - 54,972
Capital contributions from parent company - 12,659 - - - 12,659
Cash dividends on common stock - - - (54,700) - (54,700)
Other - - - (1) - (1)
- ---------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2000 37,691 194,161 326 172,720 - 404,898
Net income after dividends on preferred stock - - - 63,887 - 63,887
Capital contributions from parent company - 73,095 - - - 73,095
Cash dividends on common stock - - - (50,200) - (50,200)
- ---------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2001 37,691 267,256 326 186,407 - 491,680
Net income after dividends on preferred stock - - - 73,013 - 73,013
Capital contributions from parent company - 18,025 - - - 18,025
Other comprehensive income (loss) - - - - (1,264) (1,264)
Cash dividends on common stock - - - (63,500) - (63,500)
Other - (1) - - - (1)
- ---------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2002 $37,691 $285,280 $326 $195,920 $(1,264) $517,953
=================================================================================================================================
The accompanying notes are an integral part of these financial statements.
STATEMENTS OF COMPREHENSIVE INCOME For the Years Ended December 31, 2002, 2001,
and 2000 Mississippi Power Company 2002 Annual Report
- ---------------------------------------------------------------------------------------------------------------------------
2002 2001 2000
- ----------------------------------------------------------------------------------------------------------------------------
(in thousands)
Net income after dividends on preferred stock $73,013 $63,887 $54,972
- ---------------------------------------------------------------------------------------------------------------------------
Other comprehensive income (loss):
Change in additional minimum pension liability, net of (1,264) - -
tax of $(783)
- ---------------------------------------------------------------------------------------------------------------------------
Total other comprehensive income (loss) (1,264) - -
- ---------------------------------------------------------------------------------------------------------------------------
Comprehensive Income $71,749 $63,887 $54,972
===========================================================================================================================
The accompanying notes are an integral part of these financial statements.
II-195
NOTES TO FINANCIAL STATEMENTS
Mississippi Power Company 2002 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Mississippi Power Company (the Company) is a wholly owned subsidiary of Southern
Company, which is the parent company of five operating companies, a system
service company (SCS), Southern Communications Services (Southern LINC),
Southern Company Gas (Southern GAS), Southern Company Holdings (Southern
Holdings), Southern Nuclear Operating Company (Southern Nuclear), Southern Power
Company (Southern Power), Southern Telecom, and other direct and indirect
subsidiaries. The operating companies - Alabama Power Company, Georgia Power
Company, Gulf Power Company, the Company, and Savannah Electric and Power
Company - provide electric service in four southeastern states. Southern Power
was established in 2001 to construct, own, and manage Southern Company's
competitive generation assets and sell electricity at market-based rates in the
wholesale market. Contracts among the operating companies - 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 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 Telecom provides fiber optic communication services within the
Southeast. Southern GAS, which began operations in August 2002, is a competitive
retail natural gas marketer serving communities in Georgia. Southern Holdings is
an intermediate holding subsidiary for Southern Company's investments in
leveraged leases, alternative fuel products, and an energy services business.
Southern Nuclear provides services to Southern Company's nuclear power plants.
Southern Company is registered as a holding company under the Public Utility
Holding Company Act of 1935 (PUHCA). Both the Company and its subsidiaries are
subject to the regulatory provisions of the PUHCA. The Company is also subject
to regulation by the FERC and the Mississippi Public Service Commission (MPSC).
The Company follows accounting principles generally accepted in the United
States and complies with the accounting policies and practices prescribed by its
respective regulatory commissions. The preparation of financial statements in
conformity with accounting principles generally accepted in the United States
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.
Affiliate 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 analysis, finance and treasury, tax, information
resources, marketing, auditing, insurance and pension administration, human
resources, systems and procedures, and other services with respect to business
and operations and power pool operations. Costs for these services amounted to
$43.6 million, $44.1 million, and $46.2 million during 2002, 2001, and 2000,
respectively. Cost allocation methodologies used by SCS are approved by the SEC
and management believes they are reasonable.
The Company has an agreement with Alabama Power under which the Company
owns a portion of Greene County Steam Plant. Alabama Power operates Greene
County Steam Plant and the Company reimburses Alabama Power for its
proportionate share of all associated expenditures and costs. The Company
reimbursed Alabama Power for the Company's proportionate share of related
expenses which totaled $6.4 million in 2002. The Company also has an agreement
with Gulf Power under which Gulf Power owns a portion of Plant Daniel. The
Company operates Plant Daniel and Gulf Power reimburses the Company for its
proportionate share of all associated expenditures and costs. Gulf Power
reimbursed the Company for Gulf Power's proportionate share of related expenses
which totaled $16.6 million in 2002. See Note 4 for additional information.
The operating companies, (including the Company), Southern Power, and
Southern Gas may jointly enter into various types of wholesale energy, natural
gas and certain other contracts, either directly or through SCS as an agent.
II-196
NOTES (continued)
Mississippi Power Company 2002 Annual Report
Each participating company may be jointly and severally liable for the
obligations incurred under these agreements.
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:
2002 2001
-------------------------
(in thousands)
Deferred income tax charges $ 12,617 $ 13,394
Vacation pay 5,782 5,810
Premium on reacquired debt 7,776 6,719
Fuel hedging asset 14,558 8,366
Other assets 49 674
Property damage reserve (5,077) (4,044)
Deferred income tax credits (20,798) (23,626)
Fuel-hedging liabilities (14,990) -
Other liabilities (2,450) (1,066)
- ---------------------------------------------------------------
Total $ (2,533) $ 6,227
===============================================================
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. All
regulatory assets and liabilities are reflected in rates.
See "Depreciation and Amortization" for information regarding regulatory
assets and liabilities created as a result of the January 1, 2003 adoption of
FASB Statement No. 143, Accounting for Asset Retirement Obligations.
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.
Energy revenues are recognized as services are rendered. Capacity revenues
from long-term contracts are recognized at the lesser of the levelized basis or
the cash collected over the respective contract period. Unbilled revenues are
accrued at the end of each fiscal period. The Company's retail and wholesale
rates include provisions to adjust billings for fluctuations in fuel costs, fuel
hedging, 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 1/2 percent of revenues.
Depreciation and Amortization
Depreciation of the original cost of plant in service is provided primarily by
using composite straight-line rates, which approximated 3.4 percent in 2002, 3.5
percent in 2001, and 3.5 percent in 2000. When property subject to depreciation
is retired or otherwise disposed of in the normal course of business, its
original cost - together with the cost of removal, less salvage - is charged to
accumulated 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.
In January 2003, the Company adopted FASB Statement No. 143, Accounting for
Asset Retirement Obligations. Statement No. 143 establishes new accounting and
reporting standards for legal obligations associated with the ultimate cost of
retiring long-lived assets. The present value of the ultimate costs for an
asset's future retirement must be recorded in the period in which the liability
II-197
NOTES (continued)
Mississippi Power Company 2002 Annual Report
is incurred. The cost must be capitalized as part of the related long-lived
asset and depreciated over the asset's useful life.
There was no cumulative effect adjustment to net income resulting from the
adoption of Statement No. 143. The Company expects to receive an accounting
order from the MPSC to defer the transition adjustment; therefore, the Company
recorded a related regulatory asset of $596,000 to reflect the regulatory
treatment of these costs under Statement No. 71. The initial Statement No. 143
liability the Company recognized was $979,000, of which $59,000 was added to the
accumulated depreciation reserve. The amount capitalized to property, plant, and
equipment was $442,000.
The Company has retirement obligations related to ash landfill sites, ash
ponds, water wells, and underground storage tanks. The Company has also
identified retirement obligations related to certain transmission, distribution,
and wireless communication facilities. However, a liability for the removal of
these transmission, distribution, and wireless communication assets will not be
recorded because no reasonable estimate can be made regarding the timing of any
related retirements. The Company will continue to recognize in its income
statement the ultimate removal costs in accordance with its regulatory
treatment. Any difference between costs recognized under Statement No. 143 and
those reflected in rates will be recognized as either a regulatory asset or
liability. It is estimated that this annual difference will be approximately
$75,000. Historically, these costs have been recovered in rates and management
believes the actual asset removal costs will continue to be recoverable in
rates.
Statement No. 143 does not permit non-regulated companies to continue
accruing future retirement costs for long-lived assets that they do not have a
legal obligation to retire. However, in accordance with the regulatory treatment
of these costs, the Company will continue to recognize the removal costs for
these other obligations in its depreciation rates. As of January 1, 2003, the
amount included in the accumulated depreciation reserve that represents a
regulatory liability for these costs was $70 million.
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.
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 and recovered through the Company's fuel clause. The cost of replacements
of property - exclusive of minor items of property - is capitalized.
Impairment of Long-Lived Assets and Intangibles
The Company evaluates long-lived assets for impairment 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
either a specific regulatory disallowance or an estimate of undiscounted future
cash flows attributable to the assets, as compared with 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
the 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 Statements of Cash Flows, temporary cash investments are
considered cash equivalents. Temporary cash investments are securities with
original maturities of 90 days or less.
II-198
NOTES (continued)
Mississippi Power Company 2002 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.
Stock Options
Southern Company provides non-qualified stock options to a large segment of the
Company's employees ranging from line management to executives. The Company
accounts for its stock-based compensation plans in accordance with Accounting
Principles Board Opinion No. 25. Accordingly, no compensation expense has been
recognized because the exercise price of all options granted equals the
fair-market value on the date of grant. When options are exercised, the Company
receives a capital contribution from Southern Company equivalent to the related
income tax benefit.
Comprehensive Income
Comprehensive income - consisting of net income and changes in additional
minimum pension liability, net of income taxes - is presented in the financial
statements. The objective of comprehensive income is to report a measure of all
changes in common stock equity of an enterprise that result from transactions
and other economic events of the period other than transactions with owners.
Financial Instruments
The Company uses derivative financial instruments to limit exposure to
fluctuations in interest rates, the prices of certain fuel purchases, and
electricity purchases and sales. All derivative financial instruments are
recognized as either assets or liabilities and are measured at fair value.
Substantially all of the Company's bulk energy purchases and sales contracts are
derivatives. However, in many cases, these contracts qualify as normal purchases
and sales and are accounted for under the accrual method. Other contracts
qualify as cash flow hedges of anticipated transactions. This results in the
deferral of related gains and losses in other comprehensive income or regulatory
assets or liabilities as appropriate until the hedged transactions occur. Any
ineffectiveness is recognized currently in net income. Contracts that do not
qualify for the normal purchase and sale exception and that do not meet the
hedge requirements are marked to market through current period income and are
recorded on a net basis in the Statements of Income.
In June 2001, the MPSC approved the Company's request to implement an
Energy Cost Management Clause (ECM). ECM, among other things, allows the Company
to utilize financial instruments that are used to hedge its fuel commitments.
Changes in the fair value of these financial instruments are recorded as
regulatory assets or liabilities. Amounts paid or received as a result of
financial settlement of these instruments are classified as fuel expense and are
included in the ECM factor applied to customer billings. The Company's
jurisdictional wholesale customers have a similar ECM mechanism which was
approved by the FERC in 2002.
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's other 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, 2002 $313 $313
At December 31, 2001 $314 $309
Capital trust preferred
securities:
At December 31, 2002 $ 35 $ 36
At December 31, 2001 $ 35 $ 35
- ------------------------------------------------------------
The fair values for long-term debt and preferred securities were based on
either closing market price or closing price of comparable instruments.
Provision for Property Damage
The Company carries insurance for the cost of certain types of damage to
generation plants and general property. However, the Company is self-insured for
II-199
NOTES (continued)
Mississippi Power Company 2002 Annual Report
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 $50,000 is charged to the accumulated
provision as ordered by the MPSC. The annual accruals may range from $1.5
million to $4.6 million with a maximum reserve totaling $23 million. The Company
accrued $1.8 million in 2002, $2.5 million in 2001 and $3.5 million in 2000. As
of December 31, 2002, the accumulated provision amounted to $5.1 million.
2. RETIREMENT BENEFITS
The Company has a defined benefit, trusteed, pension plan that covers
substantially all employees. The Company also provides certain non-qualified
benefit plans for a selected group of management and highly compensated
employees. The Company provides certain medical care and life insurance benefits
for retired employees. Substantially all these employees may become eligible for
such benefits when they retire. The Company funds trusts to the extent
deductible under federal income tax regulations or the extent required by
regulatory commissions. In late 2000, as well as in 2002, the Company adopted
several pension and postretirement benefit plan changes that had the effect of
increasing benefits to both current and future retirees.
Plan assets consist primarily of domestic and international equities,
global fixed income securities, real estate, and private equity investments. 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
--------------------------
2002 2001
- ---------------------------------------------------------------------
(in thousands)
Balance at beginning of year $172,167 $154,411
Service cost 5,259 4,797
Interest cost 12,674 11,817
Benefits paid (8,386) (8,456)
Actuarial gain and employee
transfers 528 1,268
Amendments 4,200 8,406
Other - (76)
- ---------------------------------------------------------------------
Balance at end of year $186,442 $172,167
=====================================================================
Plan Assets
--------------------------
2002 2001
- ---------------------------------------------------------------------
(in thousands)
Balance at beginning of year $211,546 $256,648
Actual return on plan assets (14,089) (37,214)
Benefits paid (7,875) (7,850)
Employee transfers (743) (38)
- ---------------------------------------------------------------------
Balance at end of year $188,839 $211,546
=====================================================================
The accrued pension costs recognized in the Balance Sheets
were as follows:
2002 2001
- ------------------------------------------------------------------
(in thousands)
Funded status $2,396 $ 39,379
Unrecognized transition obligation (2,180) (2,716)
Unrecognized prior service cost 16,669 13,656
Unrecognized net gain (9,087) (45,818)
- ------------------------------------------------------------------
Prepaid asset, net 7,798 4,501
Portion included in
benefit obligations 7,195 6,670
- ------------------------------------------------------------------
Total prepaid assets recognized in
the Balance Sheet $14,993 $ 11,171
==================================================================
In 2002 and 2001, amounts recognized in the Balance Sheet for accumulated
other comprehensive income was $2 million and $0 million, respectively.
Intangible assets recognized were $2 million in 2002 and $2 million in 2001.
II-200
NOTES (continued)
Mississippi Power Company 2002 Annual Report
Components of the pension plans' net periodic cost were as follows:
2002 2001 2000
- ---------------------------------------------------------------
(in thousands)
Service cost $ 5,259 $ 4,797 $ 4,357
Interest cost 12,674 11,818 10,912
Expected return on
plan assets (18,380) (17,328) (15,910)
Recognized net gain (2,654) (3,012) (2,577)
Net amortization 650 511 76
- ---------------------------------------------------------------
Net pension income $ (2,451) $ (3,214) $(3,142)
===============================================================
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
-------------------------
2002 2001
- --------------------------------------------------------------
(in thousands)
Balance at beginning of year $51,523 $44,952
Service cost 959 922
Interest cost 3,781 3,411
Benefits paid (3,320) (2,918)
Actuarial gain and
employee transfers 8,225 3,256
Amendments - 1,900
- --------------------------------------------------------------
Balance at end of year $61,168 $51,523
==============================================================
Plan Assets
----------------------
2002 2001
- --------------------------------------------------------------
(in thousands)
Balance at beginning of year $16,269 $17,843
Actual return on plan assets (516) (1,888)
Employer contributions 3,645 3,232
Benefits paid (3,320) (2,918)
- --------------------------------------------------------------
Balance at end of year $16,078 $16,269
==============================================================
The accrued postretirement costs recognized in the Balance
Sheets were as follows:
2002 2001
- ------------------------------------------------------------------
(in thousands)
Funded status $(45,090) $(35,254)
Unrecognized transition obligation 3,582 3,928
Unrecognized prior service cost 1,715 1,821
Unrecognized net gain 10,216 (40)
Fourth quarter contributions 1,029 1,268
- ------------------------------------------------------------------
Accrued liability recognized in the
Balance Sheets $(28,548) $(28,277)
==================================================================
Components of the postretirement plans' net periodic cost
were as follows:
2002 2001 2000
- -----------------------------------------------------------------
(in thousands)
Service cost $ 959 $ 922 $ 830
Interest cost 3,781 3,411 3,309
Expected return on
plan assets (1,514) (1,409) (1,235)
Transition obligation 346 346 346
Prior service cost 106 80 -
Recognized net loss - (38) -
- -----------------------------------------------------------------
Net postretirement cost $ 3,678 $ 3,312 $ 3,250
=================================================================
The weighted average rates assumed in the actuarial calculations
for both the pension plans and postretirement benefits plan were:
2002 2001 2000
-----------------------------------------------------------------
Discount 6.50% 7.50% 7.50%
Annual salary increase 4.00 5.00 5.00
Long-term return on plan assets 8.50 8.50 8.50
-----------------------------------------------------------------
II-201
NOTES (continued)
Mississippi Power Company 2002 Annual Report
An additional assumption used in measuring the accumulated postretirement
benefit obligation was a weighted average medical care cost trend rate of 8.75
percent for 2002, decreasing gradually to 5.25 percent through the year 2010 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,
2002 as follows:
1 Percent 1 Percent
Increase Decrease
- ----------------------------------------------------------------
(in thousands)
Benefit obligation $4,438 $3,943
Service and interest costs 331 286
- ----------------------------------------------------------------
Employee Savings Plan
The Company also sponsors a 401(k) defined contribution plan covering
substantially all employees. The Company provides a 75 percent matching
contribution up to 6 percent of an employee's base salary. Total matching
contributions made to the plan for the years 2002, 2001, and 2000 were $2.6
million, $2.5 million, and $2.3 million, respectively.
3. CONTINGENCIES AND REGULATORY MATTERS
General
The Company is subject to certain claims and legal actions arising in the
ordinary course of business. The Company's business activities are also subject
to extensive governmental regulation related to public health and the
environment. Litigation over environmental issues and claims of various types,
including property damage, personal injury, and citizen enforcement of
environmental requirements, has increased generally throughout the United
States. In particular, personal injury claims for damages caused by alleged
exposure to hazardous materials have become more frequent.
The ultimate outcome of such litigation currently filed against the Company
cannot be predicted at this time; however, after consultation with legal
counsel, management does not anticipate that the liabilities, if any, arising
from such proceedings would have a material adverse effect on the Company's
financial statements.
Environmental Litigation
On November 1999, the Environmental Protection Agency (EPA) brought a civil
action in the U.S. District Court in Georgia against Alabama Power, Georgia
Power and the SCS. The complaint alleges violations of the 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 operating companies 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, Savannah
Electric and the Company 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 control
equipment when performing maintenance and construction at coal burning plants
constructed or under construction prior to 1978. The U.S. District Court in
Georgia granted Alabama Power's motion to dismiss for lack of jurisdiction and
granted the SCS' motion to dismiss on the grounds that it neither owned nor
operated the generating units involved in the proceedings. The court granted the
EPA's motion to add Savannah Electric as a defendant, but it denied the motion
to add Gulf Power and the Company based on lack of jurisdiction over those
companies. As directed by the court, the EPA re-filed its amended complaint
limiting claims to those brought against Georgia Power and Savannah Electric.
Also, the EPA re-filed its claims against Alabama Power in the U.S. District
Court in Alabama. It has not re-filed its claims against Gulf Power, SCS, or the
Company.
The Alabama Power, Georgia Power, and Savannah Electric cases have been
stayed since the spring of 2001, pending a ruling by the U.S. Court of Appeals
for the Eleventh Circuit in the appeal of a very similar New Source Review
II-202
NOTES (continued)
Mississippi Power Company 2002 Annual Report
enforcement action against the Tennessee Valley Authority (TVA). The TVA appeal
involves many of the same legal issues raised by the actions against Alabama
Power, Georgia Power, and Savannah Electric. Because the outcome of the TVA
appeal could have a significant adverse impact on Alabama Power and Georgia
Power, both companies have been parties to that appeal as well. In February
2003, the U.S. District Court in Alabama extended the stay of the EPA litigation
proceeding in Alabama until the earlier of May 6, 2003 or a ruling by the U.S.
Court of Appeals for the Eleventh Circuit in the related litigation involving
TVA. On August 21, 2002, the U.S. District Court in Georgia denied the EPA's
motion to reopen the Georgia case. The denial was without prejudice to the EPA
to refile the motion at a later date, which the EPA has not done at this time.
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 could 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.
Retail Rate Adjustment Plans
The Company's retail base rates are set under Performance Evaluation Plan (PEP),
a rate plan originally approved in 1986 and modified in 1994 and 2002. See "2001
Retail Rate Case." PEP was designed with the objective that the plan would
reduce the impact of rate changes on the customer and provide incentives for the
Company to keep customer prices low. PEP includes a mechanism for 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
the Company's performance-based return on investment. Any change in rates is
limited to 2 percent of retail revenues per evaluation period.
Environmental Compliance Overview Plan
The MPSC approved the Company's Environmental Compliance Overview Plan (ECO
Plan) in 1992. The ECO Plan establishes procedures to facilitate the MPSC's
overview of the Company's environmental strategy and provides for recovery of
costs (including costs of capital) associated with environmental projects
approved by the MPSC. Under the ECO Plan, any increase in the annual revenue
requirement is limited to 2 percent of retail revenues. However, the ECO Plan
also provides for carryover of any amount over the 2 percent limit into the next
year's revenue requirement. The Company 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. The
Company recovers such costs under the ECO Plan as they are incurred, as provided
for in the Company's 1995 ECO Plan Order. The Company filed its 2003 ECO Plan in
January 2003, which, if approved as filed, will result in a slight increase in
customer prices.
2001 Retail Rate Case
In August 2001, the Company filed a request with the MPSC for a retail rate
increase of approximately $46.4 million. In connection with the Company's
request, the MPSC suspended the semi-annual evaluations under PEP. In December
2001, the MPSC approved an increase of approximately $39 million, which took
effect in January 2002. Additionally, the MPSC ordered the Company to reactivate
the semi-annual evaluations under PEP, beginning with the 12-month period ending
December 31, 2002. PEP will remain in effect until the MPSC modifies, suspends
or terminates the plan. In May 2002, the MPSC issued an order adopting new
return on equity models to be used in the PEP process. The new models are very
similar to those that established the $39 million rate increase authorized in
December 2001 and are incorporated into the PEP evaluation filing for the period
ending December 31, 2002.
In 1998, the Company was granted a Certificate of Public Convenience and
Necessity to build approximately 1,064 megawatts of combined cycle generation at
the Company's Plant Daniel site. The certificate and ownership rights were
transferred to Escatawpa Funding Limited Partnership (Escatawpa), which is
II-203
NOTES (continued)
Mississippi Power Company 2002 Annual Report
currently leasing the facility to the Company. See Note 8 under "Lease
Agreements" for additional information. In October 2000, the MPSC approved a
cost allocation that allocates a pro-rata share of the Plant Daniel Unit 3 and 4
capacity, along with the Company's existing generation, to the retail
jurisdiction. The Company's 2001 retail rate case reflected this methodology and
the MPSC's December 2001 order on the retail rate case filing approved the
Company's cost allocations.
Wholesale Customer Settlement Agreement
In February 2002, the Company reached an agreement with certain of its wholesale
customers to increase its wholesale tariff rates effective June 1, 2002. The
FERC accepted the settlement agreement and placed the new tariff rates in effect
without modification. The settlement agreement results in an annual increase of
approximately $10.5 million, the adoption of an Energy Cost Management Clause
and the cost allocation of Plant Daniel Units 3 and 4, similar to the plans
approved by the Company's retail jurisdiction.
Right of Way Litigation
In 2002, the Company, along with Georgia Power, Gulf Power, Savannah Electric,
and Southern Telecom (collectively, defendants), were named as defendants in
numerous lawsuits brought by landowners regarding the installation and use of
fiber optic cable over defendants' rights of way located on the landowners'
property. The plaintiffs' lawsuits claim that defendants may not use or sublease
to third parties some or all of the fiber optic communications lines on the
rights of way that cross the plaintiffs' properties, and that such actions by
defendants exceed the easements or other property rights held by defendants. The
plaintiffs assert claims for, among other things, trespass and unjust
enrichment. The plaintiffs seek compensatory and punitive damages and injunctive
relief. Defendants believe that the plaintiffs' claims are without merit. An
adverse outcome in these matters could result in substantial judgments; however,
the final outcome of these matters cannot now be determined.
Transmission Facilities Agreement
In January 2002, FERC began conducting an investigation to determine
whether the cost of debt and the cost of preferred stock reflected in the amount
charged under the Transmission Facilities Agreement between Entergy Corp. and
the Company, when considered in light of other aspects of the contract, yield an
overall just and reasonable rate. The hearing is scheduled for September, 2003.
The Company believes that it is in full compliance with the terms of the
contract, which has been in place since 1982, and does not believe that it will
have a significant impact on the Company's financial results. However, the
outcome of FERC's investigation cannot be predicted.
4. JOINT OWNERSHIP AGREEMENTS
The Company and Alabama Power own as tenants in common Units 1 and 2 at Greene
County Steam Plant, which is located in Alabama and operated by Alabama Power.
Additionally, the Company and Gulf Power own as tenants in common Units 1 and 2
at Plant Daniel, which is located in Mississippi and operated by the Company.
At December 31, 2002, the Company'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% $65,223 $34,441
Daniel
Units 1 and 2 1,000 50% $237,912 $114,481
---------------------------------------------------------------
The Company's proportionate share of plant operating expenses is included in
the corresponding operating expenses in the Statements of Income.
5. LONG-TERM SALES AND FACILITY
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 Southern 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.
The Company has a 10-year power sale agreement with Dynegy that began in
June 2001. The minimum capacity revenue that the Company will receive will
II-204
NOTES (continued)
Mississippi Power Company 2002 Annual Report
average approximately $21 million per year through May 2011. Capacity revenues
for 2002 and 2001 were approximately $20.3 million and $12.3 million,
respectively, and were classified as sales for resale in the Statements of
Income. As a result of Dynegy's liquidity problems and under the terms of this
contract, Dynegy has provided a letter of credit expiring in April 2003 totaling
$26 million that can be drawn in the event of a default under the agreement or
the failure to renew the letters of credit prior to expiration.
In 1984, the Company and Entergy Corp. entered into a 40-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 2002,
2001 and 2000, use fees collected under this agreement, net of related expenses,
amounted to approximately $1.6 million, $2.5 million and $2.6 million
respectively, and are included within Other Income in the Statements of Income.
See Note 3 under "Transmission Facilities Agreement" for additional information.
6. INCOME TAXES
At December 31, 2002, the tax-related regulatory assets and liabilities were $13
million and $21 million, respectively. These assets are attributable to tax
benefits flowed through to customers in prior years and to taxes applicable to
capitalized interest. 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:
2002 2001 2000
----------------------------------
(in thousands)
Total provision for
income taxes
Federal --
Current $42,603 $43,596 $28,934
Deferred (3,122) (8,661) 622
----------------------------------------------------------------
39,481 34,935 29,556
----------------------------------------------------------------
State --
Current 6,680 6,698 4,670
Deferred (282) (1,057) 130
----------------------------------------------------------------
6,398 5,641 4,800
----------------------------------------------------------------
Total $45,879 $40,576 $34,356
================================================================
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:
2002 2001
------------------------------
(in thousands)
Deferred tax liabilities:
Accelerated depreciation $157,087 $147,147
Basis differences 7,791 8,271
Other 38,005 34,544
--------------------------------------------------------------
Total 202,883 189,962
--------------------------------------------------------------
Deferred tax assets:
Other property
basis differences 14,501 15,983
Pension and
other benefits 9,546 9,474
Property insurance 1,942 1,547
Unbilled fuel 6,048 5,596
Other 42,891 27,269
--------------------------------------------------------------
Total 74,928 59,869
--------------------------------------------------------------
Total deferred tax
liabilities, net 127,955 130,093
Portion included in current
assets, net 18,675 8,820
--------------------------------------------------------------
Accumulated deferred
income taxes in the
Balance Sheets $146,630 $138,913
==============================================================
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 2002, 2001, and 2000. At December 31, 2002, all
II-205
NOTES (continued)
Mississippi Power Company 2002 Annual Report
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:
2002 2001 2000
------------------------------
Federal statutory rate 35.0% 35.0% 35.0%
State income tax, net of
federal deduction 3.4 3.4 3.4
Non-deductible book
depreciation 0.5 0.5 0.6
Other (1.0) (0.8) (1.5)
--------------------------------------------------------------
Effective income tax rate 37.9% 38.1% 37.5%
==============================================================
Southern Company files a consolidated federal income tax return. Under a
joint consolidated income tax agreement, each subsidiary's current and deferred
tax expense is computed on a stand-alone basis. In accordance with Internal
Revenue Service regulations, each company is jointly and severally liable for
the tax liability.
7. CAPITALIZATION
Preferred Securities
Statutory trusts formed by the Company, of which the Company owns all the common
securities, have issued mandatorily redeemable preferred securities. In March
2002, Mississippi Power Capital Trust II sold $35 million of its 7.20% Trust
Originated Preferred Securities due December 30, 2041, which are guaranteed by
the Company. The proceeds of this issuance were used to redeem $35 million of
Mississippi Power Capital Trust I 7.75% Trust Originated Preferred Securities
originally issued in 1997.
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 Trust's payment obligations with respect to the
preferred securities.
Trust II is a subsidiary of the Company, and accordingly is consolidated in
the Company's financial statements.
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:
2002 2001
------------------
(in thousands)
Bond improvement fund requirement $ 634 $ 650
Less: Portion to be satisfied by
certifying property additions 634 650
-------------------------------------------------------------
Cash sinking fund requirement - -
Current portion of other long-term debt 68,350 80,000
Pollution control bond cash
sinking fund requirements 850 20
-------------------------------------------------------------
Total $69,200 $80,020
=============================================================
The first mortgage bond improvement fund requirement is one percent of each
outstanding series authenticated under the indenture of the Company 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.
Bank Credit Arrangements
At December 31, 2002, the Company had total committed credit agreements with
banks for approximately $97.5 million, all of which was unused. These credit
agreements expire in 2003. Some of these agreements allow short-term borrowings
to be converted into term loans, payable in 8 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. Commitment fees are less than 1/8 of 1
percent for the Company. Compensating balances are not legally restricted from
withdrawal.
This $97.5 million in unused credit arrangements provides required
liquidity support to the Company's borrowings through a commercial paper
program. The Company has a $67 million commercial paper program. At December 31,
II-206
NOTES (continued)
Mississippi Power Company 2002 Annual Report
2002, the Company had no outstanding commercial paper or extendible commercial
notes. The credit arrangements also provide support to the Company's variable
daily rate pollution control bonds.
Assets Subject to Lien
The Company'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.
Dividend Restrictions
The Company's first mortgage bond indenture and the corporate charter contain
various common stock dividend restrictions. At December 31, 2002, 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.
Pollution Control Bonds
The Company has incurred obligations in connection with the sale by public
authorities of tax-exempt pollution control revenue bonds. The amount of
tax-exempt pollution control revenue bonds outstanding at December 31, 2002 was
$83.5 million.
Senior Notes
In March 2002, the Company issued $80 million of Series D Floating Rate Senior
Notes due March 12, 2004. The proceeds of the sale were used to repay $80
million of Series C Floating Rate Senior Notes due March 28, 2002.
8. COMMITMENTS
Construction Program
The Company is engaged in continuous construction programs, primarily related to
transmission and distribution facilities and generating plants, the costs of
which are currently estimated to total $76 million in 2003, $86 million in 2004,
and $75 million in 2005. 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;
FERC rules and transmission regulations; increasing costs of labor, equipment
and materials; and cost of capital. At December 31, 2002, significant purchase
commitments were outstanding in connection with the construction program.
Long-Term Service Agreements
The Company has entered into a Long-Term Service Agreement (LTSA) with General
Electric (GE) for the purpose of securing maintenance support for the lease
combined cycle units at Plant Daniel. In summary, the LTSA stipulates that GE
will perform all planned inspections on the covered equipment, which includes
the cost of all labor and materials. GE is also obligated to cover the costs of
unplanned maintenance on the covered equipment subject to a limit specified in
the contract. However, the LTSA contains various cancellation provisions at the
option of the Company.
In general, the LTSA is in effect through two major inspection cycles of
the units. Scheduled payments to GE are made monthly based on estimated
operating hours of the units and are recognized as an expense based on actual
hours of operation. The Company has recognized $11 million and $9.6 million for
2002 and 2001, respectively, which is included in maintenance expense on the
Statements of Income. Total remaining payments to GE under this agreement are
currently estimated to total $166.5 million over the next 11 years.
Lease Agreements
In 1989, the Company 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 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. Both of these leases were for the transport of coal to Plant
Daniel.
Gulf Power, as joint owner of Plant Daniel Units 1 and 2, is responsible
for one half of the lease cost. The Company's share (50%) of the leases, charged
to fuel stock and recovered through the fuel cost recovery clause, was $1.9
million in 2002, $1.9 million in 2001, and $2.1 million in 2000. The Company's
II-207
NOTES (continued)
Mississippi Power Company 2002 Annual Report
annual lease payments for 2003 through 2007 will average approximately $2.0
million and after 2007, lease payments total in aggregate approximately $10
million.
In 1999, the Company signed an Agreement for Lease and a Lease Agreement
with Escatawpa Funding, Limited Partnership (Escatawpa). These agreements called
for the Company to design and construct, as agent for Escatawpa, a 1,064
megawatt natural gas combined cycle facility at the Company's Plant Victor J.
Daniel Facility (Facility). The Company entered into this transaction during a
period when retail access was under review by MPSC. Additionally, the lease
arrangement provided a lower cost alternative to its cost based rate regulated
customers than a traditional rate base asset. See Note 3 under "Retail Rate
Adjustment Plans" for a description of the Company's PEP formula rate plan. The
Facility is treated as an operating lease for accounting purposes, as well as
for both retail and wholesale rate recovery purposes. For income tax purposes,
the Company retains tax ownership.
In May 2001, the Facility was completed, placed into commercial operation
and the initial 10-year lease term began. The completion cost was approximately
$370 million. The lease provides for a residual value guarantee (approximately
71% of the completion cost) by the Company that is due upon termination of the
lease in certain circumstances. The lease also includes a purchase and renewal
option. The purchase price is based on the completion cost of the Facility. The
Company is required to amortize approximately 10% of the initial completion cost
over the initial ten year period. Eighteen months prior to the end of the
initial lease, the Company may elect to renew for another 10 years. If the
Company elects to renew the lease, the agreement calls for the Company to
amortize an additional 17% of the initial completion cost over the renewal
period. Upon termination of the lease, at the Company's option, the Company may
either exercise its purchase option or the Facility can be sold to a third
party. The Company expects that the fair market value of the Facility would
substantially reduce or eliminate the payment under the residual value
guarantee. In 2002 and 2001, the Company recognized approximately $26 million
and $18 million, respectively, in lease expense which includes approximately
$3.5 million and $2.4 million, respectively, related to the amortization of the
initial completion cost.
The Company does not consolidate Escatawpa on its balance sheet since
parties unrelated to the Company and Southern Company have made substantive
residual equity investments in excess of 3 percent. In January 2003, the FASB
issued its Interpretation No. 46, Consolidation of Certain Special-Purpose
Entities. Under this interpretation, the Company would be required to
consolidate Escatawpa as of July 1, 2003, and record a cumulative effect
adjustment as if the Company had initially recorded that asset on its books. If
the Company does not restructure the existing arrangement, the impact of
consolidating Escatawpa would result in a cumulative effect adjustment relating
to depreciation of approximately $13 million, net of tax, through June 30, 2003
and additional expenses of approximately $10.8 million annually thereafter.
Consolidating the asset and related debt or restructuring the current
arrangement could require further regulatory review by the MPSC.
The Company estimates that its annual amount of future minimum operating
lease payments under this arrangement, exclusive of any payment related to the
residual value guarantee, as of December 31, 2002, are as follows:
Year Lease Payments
(in millions)
2003 $26
2004 26
2005 26
2006 25
2007 25
2008 and thereafter 98
- -------------------------------------------------------------
Total commitments $226
=============================================================
Fuel
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
fuel. In most cases, these contracts contain provisions for price escalations,
minimum production levels, and other financial commitments. In addition, the
Company utilizes financial instruments to eliminate price volatility.
II-208
NOTES (continued)
Mississippi Power Company 2002 Annual Report
Total estimated fixed-price obligations at December 31, 2002 are as
follows:
Year Fuel
(in millions)
2003 $191
2004 74
2005 6
2006 6
2007 6
2008 and thereafter 65
- -----------------------------------------------------------
Total commitments $348
===========================================================
In addition, SCS acts as agent for the five operating companies, Southern
Power and Southern GAS with regard to natural gas purchases. Natural gas
purchases (in dollars) are based on various market indices at the actual time of
delivery; therefore, only the volume commitments are firm. The Company's
committed volumes allocated based on usage projections, as of December 31, 2002
are as follows:
Year Natural Gas
(MMBtu)
2003 42,172,935
2004 25,730,963
2005 9,796,080
2006 6,381,115
2007 2,088,762
- -----------------------------------------------------------
Total commitments 86,169,855
===========================================================
Additional commitments for fuel will be required to supply the Company's
future needs.
Acting as an agent for all of Southern Company's operating companies,
Southern Power, and Southern GAS, SCS may enter into various types of wholesale
energy and natural gas contracts. Each of the operating companies, Southern
Power, and Southern GAS may be jointly and severally liable for the obligations
under these agreements. Accordingly, the creditworthiness of Southern Power and
Southern GAS are currently inferior to the creditworthiness of the operating
companies. Southern Company has entered into keep-well agreements with each of
the operating companies, including the Company, to insure they will not
subsidize or be responsible for any costs, losses, liabilities, or damages
resulting from the inclusion of Southern Power or Southern GAS as a contracting
party under these agreements.
9. QUARTERLY FINANCIAL DATA (UNAUDITED)
Summarized quarterly financial data for 2002 and 2001 are as follows:
Net Income
After Dividends
Operating Operating On Preferred
Quarter Ended Revenues Income Stock
- -------------------------------------------------------------------
(in thousands)
March 2002 $183,058 $28,873 $13,982
June 2002 205,378 38,457 20,788
September 2002 243,077 60,010 33,384
December 2002 192,652 17,930 4,859
March 2001 $171,312 $23,615 $ 9,757
June 2001 203,949 32,640 16,571
September 2001 235,916 53,263 30,379
December 2001 184,888 23,315 7,180
- -------------------------------------------------------------------
The Company's business is influenced by seasonal weather conditions
and the timing of rate changes.
II-209
SELECTED FINANCIAL AND OPERATING DATA 1998-2002 Mississippi Power Company 2002
Annual Report
- -----------------------------------------------------------------------------------------------------------------------------
2002 2001 2000 1999 1998
- -----------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands)* $824,165 $796,065 $687,602 $633,004 $595,131
Net Income after Dividends
on Preferred Stock (in thousands) $73,013 $63,887 $54,972 $54,809 $55,105
Cash Dividends
on Common Stock (in thousands) $63,500 $50,200 $54,700 $56,100 $51,700
Return on Average Common Equity (percent) 14.46 14.25 13.80 14.00 14.15
Total Assets (in thousands) $1,412,166 $1,340,203 $1,275,071 $1,251,136 $1,189,605
Gross Property Additions (in thousands) $67,460 $61,193 $81,211 $75,888 $68,231
- -----------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $517,953 $491,680 $404,898 $391,968 $391,231
Preferred stock 31,809 31,809 31,809 31,809 31,809
Company obligated mandatorily
redeemable preferred securities 35,000 35,000 35,000 35,000 35,000
Long-term debt 243,715 233,753 370,511 321,802 292,744
- -----------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $828,477 $792,242 $842,218 $780,579 $750,784
=============================================================================================================================
Capitalization Ratios (percent):
Common stock equity 62.5 62.1 48.1 50.2 52.1
Preferred stock 3.8 4.0 3.8 4.1 4.2
Company obligated mandatorily
redeemable preferred securities 4.2 4.4 4.2 4.5 4.7
Long-term debt 29.5 29.5 43.9 41.2 39.0
- -----------------------------------------------------------------------------------------------------------------------------
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 A+ A+ A+ AA- AA-
Fitch AA- AA- AA- AA- AA-
Preferred Stock -
Moody's A3 A3 a1 a1 a1
Standard and Poor's BBB+ BBB+ BBB+ A- A
Fitch A A A A A+
Unsecured Long-Term Debt -
Moody's A1 A1 - - -
Standard and Poor's A A - - -
Fitch A+ A+ - - -
=============================================================================================================================
Customers (year-end):
Residential 158,873 158,852 158,253 157,592 156,530
Commercial 32,713 32,538 32,372 31,837 31,319
Industrial 489 498 517 546 587
Other 171 173 206 202 200
- -----------------------------------------------------------------------------------------------------------------------------
Total 192,246 192,061 191,348 190,177 188,636
=============================================================================================================================
Employees (year-end): 1,301 1,316 1,319 1,328 1,230
- -----------------------------------------------------------------------------------------------------------------------------
* 1999 data includes the true-up of the unbilled revenue estimates.
II-210
SELECTED FINANCIAL AND OPERATING DATA 1998-2002 (continued)
Mississippi Power Company 2002 Annual Report
- --------------------------------------------------------------------------------------------------------------------------------
2002 2001 2000 1999 1998
- --------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands)*:
Residential $186,522 $164,716 $170,729 $159,945 $157,642
Commercial 181,224 163,253 163,552 153,936 145,677
Industrial 164,042 156,525 159,705 151,244 135,039
Other 5,039 4,659 4,565 4,309 4,209
- --------------------------------------------------------------------------------------------------------------------------------
Total retail 536,827 489,153 498,551 469,434 442,567
Sales for resale - non-affiliates 224,275 204,623 145,931 131,004 121,225
Sales for resale - affiliates 46,314 85,652 27,915 19,446 18,285
- --------------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 807,416 779,428 672,397 619,884 582,077
Other revenues 16,749 16,637 15,205 13,120 13,054
- --------------------------------------------------------------------------------------------------------------------------------
Total $824,165 $796,065 $687,602 $633,004 $595,131
================================================================================================================================
Kilowatt-Hour Sales (in thousands)*:
Residential 2,300,017 2,162,623 2,286,143 2,248,255 2,248,915
Commercial 2,902,291 2,840,840 2,883,197 2,847,342 2,623,276
Industrial 4,161,902 4,275,781 4,376,171 4,407,445 3,729,166
Other 39,635 41,009 41,153 40,091 39,772
- --------------------------------------------------------------------------------------------------------------------------------
Total retail 9,403,845 9,320,253 9,586,664 9,543,133 8,641,129
Sales for resale - non-affiliates 5,380,145 5,011,212 3,674,621 3,256,175 3,157,837
Sales for resale - affiliates 1,586,968 2,952,455 452,611 539,939 552,142
- --------------------------------------------------------------------------------------------------------------------------------
Total 16,370,958 17,283,920 13,713,896 13,339,247 12,351,108
================================================================================================================================
Average Revenue Per Kilowatt-Hour (cents)*:
Residential 8.11 7.62 7.47 7.11 7.01
Commercial 6.24 5.75 5.67 5.41 5.55
Industrial 3.94 3.66 3.65 3.43 3.62
Total retail 5.71 5.25 5.20 4.92 5.12
Sales for resale 3.88 3.64 4.21 3.96 3.76
Total sales 4.93 4.51 4.90 4.65 4.71
Residential Average Annual
Kilowatt-Hour Use Per Customer * 14,453 13,634 14,445 14,301 14,376
Residential Average Annual
Revenue Per Customer * $1,172.12 $1,038.41 $1,078.76 $1,017.42 $1,007.68
Plant Nameplate Capacity
Ratings (year-end) (megawatts) 3,156 3,156 2,086 2,086 2,086
Maximum Peak-Hour Demand (megawatts):
Winter 2,311 2,249 2,305 2,125 1,740
Summer 2,492 2,466 2,593 2,439 2,339
Annual Load Factor (percent) 61.8 60.7 59.3 59.6 58.0
Plant Availability Fossil-Steam (percent): 91.7 92.8 92.6 91.0 90.0
- --------------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 50.8 52.0 67.8 69.4 66.5
Oil and gas 37.7 35.9 13.5 15.9 14.5
Purchased power -
From non-affiliates 3.1 3.1 7.7 6.2 8.0
From affiliates 8.4 9.0 11.0 8.5 11.0
- --------------------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0 100.0 100.0
================================================================================================================================
* 1999 data includes the true-up of the unbilled revenue estimates.
II-211
SAVANNAH ELECTRIC AND POWER COMPANY
FINANCIAL SECTION
II-212
MANAGEMENT'S REPORT
Savannah Electric and Power Company 2002 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 accounting
principles generally accepted in the United States 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 accounting 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.
Southern Company's audit committee of its board of directors, composed of
five independent directors, provides a broad overview of management's financial
reporting and control functions. Additionally, a committee of Savannah Electric
and Power Company's board of directors, composed of five outside directors,
meets periodically with management, the internal auditors and the independent
public accountants to discuss auditing, internal controls and compliance
matters. The internal auditors and the independent public accountants have
access to the members of these committees 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 accounting principles
generally accepted in the United States.
/s/Anthony R. James
Anthony R. James
President
and Chief Executive Officer
/s/K. R. Willis
K. R. Willis
Vice President,
Treasurer, Chief Financial Officer
and Assistant Secretary
February 17, 2003
II-213
INDEPENDENT AUDITORS' REPORT
Savannah Electric and Power Company:
We have audited the accompanying balance sheet and statement of capitalization
of Savannah Electric and Power Company (a wholly owned subsidiary of Southern
Company) as of December 31, 2002, and the related statements of income,
comprehensive income, common stockholder's equity, and cash flows for the year
then ended. These financial statements are the responsibility of Savannah
Electric and Power Company's management. Our responsibility is to express an
opinion on these financial statements based on our audit. The financial
statements of Savannah Electric and Power Company as of December 31, 2001, and
for each of the two years then ended were audited by other auditors who have
ceased operations. Those auditors expressed an unqualified opinion on those
financial statements and included an explanatory paragraph that described a
change in the method of accounting for derivative instruments and hedging
activities in their report dated February 13, 2002.
We conducted our audit in accordance with auditing standards generally
accepted in the United States of America. 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 audit provides a
reasonable basis for our opinion.
In our opinion, the 2002 financial statements (pages II-228 to II-245)
present fairly, in all material respects, the financial position of Savannah
Electric and Power Company at December 31, 2002, and the results of its
operations and its cash flows for the year then ended in conformity with
accounting principles generally accepted in the United States of America.
/s/Deloitte & Touche LLP
Atlanta, Georgia
February 17, 2003
THE FOLLOWING REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS IS A COPY OF THE REPORT
PREVIOUSLY ISSUED IN CONNECTION WITH THE COMPANY'S 2001 ANNUAL REPORT ON FORM
10-K AND HAS NOT BEEN REISSUED BY ARTHUR ANDERSEN LLP.
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, 2001 and 2000, 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, 2001. 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-192 through II-206)
referred to above present fairly, in all material respects, the financial
position of Savannah Electric and Power Company as of December 31, 2001 and
2000, and the results of its operations and its cash flows for each of the three
years in the period ended December 31, 2001, in conformity with accounting
principles generally accepted in the United States.
As explained in Note 1 to the financial statements, effective January 1,
2001, Savannah Electric and Power Company changed its method of accounting for
derivative instruments and hedging activities.
/s/ Arthur Andersen LLP
Atlanta, Georgia
February 13, 2002
II-214
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Savannah Electric and Power Company 2002 Annual Report
RESULTS OF OPERATIONS
- ---------------------
Earnings
Savannah Electric and Power Company's net income for 2002 totaled $22.9 million,
representing an increase of $0.8 million or 3.7 percent from the prior year.
Earnings were up primarily due to higher retail revenues, somewhat offset by
higher operating expenses.
Earnings were $22.1 million in 2001 and $23.0 million in 2000. Compared to
prior years, this represented a 3.9 percent decrease in 2001 and no significant
change in 2000.
A condensed income statement is as follows:
Increase (Decrease)
Amount From Prior Year
- ------------------------------------------------------------------
2002 2002 2001 2000
- ------------------------------------------------------------------
(in thousands)
Operating revenues $299,552 $15,700 $(11,866) $44,124
- ------------------------------------------------------------------
Fuel 54,955 4,159 (6,381) 6,647
Purchased power 75,604 2,518 (2,254) 27,544
Other operation
and maintenance 81,018 10,525 (1,927) 5,746
Depreciation
and amortization 22,704 (3,247) 711 1,399
Taxes other than
income taxes 14,457 473 868 426
-----------------------------------------------------------------
Total operating
Expenses 248,738 14,428 (8,983) 41,762
- ------------------------------------------------------------------
Operating income 50,814 1,272 (2,883) 2,362
Other income
(expense), net (15,501) 247 134 (710)
Less --
Income taxes 12,433 702 (1,843) 1,766
- ------------------------------------------------------------------
Net Income $ 22,880 $ 817 $ (906) $ (114)
==================================================================
Revenues
Total operating revenues for 2002 were $299.6 million, reflecting a
5.5 percent increase when compared to 2001. The following table
summarizes the factors affecting operating revenues for the past
three years:
Amount
---------------------------------------
2002 2001 2000
---------------------------------------
(in thousands)
Retail - prior year $269,172 $282,622 $242,265
Change in --
Base rates 5,101 - (499)
Sales growth 8,729 (1,541) 6,798
Weather 2,397 (427) 2,973
Fuel cost recovery
and other 372 (11,482) 31,085
- ------------------------------------------------------------------
Total retail 285,771 269,172 282,622
- ------------------------------------------------------------------
Sales for resale --
Non-affiliates 6,354 8,884 4,748
Affiliates 4,075 3,205 4,974
- ------------------------------------------------------------------
Total sales for resale 10,429 12,089 9,722
- ------------------------------------------------------------------
Other operating revenues 3,352 2,591 3,374
- ------------------------------------------------------------------
Total operating revenues $299,552 $283,852 $295,718
==================================================================
Percent change 5.5% (4.0)% 17.5%
- ------------------------------------------------------------------
Retail revenues increased 6.2 percent or $16.6 million in 2002, declined
$13.5 million in 2001, and increased $40.4 million in 2000. The significant
factors driving these changes are shown in the table above. Retail base rates
increased reflecting the Georgia Public Service Commission (GPSC) decision
effective June 2002. See Note 3 to the financial statements under "Retail
Regulatory Matters" for additional information on the Company's 2002 rate order.
Electric rates include provisions to adjust billings for fluctuations in
fuel costs, the energy component of purchased power costs, and certain other
costs. Under the fuel recovery provisions, fuel revenues generally equal fuel
expenses--including the fuel component of purchased energy--and do not affect
net income. In May 2001, the Company implemented a Fuel Cost Recovery (FCR) rate
increase under a GPSC rate order. The order established a new fuel rate to
better reflect current fuel costs and to collect the under-recovered balance.
The GPSC-approved FCR anticipated a three year recovery of the under-recovered
fuel balance. Due to decreasing fuel costs in late 2001 and early 2002, the
Company recovered all of this balance by March 2002. In May 2002, the GPSC
II-215
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 2002 Annual Report
approved a FCR decrease which more than offset the Company's base rate increase.
See Note 3 to the financial statements under "Retail Regulatory Matters" for
additional information on the Company's 2002 rate order.
Revenues from sales to utilities outside the service area under long-term
contracts may include both capacity and energy components. These transactions do
not have a significant impact on earnings since the energy is generally sold at
variable cost.
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 energy 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 2002 and the percent change by year were as
follows:
KWH Percent Change
----------- --------------------------
2002 2002 2001 2000
----------- ---------------------------
(in millions)
Residential 1,793 8.1% (0.7)% 5.8%
Commercial 1,477 6.4 1.4 6.3
Industrial 793 0.7 (1.6) 12.2
Other 140 4.4 (1.4) 2.5
-----------
Total retail 4,203 5.9 (0.2) 7.1
Sales for resale --
Non-affiliates 151 35.7 43.4 50.3
Affiliates 126 43.4 (1.0) 15.1
-----------
Total 4,480 7.5% 0.6% 7.8%
===============================================================
In 2002, residential and commercial energy sales increased from the prior
year reflecting the positive impact of weather and continued growth in
customers. Industrial sales increased slightly reflecting customer growth,
offset by a general economic slowdown.
In 2001, total retail energy sales were down slightly from the prior year,
reflecting a decrease in energy sales of 1.6 percent to industrial customers due
to a slowing of the economy. Residential energy sales also decreased reflecting
weather related demand, somewhat offset by customer growth. In 2000, total
retail energy sales were up by 7.1 percent from the prior year, reflecting
increased energy sales of 12.2 percent to industrial customers due to the
re-opening of an industrial facility under new ownership. Residential and
commercial energy sales also increased reflecting weather-related demand and
customer growth.
Expenses
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 generating units.
The amount and sources of energy supply and the total average cost of
energy supply were as follows:
2002 2001 2000
--------------------------
Total energy supply
(millions of KWHs) 4,628 4,310 4,286
Sources of energy supply
(percent) --
Coal 45 50 52
Oil - 1 2
Gas 4 3 5
Purchased power 51 46 41
Total average cost of
energy supply (cents/KWH) 2.82 2.87 3.09
- -----------------------------------------------------------------
Fuel expense increased 8.2 percent due to increased gas usage and a higher
cost of coal in 2002. In 2001, fuel expense decreased 11.2 percent due to a
decrease in generation and a slightly lower average cost of fuel. In 2000, fuel
expense increased 13.2 percent due to an increase in generation and a higher
average cost of fuel.
Purchased power expense increased 3.4 percent in 2002 primarily due to an
increase in energy demands. Purchased power from non-affiliates decreased 72.5
percent and increased from affiliates 38.6 percent in 2002 due principally to a
purchased power agreement between the Company and Southern Power for energy and
capacity from Plant Wansley Units 6 and 7 which began operation in June 2002.
Purchased power expense decreased 3.0 percent in 2001 primarily due to lower
fuel prices. Purchased power expense, in 2000, increased 57.6 percent over the
prior year due to higher energy demands and higher energy prices.
II-216
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 2002 Annual Report
In 2002, other operation and maintenance expenses increased 14.9 percent.
Other operation expense was higher reflecting increased distribution and
administrative and general costs and costs associated with new marketing
programs. Distribution costs increased to support improved customer reliability.
Administrative and general costs were higher primarily due to increases in
security, outside services including legal, accounting and auditing, regulatory
activities, and employee benefits expenses. Administrative and general expenses
were also higher reflecting the annual true-up in billings to Georgia Power for
charges associated with the jointly owned combustion turbines at the Company's
Plant McIntosh. Maintenance expense increased from 2001 primarily as a result of
scheduled maintenance outages at Plant Kraft and amortization of expenses for a
major maintenance project on the combustion turbines at Plant McIntosh. See Note
3 to the financial statements under "Retail Regulatory Matters" for additional
information.
In 2001, other operation expense decreased 4.7 percent reflecting the
discontinuation of a marketing program and lower administrative and general
expenses. Administrative and general expenses decreased primarily due to the
annual true-up in billings to Georgia Power for charges associated with the
jointly owned combustion turbines at the Company's Plant McIntosh and lower
insurance expenses. Other operation and maintenance expenses in 2000 increased
8.6 percent over the prior year. Other operation expense was higher reflecting
increased employee benefit expenses. Maintenance expense increased from 1999
reflecting higher power delivery and power generation maintenance costs to
support improved customer reliability and unit availability, respectively.
Depreciation and amortization decreased 12.5 percent in 2002 primarily as a
result of discontinuing accelerated depreciation and beginning amortization of
the related regulatory liability in June 2002, in accordance with the 2002 rate
order. Depreciation and amortization increased over prior years by 2.8 percent
in 2001 and 5.9 percent in 2000 primarily due to additional depreciation charges
under a 1998 GPSC accounting order. See Note 3 to the financial statements under
"Retail Regulatory Matters" for additional information.
Interest expense decreased in 2002 and 2001 primarily due to lower
interest rates. Interest expense increased in 2000 due to higher rates on
variable rate debt and an increase in short-term debt.
Effects of Inflation
The Company is subject to rate regulation that is based on the recovery of
historical costs. In addition, the income tax laws are also based on 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 or the partially offsetting gain that
arises through financing facilities with fixed-money obligations such as
long-term debt and trust preferred securities. Any recognition of inflation by
regulatory authorities is reflected in the rate of return allowed.
Future Earnings Potential
General
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, which include maintaining a stable regulatory environment and
achieving energy sales growth while containing costs.
Future earnings in the near term will depend, in part, upon growth in
energy sales, which is subject to a number of factors. These factors include
weather, competition, energy conservation practiced by customers, the elasticity
of demand, and the rate of economic growth in the Company's service area.
The Company 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).
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 2002 Annual Report
In November 2001, the Company filed a request with the GPSC for a base rate
increase of $24.4 million to recover expenses related to a new purchased power
agreement and other operation and maintenance expenses. The Company also filed
for a fuel cost recovery decrease in March 2002. In May 2002, the GPSC approved
a $7.8 million base rate increase and an authorized return on equity of 12.0
percent. At the same time, the GPSC also approved a $44.3 million fuel cost
recovery reduction. All customers saw a net rate decrease effective June 2002.
In August 2002, the GPSC denied the Company's request for reconsideration of the
base rate case decision. In November 2002, the Company filed a request for an
accounting order to defer approximately $3.8 million annually in Plant Wansley
purchased power costs, which the GPSC had ruled to be outside of the test period
in the Company's base rate order. On December 17, 2002, an accounting order was
approved by the GPSC, which allows the deferral of these costs until May 2005.
Under the terms of the order, two-thirds of any earnings of the Company in a
calendar year above a 12 percent return on common equity will be used to
amortize the deferred amounts to expense. The remaining one-third of any such
earnings will be retained by the Company. In January 2003, the Company began
deferring the costs under the terms of the accounting order.
Prior to the 2002 base rate case order, the Company had been operating
under a four-year accounting order approved by the GPSC. See Note 3 to the
financial statements under "Retail Regulatory Matters" for additional
information.
The Company plans to retire a 102 megawatt peaking facility in May 2005. In
June 2002, the Company entered into a fifteen-year purchased power agreement
with Southern Power for 200 megawatts of capacity beginning in June 2005 from
the planned combined-cycle plant at Plant McIntosh to be built and owned by
Southern Power. The annual capacity cost is expected to be approximately $15.0
million. In December 2002, the Company received certification of this capacity
from the GPSC.
In accordance with Financial Accounting Standards Board (FASB) Statement
No. 87, Employers' Accounting for Pensions, the Company recorded non-cash
pension costs of approximately $4.4 million pre-tax in 2002. Future pension
costs are dependent on several factors including trust earnings and changes to
the plan. Postretirement benefit costs for the Company were approximately $2.6
million in 2002 and are expected to continue to trend upward. A portion of
pension and postretirement benefit costs is capitalized based on
construction-related labor charges. For more information regarding pension and
postretirement benefits, see Note 2 to the financial statements.
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 under
"Environmental Matters."
Industry Restructuring
The electric utility industry in the United States is continuing to evolve as a
result of regulatory and competitive factors. Among the primary agents of change
was 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 enhanced the incentive for
IPPs to build power plants for a utility's large industrial and commercial
customers where retail access is allowed and sell energy to other utilities.
Also, electricity sales for resale rates were affected by numerous new energy
suppliers, including power marketers and brokers.
This past year, merchant energy companies and traditional electric utilities
with significant energy marketing and trading activities came under severe
financial pressures. Many of these companies have completely exited or
drastically reduced all energy marketing and trading activities and sold foreign
and domestic electric infrastructure assets. The Company has not experienced any
material financial impact regarding its limited energy trading operations.
Although the Energy Act does not provide for retail customer access, it was
a major catalyst for restructuring and consolidation that took place within the
utility industry. Numerous federal and state initiatives that promote wholesale
and retail competition are in varying stages. Among other things, these
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 2002 Annual Report
initiatives allow retail customers in some states to choose their electricity
provider. 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 discussed in Georgia, none
have been enacted. Enactment could require numerous issues to be resolved,
including significant ones relating to recovery of any stranded investments,
full cost recovery of energy produced, and other issues related to the energy
crisis that occurred in California. The Company does 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.
FERC Matters
In December 1999, the FERC issued its final rule on Regional Transmission
Organizations (RTOs). The order encouraged utilities owning transmission systems
to form RTOs on a voluntary basis. Southern Company and its operating companies,
including the Company, have submitted a series of status reports informing the
FERC of progress toward the development of a Southeastern RTO. In these status
reports, Southern Company explained that it is developing a for-profit RTO known
as SeTrans with a number of non-jurisdictional cooperative and public power
entities. In 2002, Entergy Corporation and Cleco Power joined the SeTrans
development process. In 2002, the sponsors of SeTrans established a Stakeholder
Advisory Committee, which will participate in the development of the RTO, and
held public meetings to discuss the SeTrans proposal. On October 10, 2002, the
FERC granted Southern Company's and other SeTrans' sponsors petition for a
declaratory order regarding the governance structure and the selection process
for the Independent System Administrator (ISA) of the SeTrans RTO. The FERC also
provided guidance on other issues identified in the petition. The SeTrans
sponsors announced the selection of ESB International, Ltd. (ESBI) to be the
preferred ISA candidate. Should negotiations with this candidate successfully
conclude with final agreement among the parties, the SeTrans sponsors intend to
seek any state and federal regulatory or other approvals necessary for formation
of the SeTrans RTO and the approval of ESBI to serve in the capacity of the
SeTrans ISA. The creation of SeTrans is not expected to have a material impact
on the Company's financial statements; however, the outcome of this matter
cannot now be determined.
In July 2002, the FERC issued a notice of proposed rulemaking regarding
open access transmission service and standard electricity market design. The
proposal, if adopted, would among other things: (1) require transmission assets
of jurisdictional utilities to be operated by an independent entity; (2)
establish a standard market design; (3) establish a single type of transmission
service that applies to all customers; (4) assert jurisdiction over the
transmission component of bundled retail service; (5) establish a generation
reserve margin; (6) establish bid caps for a day ahead and spot energy markets;
and (7) revise the FERC policy on the pricing of transmission expansions.
Comments on certain aspects of the proposal have been submitted by Southern
Company. Any impact of this proposal on Southern Company and its subsidiaries,
including the Company, will depend on the form in which final rules may be
ultimately adopted; however, the Company's revenues, expenses, assets, and
liabilities could be adversely affected by changes in the transmission
regulatory structure in its regional power market.
Accounting Policies
Critical Policy
The Company's significant accounting policies are described in Note 1 to the
financial statements. The Company's only critical accounting policy involves
rate regulation. 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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 2002 Annual Report
New Accounting Standards
Derivatives
- -----------
Effective January 2001, the Company adopted FASB Statement No. 133, Accounting
for Derivative Instruments and Hedging Activities, as amended. In October 2002,
the Emerging Issues Task Force (EITF) of the FASB announced accounting changes
related to energy trading contracts in Issue No. 02-03. In October 2002, the
Company prospectively adopted the EITF's requirement to reflect the impact of
certain energy trading contracts on a net basis. This change had no material
impact on the Company's income statement. Another change also required certain
energy trading contracts to be accounted for on an accrual basis effective
January 2003. This change had no impact on the Company's current accounting
treatment.
Asset Retirement Obligations
- ----------------------------
Prior to the adoption of FASB Statement No. 143 in January 2003, the Company
accrued for the ultimate cost of retiring most long-lived assets over the life
of the related asset through depreciation expense. FASB Statement No. 143,
Accounting for Asset Retirement Obligations, establishes new accounting and
reporting standards for legal obligations associated with the ultimate cost of
retiring long-lived assets. The present value of the ultimate costs for an
asset's future retirement must be recorded in the period in which the liability
is incurred. The cost must be capitalized as part of the related long-lived
asset and depreciated over the asset's useful life. Additionally, Statement No.
143 does not permit non-regulated companies to continue accruing future
retirement costs for long-lived assets that they do not have a legal obligation
to retire. See Note 1 to the financial statements under "Depreciation and
Amortization" and "Regulatory Assets and Liabilities" for information regarding
the financial statement impacts of adopting this standard effective January 1,
2003.
Guarantees
- ----------
In 2002, the FASB issued Interpretation No. 45, Accounting and Disclosure
Requirements for Guarantees. This interpretation requires disclosure of certain
direct and indirect guarantees. In addition, it requires recognition of a
liability at inception for any new or modified guarantees issued after December
31, 2002. The adoption of this new standard had no impact on the Company's
financial statements.
FINANCIAL CONDITION
- -------------------
Plant Additions
The principal change in the Company's financial condition in 2002 was the
addition of $32.5 million to utility plant. The funds needed for gross property
additions are currently provided from operating activities and from financing
activities. See Statements of Cash Flows for additional information.
Credit Rating Risk
The Company does not have any credit agreements that would require material
changes in payment schedules or terminations as a result of a credit rating
downgrade.
Exposure to Market Risks
Due to cost-based regulation, the Company has limited exposure to market
volatility in interest rates, commodity fuel prices, and prices of electricity.
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. Company
policy is that derivatives are to be used primarily for hedging purposes.
Derivative positions are monitored using techniques that include market
valuation and sensitivity analysis.
The weighted average rate on variable rate long-term debt outstanding at
December 31, 2002 was 2.0 percent. If the Company sustained a 100 basis point
change in interest rates for all variable rate long-term debt, the change would
have affected annualized interest expense by approximately $0.4 million at
December 31, 2002. See Note 1 to the financial statements under "Financial
Instruments" for additional information. The Company is not aware of any facts
or circumstances that would significantly affect such exposures in the near
term.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 2002 Annual Report
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. In addition, on June 1,
2001, the Company implemented a natural gas/oil hedging program ordered by the
GPSC. The program has negative financial hedge limits. In terms of dollar
amounts, negative financial hedging positions, recoverable through the fuel
clause, are limited to an above market cap equal to 10 percent of the Company's
annual natural gas/oil budget. These hedging position limits were $1.5 million
for 2001, $2.4 million for 2002 and will be $1.1 million for 2003. The program
has operated within the defined hedging position limits set for each year.
The fair value of changes in derivative energy trading contracts and
year-end valuations are as follows:
Changes in Fair Value
- ---------------------------------------------------------------
2002 2001
- ---------------------------------------------------------------
(in thousands)
Contracts beginning of year $(1,053) $ 36
Contracts realized or settled 269 (32)
New contracts at inception - -
Changes in valuation
techniques - -
Current period changes 1,410 (1,057)
- ---------------------------------------------------------------
Contracts end of year $ 626 $ (1,053)
===============================================================
Source of Year-End Valuation Prices
- ------------------------------------------------------------------
Maturity
Total ------------------------
Fair Value Year 1 2-3 Years
- ------------------------------------------------------------------
(in thousands)
- -----------------------------------------------------------------
Actively quoted $626 $986 $(360)
External sources - - -
Models and other
methods - - -
- -----------------------------------------------------------------
Contracts end of year $626 $986 $(360)
=================================================================
Unrealized gains and losses from mark to market adjustments on contracts
related to the retail fuel hedging program are recorded as regulatory assets and
liabilities. Realized gains and losses from this program are included in fuel
expense and are recovered through the Company's fuel cost recovery clause. Gains
and losses on contracts that do not represent hedges are recognized in the
Statements of Income as incurred. At December 31, 2002, the fair value of
derivative energy contracts was reflected in the financial statements as
follows:
Amounts
- --------------------------------------------------------------
(in thousands)
Regulatory liabilities, net $621
Other comprehensive income 0
Net income 5
- --------------------------------------------------------------
Total fair value $626
==============================================================
Approximately $40 thousand and $35 thousand of gains were recognized in
income in 2002 and 2001, respectively. The Company is exposed to market-price
risk in the event of nonperformance by parties to the derivative energy
contracts. The Company's policy is to enter into agreements with counterparties
that have investment grade credit ratings by Moody's and Standard & Poor's or
with counterparties who have posted collateral to cover potential credit
exposure. Therefore, the Company does not anticipate market risk exposure from
nonperformance by the counterparties. For additional information, see Note 1 to
the financial statements under "Financial Instruments."
Capital Structure
As of December 31, 2002, the Company's capital structure consisted of 46.4
percent common stockholder's equity, 10.3 percent trust preferred securities,
and 43.3 percent long-term debt, excluding amounts due within one year.
Maturities and retirements of long-term debt were $53.6 million in 2002,
$50.7 million in 2001, and $0.4 million in 2000.
In September 2002, the Company borrowed $25 million under a $30 million
variable rate revolving credit agreement which terminates in 2005. The proceeds
were used to repay a portion of the Company's short-term indebtedness. In
November 2002, the Company issued $55 million of Series D 5.50% senior notes
maturing in 2017. The Company used the proceeds to redeem all of the remaining
$23.1 million 7.40% Series First Mortgage Bonds due in 2023, to redeem its $30
million Series A 6 5/8% Senior Retail Intermediate Bonds due in 2015, and for
general corporate purposes.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 2002 Annual Report
Subsequent to December 31, 2002, the Company refinanced $13.9 million in
pollution control bonds from a daily variable interest rate to an auction rate
mode.
The composite interest rates and dividend rates for the years 2000 through
2002 as of year-end were as follows:
2002 2001 2000
-------------------------------
Composite interest rates
on long-term debt 5.0% 5.9% 6.6%
Trust preferred securities
dividend rate 6.9% 6.9% 6.9%
- -----------------------------------------------------------------
The composite interest rates on long-term debt decreased from 2000 to 2002
due to lower interest rates on variable rate debt and the refinancing of higher
priced fixed rate debt.
Capital Requirements for Construction
The Company's projected construction expenditures for the next three years total
$136.3 million ($41.5 million in 2003, $50.7 million in 2004, and $44.1 million
in 2005). Actual construction costs may vary from this estimate because of
factors such as changes in: business conditions; environmental regulations; FERC
rules and transmission 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 and upgrading of new and existing
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
$47.5 million will be needed by the end of 2005 for maturities of long-term debt
and present sinking fund requirements.
Capital requirements, lease obligations, and purchase commitments --
discussed in Notes 4 and 6 to the financial statements -- are as follows:
2003 2004 2005
- -----------------------------------------------------------------
(in thousands)
Notes $20,000 $ - $25,000
Leases -
Capital 892 836 774
Operating 858 842 775
Purchase commitments
Fuel 28,326 15,594 314
Purchased power 12,917 12,694 23,882
- ----------------------------------------------------------------
Sources of Capital
As shown in the chart below, at December 31, 2002, the Company had $55 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. The Company also has adequate cash flow from
operating activities and access to the capital markets to meet liquidity needs.
Bank arrangements are as follows:
Expires
------------------------
Total Unused 2003 2005
-----------------------------------------------------------
(in thousands)
$80,000 $55,000 $40,000 $40,000
-----------------------------------------------------------
For additional information, see Note 6 to the financial statements under
"Bank Credit Arrangements".
The Company may also meet short-term cash needs through a Southern Company
subsidiary organized to issue and sell commercial paper and extendible
commercial notes at the request and for the benefit of the Company and the other
Southern Company operating companies. At December 31, 2002, the Company had
outstanding $2.9 million of commercial paper and no outstanding extendible
commercial notes.
The Company's committed credit arrangements provide liquidity support to
the Company's variable rate obligations and to its commercial paper program. At
December 31, 2002, the amount of variable rate obligations outstanding requiring
liquidity support was $25.0 million, which includes the $2.9 million outstanding
commercial paper.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 2002 Annual Report
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 including both internal and
external funds. The external funding came from the issuance of debt and trust
preferred securities. Recently, the Company's debt financings have consisted of
unsecured debt. 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. There are no 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. Authorization for long-term financings is
required by the GPSC. The Company received authority from the GPSC for $115
million of such financings expiring December 31, 2003. Currently, the Company
has $16.0 million available under this authority.
Environmental Matters
New Source Review Enforcement Actions
In November 1999, the Environmental Protection Agency (EPA) brought a civil
action in the U.S. District Court in Georgia against Alabama Power, Georgia
Power, and the system service company. The complaint alleges violations of the
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 operating companies 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 the Company 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 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 U.S. District Court in Georgia granted Alabama Power's motion to
dismiss for lack of jurisdiction in Georgia and granted the system service
company's motion to dismiss on the grounds that it neither owned nor operated
the generating units involved in the proceedings. The court granted the EPA's
motion to add the Company as a defendant, but it denied the motion to add Gulf
Power and Mississippi Power based on lack of jurisdiction over those companies.
As directed by the court, the EPA refiled its amended complaint limiting claims
to those brought against Georgia Power and the Company. Also, the EPA refiled
its claims against Alabama Power in the U.S. District Court in Alabama. It has
not refiled against Gulf Power, Mississippi Power, or the system service
company. The Alabama Power, Georgia Power, and the Company's cases have been
stayed since the spring of 2001, pending a ruling by the U.S. Court of Appeals
for the Eleventh Circuit in the appeal of a very similar New Source Review
enforcement action against the Tennessee Valley Authority (TVA). The TVA appeal
involves many of the same legal issues raised by the actions against Alabama
Power, Georgia Power, and the Company. Because the outcome of the TVA appeal
could have a significant adverse impact on Alabama Power and Georgia Power, both
companies have been parties to that case as well. In February 2003, the U.S.
District Court in Alabama extended the stay of the EPA litigation proceeding in
Alabama until the earlier of May 6, 2003 or a ruling by the U.S. Court of
Appeals for the Eleventh Circuit in the related litigation involving TVA. On
August 21, 2002, the U.S. District Court in Georgia denied the EPA's motion to
reopen the Georgia case. The denial was without prejudice to the EPA to refile
the motion at a later date, which the EPA has not done at this time.
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 in any one of these cases could require
II-223
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 2002 Annual Report
substantial capital expenditures that cannot be determined at this time and
could 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.
Environmental Statutes and Regulations
The Company's operations are subject to extensive regulation by state and
federal environmental agencies under a variety of statutes and regulations
governing environmental media, including air, water, and land resources.
Compliance with these environmental requirements will involve significant costs,
a major portion of which is expected to be recovered through existing ratemaking
provisions. There is no assurance, however, that all such costs will, in fact,
be recovered.
Compliance with the federal Clean Air Act and resulting regulations has been
and will continue to be, a significant focus for the Company. The Title IV acid
rain provisions of the Clean Air Act, for example, required significant
reductions in sulfur dioxide and nitrogen oxide emissions. Compliance was
required in two phases -- Phase I, effective in 1995 and Phase II, effective in
2000. Construction expenditures associated with Phase I compliance totaled
approximately $2 million. Phase II compliance had no significant impact on the
Company.
To help bring the remaining nonattainment areas into compliance with the
one-hour ozone standard, in 1998 the EPA issued regional nitrogen oxide
reduction rules. Those rules required 21 states, including Georgia, to reduce
and cap nitrogen oxide emissions from power plants and other large industrial
sources. However, for Georgia, the EPA must complete a separate rulemaking
before the requirements will apply. The EPA proposed a rule for Georgia in 2002
and expects to issue a final rule in 2003. The proposed rule requires compliance
by May 1, 2005. The Company's additional construction expenditures for
compliance with these new rules are currently estimated at approximately $7
million, most of which remains to be spent.
In July 1997, the EPA revised the national ambient air quality standards for
ozone and particulate matter. These revisions made the standards significantly
more stringent. In the subsequent litigation of these standards, the U.S.
Supreme Court found the EPA's implementation program for the new ozone standard
unlawful and remanded it to the EPA for further rulemaking. The EPA is expected
to propose implementation rules designed to address the court's concerns in 2003
and issue final implementation rules in 2004. The remaining legal challenges to
the new standards, which were pending before the U.S. Court of Appeals, District
of Columbia Circuit, have been resolved.
The EPA plans to designate areas as attainment or nonattainment with the new
eight-hour ozone standard by April 2004, based on air quality data for 2001
through 2003. Although not expected, part or all of the Company's service area
may be designated nonattainment under the new ozone standard. State
implementation plans, including new emission control regulations necessary to
bring those areas into attainment, could be required as early as 2007. Those
state plans could require further reductions in nitrogen oxide emissions from
power plants. If so, reductions could be required sometime after 2007. The
impact of any new standards will depend on the development and implementation of
applicable regulations.
The EPA currently plans to designate areas as attainment or nonattainment
with the new fine particulate matter standard by the end of 2004. Those area
designations will be based on air quality data collected during 2001 through
2003. Part or all of the Company's service area may be designated nonattainment
under the new particulate matter standard. State implementation plans, including
new emission control regulations necessary to bring those areas into attainment,
could be required as early as the end of 2007. Those state plans will likely
require reductions in sulfur dioxide emissions from power plants. If so, the
reductions could be required sometime after 2007. Any additional emission
reductions and costs associated with the new fine particulate matter standard
cannot be determined at this time.
The EPA has also announced plans to issue a proposed Regional Transport Rule
for the fine particulate matter standard by the end of 2003 and to finalize the
rule in 2005. This rule would likely require year-round sulfur dioxide and
nitrogen oxide emission reductions from power plants as early as 2010. If
issued, this rule would likely modify other state implementation plan
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 2002 Annual Report
requirements for attainment of the fine particulate matter standard and the
eight-hour ozone standard. It is not possible at this time to determine the
effect such a rule would have on the Company.
Further reductions in sulfur dioxide could also be required under the EPA's
Regional Haze rules. The Regional Haze rules require states to establish Best
Available Retrofit Technology (BART) standards for certain sources that
contribute to regional haze. The Company has two plants that could be subject to
these rules. The EPA regional haze program calls for states to submit State
Implementation Plans in 2007 and 2008 that contain emission reduction strategies
for achieving progress toward the visibility improvement goal. In 2002, however,
the U.S. Court of Appeals, District of Columbia Circuit, vacated and remanded
the BART provisions of the federal Regional Haze rules to the EPA for further
rulemaking. Because new BART rules have not been developed and state visibility
assessments are only beginning, it is not possible to determine the effect of
these rules on the Company at this time.
The EPA's Compliance Assurance Monitoring (CAM) regulations under Title V of
the Clean Air Act require that monitoring be performed to ensure compliance with
emissions limitations on an ongoing basis. The regulations require certain
facilities with Title V operating permits to develop and submit a CAM plan to
the appropriate permitting authority upon applying for renewal of the facility's
Title V operating permit. The Company is in the process of developing CAM plans,
which could indicate a need for improved particulate matter controls at affected
facilities. Because the plans are still in the early stages of development, the
Company cannot determine the extent to which improved controls could be required
or the costs associated with any necessary improvements. Actual ongoing
monitoring costs are expensed as incurred and are not material for any period
presented.
In December 2000, having completed its utility studies for mercury and other
hazardous air pollutants (HAPS), the EPA issued a determination that an emission
control program for mercury and, perhaps, other HAPS is warranted. The program
is being developed under the Maximum Achievable Control Technology provisions of
the Clean Air Act. The EPA currently plans to issue proposed rules regulating
mercury emissions from electric utility boilers by the end of 2003, and those
regulations are scheduled to be finalized by the end of 2004. Compliance could
be required as early as 2007. Because the rules have not yet been proposed, the
costs associated with compliance cannot be determined at this time.
In December 2002, the EPA issued final and proposed revisions to the New
Source Review program under the Clean Air Act. In February 2003, several
northeastern states petitioned the D.C. Circuit Court for a stay of the final
rules. The proposed rules are open to public comment and may be revised before
being finalized by the EPA. If fully implemented, these proposed and final
regulations could affect the applicability of the New Source Review provisions
to activities at the Company's facilities. In any event, any final regulations
must be adopted by Georgia in order to apply to the Company's facilities. The
effect of these proposed and final rules cannot be determined at this time.
Several major bills to amend the Clean Air Act to impose more stringent
emissions limitations have been proposed. Three of these, the Bush
Administration's Clear Skies Act, the Clean Power Act of 2002, and the Clean Air
Planning Act of 2002 proposed to further limit power plant emissions of sulfur
dioxide, nitrogen oxides, and mercury. The latter two bills also proposed to
limit emissions of carbon dioxide. None of these bills were enacted into law in
the last Congress. Similar bills have been, and are anticipated to be,
introduced this year. The Bush Administration's Clear Skies Act was recently
reintroduced, and President Bush has stated that it will be a high priority for
the Administration. Other bills already introduced include the Climate
Stewardship Act of 2003, which proposes capping greenhouse gas emissions. The
cost impacts of such legislation would depend upon the specific requirements
enacted.
Domestic efforts to limit greenhouse gas emissions have been spurred by
international discussions surrounding the Framework Convention on Climate Change
and specifically the Kyoto Protocol, which proposes international constraints on
the emissions of greenhouse gases. The Bush Administration does not support U.S.
ratification of the Kyoto Protocol or other mandatory carbon dioxide reduction
II-225
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 2002 Annual Report
legislation and has instead announced a new voluntary climate initiative which
seeks an 18 percent reduction by 2012 in the rate of greenhouse gas emissions
relative to the dollar value of the U.S. economy. The Company is involved in a
voluntary electric utility industry sector climate change initiative in
partnership with the government. Because this initiative is still under
development, it is not possible to determine the effect on the Company at this
time.
The Company must comply with other environmental laws and regulations that
cover the handling and disposal of hazardous waste and releases of hazardous
substances. 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 and has recognized in its financial
statements the costs to clean up known sites. The Company may be liable for a
portion or all required cleanup costs for additional sites that may require
environmental remediation. The Company has not incurred any significant cleanup
costs to date.
Under the Clean Water Act, the EPA is developing new rules aimed at reducing
impingement and entrainment of fish and fish larvae at cooling water intake
structures that will require numerous biological studies, and perhaps, retrofits
to some intake structures at existing power plants. The new rule was proposed in
February 2002 and is expected to be finalized by August 2004. The impact of any
new standards will depend on the development and implementation of applicable
regulations.
Also, under the Clean Water Act, the EPA and state environmental regulatory
agencies are developing total maximum daily loads (TMDLs) for certain impaired
waters. Establishment of maximum loads by the EPA or the Georgia Environmental
Protection Division may result in lowering permit limits for various pollutants
and a requirement to take additional measures to control non-point source
pollution (e.g., storm water runoff) at facilities discharging into waters for
which TMDLs are established. Because the effect on the Company will depend on
the actual TMDLs and permit limitations established by the implementing agency,
it is not possible to determine the effect on the Company at this time.
The EPA and the Georgia Environmental Protection Division are reviewing and
evaluating various other matters including limits on pollutant discharges to
impaired waters, hazardous waste disposal requirements, and other regulatory
matters. The impact of any new standards will depend on the development and
implementation of applicable regulations.
Several major pieces of environmental legislation are periodically 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; the Emergency Planning & Community Right-to-Know Act; and the
Endangered Species Act.
Compliance with possible additional federal or state legislation related to
global climate change, electromagnetic fields, and other environmental and
health concerns could also significantly affect the Company. The impact of any
new legislation, or changes to existing legislation, could affect many areas of
the Company's operations. The full impact of any such changes cannot, however,
be determined at this time.
Cautionary Statement Regarding Forward-Looking
Information
This Annual Report includes forward-looking statements in addition to historical
information. In some cases, forward-looking statements can be identified by
terminology such as "may," "will," "should," "could," "expects," "plans,"
"anticipates," "believes," "estimates," "predicts," "projects," "potential" or
"continue" or the negative of these terms or other comparable terminology. The
Company cautions that there are various important factors that could cause
actual results to differ materially from those indicated in the forward-looking
statements; accordingly, there can be no assurance that such indicated results
will be realized. These factors include the impact of recent and future federal
and state regulatory change, including legislative and regulatory initiatives
regarding deregulation and restructuring of the electric utility industry and
also changes in environmental and other laws and regulations to which the
Company is subject, as well as changes in application of existing laws and
II-226
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 2002 Annual Report
regulations; current and future litigation, including the pending EPA civil
actions against the Company; the effects, extent, and timing of the entry of
additional competition in the markets of the Company; the impact of fluctuations
in commodity prices, interest rates, and customer demand; state and federal rate
regulations; political, legal, and economic conditions and developments in the
United States; internal restructuring or other restructuring options that may be
pursued; potential business strategies, including acquisitions or dispositions
of assets or businesses, which cannot be assured to be completed or beneficial;
the ability of counterparties of the Company to make payments as and when due;
the effects of, and changes in, economic conditions in the United States,
including the current soft economy; the direct or indirect effects on the
Company's business resulting from the terrorist incidents on September 11, 2001,
or any similar such incidents or responses to such incidents; financial market
conditions and the results of financing efforts; the ability of the Company to
obtain additional generating capacity at competitive prices; weather and other
natural phenomena; and other factors discussed elsewhere herein and in other
reports (including the Form 10-K) filed from time to time by the Company with
the Securities and Exchange Commission.
II-227
STATEMENTS OF INCOME
For the Years Ended December 31, 2002, 2001, and 2000
Savannah Electric and Power Company 2002 Annual Report
- ---------------------------------------------------------------------------------------------------------------------------------
2002 2001 2000
- ----------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Revenues:
Retail sales $285,771 $269,172 $282,622
Sales for resale --
Non-affiliates 6,354 8,884 4,748
Affiliates 4,075 3,205 4,974
Other revenues 3,352 2,591 3,374
- ----------------------------------------------------------------------------------------------------------------------------------
Total operating revenues 299,552 283,852 295,718
- ----------------------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
Fuel 54,955 50,796 57,177
Purchased power --
Non-affiliates 6,368 23,147 25,229
Affiliates 69,236 49,939 50,111
Other 55,756 50,607 53,086
Maintenance 25,262 19,886 19,334
Depreciation and amortization 22,704 25,951 25,240
Taxes other than income taxes 14,457 13,984 13,116
- ----------------------------------------------------------------------------------------------------------------------------------
Total operating expenses 248,738 234,310 243,293
- ----------------------------------------------------------------------------------------------------------------------------------
Operating Income 50,814 49,542 52,425
Other Income and (Expense):
Interest income 147 173 252
Interest expense, net of amounts capitalized (11,608) (12,517) (12,737)
Distributions on preferred securities of subsidiary (2,740) (2,740) (2,740)
Other income (expense), net (1,300) (686) (657)
- ----------------------------------------------------------------------------------------------------------------------------------
Total other income and (expense) (15,501) (15,770) (15,882)
- ----------------------------------------------------------------------------------------------------------------------------------
Earnings Before Income Taxes 35,313 33,772 36,543
Income taxes 12,433 11,731 13,574
- ----------------------------------------------------------------------------------------------------------------------------------
Earnings Before Cumulative Effect of
Accounting Change 22,880 22,041 22,969
Cumulative effect of accounting change--
less income taxes of $14 - 22 -
- ----------------------------------------------------------------------------------------------------------------------------------
Net Income $ 22,880 $ 22,063 $ 22,969
==================================================================================================================================
The accompanying notes are an integral part of these financial statements.
II-228
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2002, 2001, and 2000
Savannah Electric and Power Company 2002 Annual Report
- ------------------------------------------------------------------------------------------------------------------------------
2002 2001 2000
- ------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Activities:
Net income $ 22,880 $ 22,063 $ 22,969
Adjustments to reconcile net income
to net cash provided from operating activities --
Depreciation and amortization 24,653 27,895 26,639
Deferred income taxes and investment tax credits, net (6,227) (20,528) 728
Pension, postretirement, and other employee benefits 6,133 6,282 3,975
Other, net (10,559) (2,198) (140)
Changes in certain current assets and liabilities --
Receivables, net 7,965 24,079 (23,260)
Fossil fuel stock 1,522 (2,711) (31)
Materials and supplies 3,383 (4,025) (542)
Other current assets (5,470) 8,587 (6,159)
Accounts payable 7,527 (8,439) 8,881
Taxes accrued (627) 2,820 (2,454)
Other current liabilities 6,002 1,224 3,939
- ------------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities 57,182 55,049 34,545
- ------------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (32,481) (31,296) (27,290)
Other (1,331) (1,875) (1,835)
- ------------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities (33,812) (33,171) (29,125)
- ------------------------------------------------------------------------------------------------------------------------------
Financing Activities:
Increase (decrease) in notes payable, net (29,263) (13,241) 11,100
Proceeds --
Senior notes 55,000 65,000 -
Other long-term debt 25,616 - -
Capital contributions from parent company 3,950 1,561 1,478
Redemptions --
First mortgage bonds (23,558) (20,642) -
Senior notes (30,000) - -
Other long-term debt - (30,071) (251)
Payment of common stock dividends (22,700) (21,700) (24,300)
Other (828) (394) -
- ------------------------------------------------------------------------------------------------------------------------------
Net cash used for financing activities (21,783) (19,487) (11,973)
- ------------------------------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents 1,587 2,391 (6,553)
Cash and Cash Equivalents at Beginning of Period 2,391 - 6,553
- ------------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ 3,978 $ 2,391 $ -
==============================================================================================================================
Supplemental Cash Flow Information:
Cash paid during the period for --
Interest (net of $165, $271, and $324 capitalized for 2002,
2001, and 2000, respectively $13,353 $15,340 $13,329
Income taxes (net of refunds) $20,979 $21,034 $19,939
- ------------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
II-229
BALANCE SHEETS
At December 31, 2002 and 2001
Savannah Electric and Power Company 2002 Annual Report
- --------------------------------------------------------------------------------------------------------------------------
Assets 2002 2001
- --------------------------------------------------------------------------------------------------------------------------
(in thousands)
Current Assets:
Cash and cash equivalents $ 3,978 $ 2,391
Receivables --
Customer accounts receivable 22,631 21,514
Unbilled revenues 11,531 8,445
Under recovered regulatory clause revenues - 11,974
Other accounts and notes receivable 2,937 2,882
Affiliated companies 1,102 1,170
Accumulated provision for uncollectible accounts (682) (500)
Fossil fuel stock, at average cost 8,328 9,851
Materials and supplies, at average cost 9,586 12,969
Prepaid taxes 20,422 12,511
Other 6,058 586
- --------------------------------------------------------------------------------------------------------------------------
Total current assets 85,891 83,793
- --------------------------------------------------------------------------------------------------------------------------
Property, Plant, and Equipment:
In service 880,604 855,290
Less accumulated provision for depreciation 416,232 402,492
- --------------------------------------------------------------------------------------------------------------------------
464,372 452,798
Construction work in progress 6,082 8,540
- --------------------------------------------------------------------------------------------------------------------------
Total property, plant, and equipment 470,454 461,338
- --------------------------------------------------------------------------------------------------------------------------
Other Property and Investments 3,648 2,742
- --------------------------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets:
Deferred charges related to income taxes 11,692 12,283
Cash surrender value of life insurance for deferred compensation plans 21,943 20,002
Unamortized debt issuance expense 3,757 3,197
Unamortized premium on reacquired debt 8,103 6,890
Other 11,717 4,498
- --------------------------------------------------------------------------------------------------------------------------
Total deferred charges and other assets 57,212 46,870
- --------------------------------------------------------------------------------------------------------------------------
Total Assets $617,205 $594,743
==========================================================================================================================
The accompanying notes are an integral part of these financial statements.
II-230
BALANCE SHEETS
At December 31, 2002 and 2001
Savannah Electric and Power Company 2002 Annual Report
- ------------------------------------------------------------------------------------------------------------------------
Liabilities and Stockholder's Equity 2002 2001
- ------------------------------------------------------------------------------------------------------------------------
(in thousands)
Current Liabilities:
Securities due within one year $ 20,892 $ 1,178
Notes payable 2,897 32,159
Accounts payable --
Affiliated 7,889 5,087
Other 15,769 10,160
Customer deposits 6,781 6,237
Taxes accrued --
Income taxes 311 2,587
Other 3,317 1,668
Interest accrued 3,268 4,014
Vacation pay accrued 2,427 2,361
Other 15,233 9,097
- ------------------------------------------------------------------------------------------------------------------------
Total current liabilities 78,784 74,548
- ------------------------------------------------------------------------------------------------------------------------
Long-term debt (See accompanying statements) 168,052 160,709
- ------------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 78,970 77,331
Deferred credits related to income taxes 12,445 13,776
Accumulated deferred investment tax credits 9,289 9,952
Employee benefits provisions 33,619 27,486
Other 16,242 14,023
- ------------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 150,565 142,568
- ------------------------------------------------------------------------------------------------------------------------
Company obligated mandatorily redeemable preferred
securities of subsidiary trusts holding company junior
subordinated notes (See accompanying statements) 40,000 40,000
- ------------------------------------------------------------------------------------------------------------------------
Common stockholder's equity (See accompanying statements) 179,804 176,918
- ------------------------------------------------------------------------------------------------------------------------
Total Liabilities and Stockholder's Equity $617,205 $594,743
========================================================================================================================
Commitments and Contingent Matters (See notes)
- ------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
II-231
STATEMENTS OF CAPITALIZATION
At December 31, 2002 and 2001
Savannah Electric and Power Company 2002 Annual Report
- ------------------------------------------------------------------------------------------------------------------------------
2002 2001 2002 2001
- ------------------------------------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
Long-Term Debt:
First mortgage bonds --
Maturity Interest Rates
-------- --------------
May 1, 2006 6.90% $ 20,000 $ 20,000
July 1, 2023 7.40% - 23,558
- ------------------------------------------------------------------------------------------------------------------------------
Total first mortgage bonds 20,000 43,558
- ------------------------------------------------------------------------------------------------------------------------------
Long-term notes payable --
5.12% due May 15, 2003 20,000 20,000
6.55% due May 15, 2008 45,000 45,000
5.50% to 6.625% due 2015 through 2017 55,000 30,000
Adjustable rates (2.12% at 1/1/03)
due September 6, 2005 25,000 -
- ------------------------------------------------------------------------------------------------------------------------------
Total long-term notes payable 145,000 95,000
- ------------------------------------------------------------------------------------------------------------------------------
Other long-term debt --
Pollution control revenue bonds --
Non-collateralized:
Variable rates (1.80 at 1/1/03)
due 2016-2037 17,955 17,955
- ------------------------------------------------------------------------------------------------------------------------------
Total other long-term debt 17,955 17,955
- ------------------------------------------------------------------------------------------------------------------------------
Capitalized lease obligations 5,989 5,374
- ------------------------------------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
requirement -- $9.4 million) 188,944 161,887
Less amount due within one year 20,892 1,178
- ------------------------------------------------------------------------------------------------------------------------------
Long-term debt excluding amount due within one year 168,052 160,709 43.3% 42.6%
- ------------------------------------------------------------------------------------------------------------------------------
Company Obligated Mandatorily
Redeemable Preferred Securities:
$25 liquidation value --
6.85% 40,000 40,000
- ------------------------------------------------------------------------------------------------------------------------------
Total (annual distribution requirement -- $2.7 million) 40,000 40,000 10.3 10.6
- ------------------------------------------------------------------------------------------------------------------------------
Common Stockholder's Equity:
Common stock, par value $5 per share --
Authorized - 16,000,000 shares
Outstanding - 10,844,635 shares in 2002 and 2001
Par value 54,223 54,223
Paid-in capital 16,776 12,826
Retained earnings 110,049 109,869
Accumulated other comprehensive income (loss) (1,244) -
- ------------------------------------------------------------------------------------------------------------------------------
Total common stockholder's equity 179,804 176,918 46.4 46.8
- ------------------------------------------------------------------------------------------------------------------------------
Total Capitalization $387,856 $377,627 100.0% 100.0%
==============================================================================================================================
The accompanying notes are an integral part of these financial statements.
II-232
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
For the Years Ended December 31, 2002, 2001, and 2000
Savannah Electric and Power Company 2002 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------------
Other
Common Paid-In Retained Comprehensive
Stock Capital Earnings Income (loss) Total
- -----------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Balance at December 31, 1999 $54,223 $ 9,787 $110,837 $ - $174,847
Net income - - 22,969 - 22,969
Capital contributions from parent company - 1,478 - - 1,478
Cash dividends on common stock - - (24,300) - (24,300)
- -----------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2000 54,223 11,265 109,506 - 174,994
Net income - - 22,063 - 22,063
Capital contributions from parent company - 1,561 - - 1,561
Cash dividends on common stock - - (21,700) - (21,700)
- -----------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2001 54,223 12,826 109,869 - 176,918
Net income - - 22,880 - 22,880
Capital contributions from parent company - 3,950 - - 3,950
Other comprehensive income (loss) - - - (1,244) (1,244)
Cash dividends on common stock - - (22,700) - (22,700)
- -----------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2002 $54,223 $16,776 $110,049 $(1,244) $179,804
===================================================================================================================================
The accompanying notes are an integral part of these financial statements.
STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2002, 2001, and 2000
Savannah Electric and Power Company 2002 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------------
2002 2001 2000
- -----------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Net income $22,880 $22,063 $22,969
- -----------------------------------------------------------------------------------------------------------------------------------
Other comprehensive income (loss):
Change in additional minimum pension liability, net of tax of $(785) (1,244) - -
- -----------------------------------------------------------------------------------------------------------------------------------
Total other comprehensive income (loss) (1,244) - -
- -----------------------------------------------------------------------------------------------------------------------------------
Comprehensive Income $21,636 $22,063 $22,969
===================================================================================================================================
The accompanying notes are an integral part of these financial statements.
II-233
NOTES TO FINANCIAL STATEMENTS
Savannah Electric and Power Company 2002 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING
POLICIES
General
Savannah Electric and Power Company (the Company) is a wholly owned subsidiary
of Southern Company, which is the parent company of five operating companies,
Southern Power Company (Southern Power), a system service company, Southern
Communications Services (Southern LINC), Southern Company Gas (Southern GAS),
Southern Company Holdings (Southern Holdings), Southern Nuclear Operating
Company (Southern Nuclear), Southern Telecom, and other direct and indirect
subsidiaries. The operating companies provide electric service in four
southeastern states. Southern Power was established in 2001 to construct, own,
and manage Southern Company's competitive generation assets and sell electricity
at market-based rates in the wholesale market. Contracts among the operating
companies and Southern Power--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. 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 Telecom provides fiber cable services within the Southeast. Southern
GAS, which began operation in August 2002, is a competitive retail natural gas
marketer serving communities in Georgia. Southern Holdings is an intermediate
holding subsidiary for Southern Company's investments in leveraged leases,
alternative fuel products, and an energy services business. Southern Nuclear
provides services to Southern Company's nuclear power plants.
Southern Company is registered as a holding company under the Public
Utility Holding Company Act of 1935 (PUHCA). Both Southern Company and its
subsidiaries are subject to the regulatory provisions of the PUHCA. The Company
also is subject to regulation by the FERC and the Georgia Public Service
Commission (GPSC). The Company follows accounting principles generally accepted
in the United States and complies with the accounting policies and practices
prescribed by the GPSC. The preparation of financial statements in conformity
with accounting principles generally accepted in the United States 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.
Affiliate Transactions
The Company has an agreement with the system service company under which the
following services are rendered to the Company at direct or allocated cost:
general and design engineering, purchasing, accounting and statistical analysis,
finance and treasury, tax, information resources, marketing, auditing, insurance
and employee benefits, human resources, systems and procedures, and other
administrative services with respect to business and operations and power pool
operations. Costs for these services amounted to $15.6 million, $15.0 million,
and $15.1 million during 2002, 2001, and 2000, respectively. Cost allocation
methodologies used by the system service company are approved by the SEC and
management believes they are reasonable.
The Company has entered into a purchased power agreement with Southern
Power for 200 megawatts of capacity from Plant Wansley Units 6 and 7 which began
operation in June 2002. Purchased power costs in 2002 amounted to $23.2 million.
At December 31, 2002, approximately $1.5 million in prepaid capacity expense
related to this agreement was recorded in other deferred debits in the balance
sheet.
In June 2002, the Company entered into another purchased power agreement
`with Southern Power for 200 megawatts of capacity from a planned combined-cycle
plant at Plant McIntosh to be built and owned by Southern Power. This agreement
will be effective in June 2005 and the annual capacity cost is expected to be
approximately $15.0 million through June 2020. See Note 4 under "Fuel and
Purchased Power Commitments" for additional information.
The Company operates an eight-unit combustion turbine site at its Plant
McIntosh. Two of the units are owned by the Company, and six of the units are
owned by Georgia Power. Georgia Power reimburses the Company for its
proportionate share of the related expenses, which were $1.8 million in 2002.
II-234
NOTES (continued)
Savannah Electric and Power Company 2002 Annual Report
The operating companies, including the Company, Southern Power, and
Southern GAS may jointly enter into various types of wholesale energy, natural
gas and certain other contracts, either directly or through the system service
company as agent. Each participating company may be jointly and severally liable
for the obligations incurred under these agreements.
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 could be credited to
customers through the ratemaking process. Regulatory assets and (liabilities)
reflected in the Balance Sheets at December 31 relate to:
2002 2001
--------------------------
(in thousands)
Deferred income tax charges $11,692 $ 12,283
Premium on reacquired debt 8,103 6,890
Deferred McIntosh
maintenance costs 5,790 53
Fuel-hedging assets - 1,018
Fuel-hedging liabilities (621) -
Deferred income tax credits (12,445) (13,776)
Storm damage reserves (5,603) (4,228)
Accelerated cost recovery (7,282) (8,000)
- ---------------------------------------------------------------
Total $ (366) $ (5,760)
===============================================================
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 including plant
exists, and write down the assets, if impaired, to their fair value. All
regulatory assets and liabilities are reflected in rates.
See "Depreciation and Amortization" in this Note for information regarding
significant regulatory assets and liabilities created as a result of the January
1, 2003 adoption of FASB Statement No. 143, Accounting for Asset Retirement
Obligations.
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 recognized as services are rendered. Unbilled revenues are
accrued 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, fuel hedging, 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.
Depreciation and Amortization
Depreciation of the original cost of plant in service is provided primarily by
using composite straight-line rates, which approximated 2.9 percent in 2002 and
3.0 percent in both 2001 and 2000. 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. In accordance with regulatory requirements, prior
to the implementation of FASB Statement No. 143 in January 2003, the Company
followed the industry practice of accruing for the ultimate cost of retiring
most long-lived assets over the life of the related asset as part of the annual
depreciation expense provision. In 2002, 2001, and 2000, the Company recorded
accelerated depreciation of $1.0 million, $2.5 million, and $2.5 million,
respectively, in accordance with the GPSC's 1998 accounting order. In the 2002
base rate order, the GPSC ordered the Company to amortize the balance of
accelerated depreciation as a credit to depreciation expense over a three year
period beginning June 2002. See Note 3 under "Retail Regulatory Matters" for
more information.
II-235
NOTES (continued)
Savannah Electric and Power Company 2002 Annual Report
In January 2003, the Company adopted FASB Statement No. 143, Accounting
for Asset Retirement Obligations. Statement No. 143 establishes new accounting
and reporting standards for legal obligations associated with the ultimate cost
of retiring long-lived assets. The present value of the ultimate costs for an
asset's future retirement must be recorded in the period in which the liability
is incurred. The cost must be capitalized as part of the related long-lived
asset and depreciated over the asset's useful life.
The cumulative effect adjustment to net income resulting from the adoption of
Statement No. 143 was immaterial. The Company expects to receive an accounting
order from the GPSC to defer the transition adjustment; therefore, the Company
recorded a related regulatory asset of $2.4 million to reflect the Company's
regulatory treatment of these costs under Statement No. 71. The initial
Statement No. 143 liability the Company recognized was $3.2 million, of which
$0.2 million was added to the accumulated depreciation reserve. The amount
capitalized to property, plant, and equipment was $1.0 million.
The Company has retirement obligations related to various landfill sites, ash
ponds, a rail line, and underground storage tanks. The Company has also
identified retirement obligations related to certain transmission and
distribution facilities. However, a liability for the removal of these
transmission and distribution assets will not be recorded because no reasonable
estimate can be made regarding the timing of any related retirements. The
Company will continue to recognize in the income statement its ultimate removal
costs in accordance with its regulatory treatment. Any difference between costs
recognized under Statement No. 143 and those reflected in rates will be
recognized as either a regulatory asset or liability. It is estimated that this
annual difference will be approximately $0.2 million. Management believes that
actual asset removal costs will be recoverable in rates over time.
Statement No. 143 does not permit non-regulated companies to continue
accruing future retirement costs for long-lived assets they do not have a legal
obligation to retire. However, in accordance with the regulatory treatment of
these costs, the Company will continue to recognize the removal costs for these
other obligations in its depreciation rates. As of January 1, 2003, the amount
included in the accumulated depreciation reserve that represents a regulatory
liability for these costs was $31.9 million.
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. Federal 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 2.82 percent in 2002, 5.13 percent in 2001, and 6.87 percent in 2000. AFUDC
as a percent of net income was 0.4 percent in 2002, 0.8 percent in 2001, and 0.9
percent in 2000.
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 AFUDC. The cost of
maintenance, repairs, and replacement of minor items of property is charged to
maintenance expense. The cost of replacements of property exclusive of minor
items of property is capitalized. In accordance with the 2002 base rate order,
the Company is deferring the costs of certain significant maintenance costs for
the combustion turbines at Plant McIntosh and amortizing such costs over 10
years, which approximates the expected maintenance cycle.
Impairment of Long-Lived Assets and Intangibles
The Company evaluates long-lived assets for impairment 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
either a specific regulatory disallowance or an estimate of undiscounted future
II-236
NOTES (continued)
Savannah Electric and Power Company 2002 Annual Report
cash flows attributable to the assets, as compared with 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
the 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 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.
Stock Options
Southern Company provides non-qualified stock options to a large segment of the
Company's employees ranging from line management to executives. The Company
accounts for its stock-based compensation plans in accordance with Accounting
Principles Board Opinion No. 25. Accordingly, no compensation expense has been
recognized because the exercise price of all options granted equaled the
fair-market value on the date of grant. When options are exercised the Company
receives a capital contribution from Southern Company equivalent to the related
income tax benefit.
Comprehensive Income
Comprehensive income - consisting of net income and changes in additional
minimum pension liability, net of income taxes - is presented in the Company's
financial statements. The objective of comprehensive income is to report a
measure of all changes in common stock equity of an enterprise that result from
transactions and other economic events of the period other than transactions
with owners.
Financial Instruments
The Company uses derivative financial instruments to limit exposure to
fluctuations in the prices of certain fuel purchases and electricity purchases
and sales. All derivative financial instruments are recognized as either assets
or liabilities and are measured at fair value. Substantially all of the
Company's bulk energy purchases and sales contracts are derivatives. However, in
many cases, these contracts qualify as normal purchases and sales and are
accounted for under the accrual method. Other contracts qualify as cash flow
hedges of anticipated transactions. This results in the deferral of related
gains and losses in other comprehensive income or regulatory assets or
liabilities as appropriate until the hedged transactions occur. Any
ineffectiveness is recognized currently in net income. Contracts that do not
qualify for the normal purchase and sale exception and that do not meet the
hedge requirements are marked to market through current period income.
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.
On June 1, 2001, the Company implemented a natural gas/oil hedging program
which was ordered by the GPSC as part of the fuel cost recovery increase filing.
The program has negative financial hedge limits. In terms of dollar amounts,
negative financial hedging positions, recoverable through the fuel clause, are
limited to an above market cap equal to 10 percent of the Company's annual
natural gas/oil budget. These hedging position limits were $1.5 million for
2001, $2.4 million for 2002 and will be $1.1 million for 2003. The program has
operated within the defined hedging position limits set for each year.
II-237
NOTES (continued)
Savannah Electric and Power Company 2002 Annual Report
The Company's other 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, 2002 $183 $187
At December 31, 2001 $157 $157
Trust preferred securities:
At December 31, 2002 $40 $40
At December 31, 2001 $40 $38
The fair values for long-term debt and trust preferred securities were
based on either closing market prices or closing prices of comparable
instruments.
2. RETIREMENT BENEFITS
The Company has defined benefit, trusteed, non-contributory pension plans that
cover substantially all employees. The Company also provides certain
non-qualified benefit plans for a select group of management and highly
compensated employees. Also, the Company provides certain medical care and life
insurance benefits for retired employees. The Company funds trusts to the extent
required by the GPSC and the FERC. In late 2000, as well as in 2002, the Company
adopted several pension and postretirement benefit plan changes that had the
effect of increasing benefits to both current and future retirees.
Plan assets consist primarily of domestic and international equities, global
fixed income securities, real estate, and private equity investments. 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
-------------------------
2002 2001
- -------------------------------------------------------------
(in thousands)
Balance at beginning of year $79,550 $71,521
Service cost 2,204 2,074
Interest cost 5,811 5,426
Benefits paid (4,213) (3,986)
Actuarial loss and
employee transfers 1,793 894
Amendments 117 3,621
- -------------------------------------------------------------
Balance at end of year $85,262 $79,550
=============================================================
Plan Assets
-------------------------
2002 2001
- -------------------------------------------------------------
(in thousands)
Balance at beginning of year $50,858 $61,880
Actual return on plan assets (2,720) (8,911)
Benefits paid (3,734) (3,570)
Employee transfers (312) 1,459
- -------------------------------------------------------------
Balance at end of year $44,092 $50,858
=============================================================
The accrued pension costs recognized in the Balance Sheets
were as follows:
2002 2001
- -------------------------------------------------------------
(in thousands)
Funded status $(41,170) $(28,692)
Unrecognized prior service
cost 6,847 7,401
Unrecognized net loss (gain) 21,432 12,336
- -------------------------------------------------------------
Accrued liability recognized
in the Balance Sheets $(12,891) $ (8,955)
=============================================================
In 2002 and 2001, amounts recognized in the balance sheets for accumulated
other comprehensive income and intangible assets were $2.0 million and $1.5
million and $0 and $1.6 million, respectively.
II-238
NOTES (continued)
Savannah Electric and Power Company 2002 Annual Report
Components of the pension plan's net periodic cost were as follows:
2002 2001 2000
- ---------------------------------------------------------------
(in thousands)
Service cost $2,204 $2,074 $1,844
Interest cost 5,811 5,426 4,854
Expected return on plan
assets (4,311) (4,215) (4,174)
Recognized net loss 54 16 -
Net amortization 672 700 503
- ---------------------------------------------------------------
Net pension cost $4,430 $4,001 $3,027
===============================================================
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
--------------------------
2002 2001
- --------------------------------------------------------------
(in thousands)
Balance at beginning of year $28,121 $26,124
Service cost 431 433
Interest cost 2,065 2,022
Benefits paid (1,160) (987)
Actuarial loss (gain) and
employee transfers 3,245 (1,214)
Amendments - 1,743
- --------------------------------------------------------------
Balance at end of year $32,702 $28,121
==============================================================
Plan Assets
------------------------
2002 2001
- ------------------------------------------------------------
(in thousands)
Balance at beginning of year $7,401 $6,910
Actual return on plan assets (732) (789)
Employer contributions 2,485 2,267
Benefits paid (1,160) (987)
- ------------------------------------------------------------
Balance at end of year $7,994 $7,401
============================================================
The accrued postretirement costs recognized in the Balance
Sheets were as follows:
2002 2001
- ------------------------------------------------------------
(in thousands)
Funded status $(24,708) $(20,720)
Unrecognized transition
obligation 4,938 5,431
Unamortized prior service cost 4,429 4,691
Unrecognized net loss 6,435 1,831
Fourth quarter contributions 2,104 1,577
- ------------------------------------------------------------
Accrued liability recognized in
the Balance Sheets $ 6,802) $ (7,190)
============================================================
Components of the postretirement plan's net periodic cost
were as follows:
2002 2001 2000
- ---------------------------------------------------------------
(in thousands)
Service cost $ 431 $ 433 $ 376
Interest cost 2,065 2,022 1,865
Expected return on plan assets (627) (555) (429)
Recognized net loss - - 66
Net amortization 756 731 618
- ---------------------------------------------------------------
Net postretirement cost $2,625 $2,631 $2,496
===============================================================
The weighted average rates assumed in the actuarial calculations
for both the pension plan and postretirement benefits plan were:
2002 2001 2000
- --------------------------------------------------------------
Discount 6.50% 7.50% 7.50%
Annual salary increase 4.00 5.00 5.00
Long-term return on plan assets 8.50 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 8.75
percent for 2002, decreasing gradually to 5.25 percent through the year 2010,
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,
2002 as follows:
1 Percent 1 Percent
Increase Decrease
- ---------------------------------------------------------------
(in thousands)
Benefit obligation $2,138 $1,935
Service and interest costs 168 166
===============================================================
II-239
NOTES (continued)
Savannah Electric and Power Company 2002 Annual Report
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.
Employee Savings Plan
The Company also sponsors a 401(k) defined contribution plan covering
substantially all employees. The Company provides a 75 percent matching
contribution up to 6 percent of an employee's base salary. Total matching
contributions made to the plan for the years 2002, 2001, and 2000 were $1.0
million, $1.0 million, and $0.9 million, respectively.
3. CONTINGENCIES AND REGULATORY
MATTERS
General Litigation Matters
The Company is subject to certain claims and legal actions arising in the
ordinary course of business. The Company's business activities are also subject
to extensive governmental regulation related to public health and the
environment. Litigation over environmental issues and claims of various types,
including property damage, personal injury, and citizen enforcement of
environmental requirements, has increased generally throughout the United
States. In particular, personal injury claims for damages caused by alleged
exposure to hazardous materials have become more frequent.
The ultimate outcome of such litigation currently filed against the Company
cannot be predicted at this time; however, after consultation with legal
counsel, management does not anticipate that the liabilities, if any, arising
from such proceedings would have a material adverse effect on the Company's
financial statements.
Environmental Protection Agency Litigation
In November 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 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 operating companies a notice of violation
related to 10 generating facilities, which include 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 the Company 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 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 U.S. District Court in Georgia granted Alabama Power's motion to
dismiss for lack of jurisdiction in Georgia and granted the system service
company's motion to dismiss on the grounds that it neither owned nor operated
the generating units involved in the proceedings. The court granted the EPA's
motion to add the Company as a defendant, but it denied the motion to add Gulf
Power and Mississippi Power based on lack of jurisdiction over those companies.
As directed by the court, the EPA refiled its amended complaint limiting claims
to those brought against Georgia Power and the Company. Also, the EPA refiled
its claims against Alabama Power in the U.S. District Court in Alabama. It has
not refiled its claims against Gulf Power, Mississippi Power, or the system
service company.
The Alabama Power, Georgia Power, and the Company's cases have been stayed
since the spring of 2001, pending a ruling by the U.S. Court of Appeals for the
Eleventh Circuit in the appeal of a very similar New Source Review enforcement
action against the Tennessee Valley Authority (TVA). The TVA appeal involves
many of the same legal issues raised by the actions against Alabama Power,
Georgia Power, and the Company. Because the outcome of the TVA appeal could have
II-240
NOTES (continued)
Savannah Electric and Power Company 2002 Annual Report
a significant adverse impact on Alabama Power and Georgia Power, both companies
have been parties to that case as well. In February 2003, the U.S. District
Court in Alabama extended the stay of the EPA litigation proceeding in Alabama
until the earlier of May 6, 2003 or a ruling by the U.S. Court of Appeals for
the Eleventh Circuit in the related litigation involving TVA. On August 21,
2002, the U.S. District Court in Georgia denied the EPA's motion to reopen the
Georgia case. The denial was without prejudice to the EPA to refile the motion
at a later date, which the EPA has not done at this time.
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 if such costs are not recovered through
regulated rates.
Right of Way Litigation
In 2002, certain subsidiaries of Southern Company, including Georgia Power, Gulf
Power, Mississippi Power, the Company, and Southern Telecom (collectively,
defendants), were named as defendants in numerous lawsuits brought by landowners
regarding the installation and use of fiber optic cable over defendants' rights
of way located on the landowners' property. The plaintiffs' lawsuits claim that
defendants may not use or sublease to third parties some or all of the fiber
optic communications lines on the rights of way that cross the plaintiffs'
properties and that such actions by defendants exceed the easements or other
property rights held by defendants. The plaintiffs assert claims for, among
other things, trespass and unjust enrichment. The plaintiffs seek compensatory
and punitive damages and injunctive relief. Defendants believe that the
plaintiffs' claims are without merit. An adverse outcome in these matters could
result in substantial judgments; however, the final outcome of these matters
cannot now be determined.
Retail Regulatory Matters
The Company filed a base rate case in November 2001 to recover significant new
expenses related to the 200 megawatt Plant Wansley purchased power agreement
which began in June 2002, as well as other operation and maintenance expense
changes. In early 2002, the Company filed for a fuel cost recovery decrease. In
May 2002, the GPSC approved a $7.8 million base rate increase and an authorized
return on equity of 12.0 percent rather than the $24.4 million and 13.5 percent
return on equity which were requested. At the same time, the GPSC also approved
a $44.3 million fuel cost recovery reduction. As a result of these two rate
changes, all customers saw a net rate decrease effective June 2002. In August
2002, the GPSC denied the Company's request for reconsideration in this matter
and in November 2002, the Company filed a request for an accounting order to
defer approximately $3.8 million annually in Plant Wansley purchased power
costs, which the GPSC had ruled to be outside of the test period in the
Company's 2002 base rate order. On December 17, 2002, an accounting order was
approved by the GPSC, authorizing the Company to defer the $3.8 million in
Wansley purchased power costs until May 2005. Under the terms of the order,
two-thirds of any earnings of the Company in a calendar year above a 12 percent
return on common equity will be used to amortize the deferred amounts to
purchase power expense. The remaining one-third of any such earnings will be
retained by the Company. In January 2003, the Company began deferring the costs
under the terms of the accounting order.
Prior to the 2002 base rate order, the Company had been operating under a
four-year accounting order approved by the GPSC. Under this order, the Company
reduced the electric rates of its small business customers by approximately $11
million over four years. The Company also expensed an additional $1.95 million
in storm damage accruals and accrued an additional $8 million in depreciation on
generating assets over the term of the order. The additional depreciation
accumulated in a regulatory liability account. In addition, the Company had
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. Total storm damages accrued under the order were
$0.5 million in 2002 and $1.5 million per year in both 2001 and 2000. As part of
the order, the Company was precluded from asking for a rate increase except upon
significant changes in economic conditions, new laws, or regulations for the
four-year term.
11-241
NOTES (continued)
Savannah Electric and Power Company 2002 Annual Report
4. COMMITMENTS
Construction Program
The Company is engaged in a continuous construction program, currently estimated
to total $41.5 million in 2003, $50.7 million in 2004, and $44.1 million in
2005. 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; acquisition of
additional generating assets; revised load growth estimates; changes in
environmental regulations; FERC rules and transmission regulations; increasing
costs of labor, equipment, and materials; and cost of capital. The Company does
not have any traditional baseload generating plants under construction. However,
construction related to new and upgrading of existing transmission and
distribution facilities and the upgrading of generating plants will continue. At
December 31, 2002, significant purchase commitments were outstanding in
connection with the construction program.
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 had fuel
commitments at December 31, 2002 as follows:
Year Commitments
- ---- ----------------
(in thousands)
2003 $28,326
2004 15,594
2005 314
2006 314
2007 314
2008 and thereafter 5,334
- ---------------------------------------------------------------
Total commitments $50,196
===============================================================
In addition, the system service company acts as agent for the Company and
the other operating companies and Southern Power with regard to natural gas
purchases. Natural gas purchases (in dollars) are based on various indices at
the actual time of delivery; therefore, only the volume commitments are firm.
The Company's committed volumes allocated based on usage projections as of
December 31, 2002 were as follows:
Year Natural Gas
- ---- --------------
(MMBtu)
2003 2,140,514
2004 1,282,989
2005 1,158,037
2006 883,956
2007 313,819
2008 and thereafter -
- --------------------------------------------------------------
Total commitments 5,779,315
==============================================================
Additional commitments for fuel will be required to supply the Company's
future needs.
Acting as an agent for all of Southern Company's operating companies,
Southern Power, and Southern GAS, the system service company may enter into
various types of wholesale energy and natural gas contracts. Each of the
operating companies, Southern Power, and Southern GAS may be jointly and
severally liable under these agreements. The creditworthiness of Southern Power
and Southern GAS is currently inferior to the creditworthiness of the operating
companies. Accordingly, Southern Company has entered into keep-well agreements
with each of the operating companies to insure they will not subsidize or be
responsible for any costs, losses, liabilities, or damages resulting from the
inclusion of Southern Power or Southern GAS as a contracting party under these
agreements.
The Company has entered into two long-term commitments for the purchase of
electricity from Southern Power. Estimated total long-term obligations at
December 31, 2002 were as follows:
Year Commitments
- ---- ----------------
(in thousands)
2003 $12,917
2004 12,694
2005 23,882
2006 26,741
2007 26,722
2008 and thereafter 197,438
- ---------------------------------------------------------------
Total commitments $300,394
===============================================================
II-242
NOTES (continued)
Savannah Electric and Power Company 2002 Annual Report
Operating Leases
The Company has rental agreements with various terms and expiration dates.
Rental expenses totaled $0.6 million for 2002, $0.4 million for 2001, and $0.4
million for 2000. Of these amounts, $0.5 million in 2002 and $0.4 million in
both 2001 and 2000 related to railcar leases and coal dozers and were
recoverable through the Company's fuel cost recovery clause.
At December 31, 2002, estimated future minimum lease payments for
noncancelable operating leases were as follows:
Year Railcars Other Total
- -------------------------------------------------------------
(in thousands)
2003 $ 429 $ 429 $ 858
2004 429 413 842
2005 429 346 775
2006 429 331 760
2007 429 327 756
2008 and thereafter 4,463 528 4,991
- -------------------------------------------------------------
Total minimum payments $6,608 $2,374 $8,982
=============================================================
5. INCOME TAXES
At December 31, 2002, tax-related regulatory assets and liabilities were $11.7
million and $12.4 million, respectively. The assets are attributable to tax
benefits flowed through to customers in prior years and to taxes applicable to
capitalized interest. The liabilities are attributable to deferred taxes
previously recognized at rates higher than current enacted tax law and to
unamortized investment tax credits.
Details of income tax provisions are as follows:
2002 2001 2000
--------------------------------
(in thousands)
Total provision for income taxes
Federal --
Currently payable $17,089 $27,991 $11,102
Deferred (5,660) (17,951) 75
- ------------------------------------------------------------------
11,429 10,040 11,177
- ------------------------------------------------------------------
State --
Currently payable 1,572 4,282 1,744
Deferred (568) (2,577) 653
- ------------------------------------------------------------------
1,004 1,705 2,397
- ------------------------------------------------------------------
Total $12,433 $11,745 $13,574
==================================================================
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:
2002 2001
---------------------
(in thousands)
Deferred tax liabilities:
Accelerated depreciation $83,092 $81,654
Property basis differences (1,250) (1,437)
Other 3,630 6,566
- ------------------------------------------------------------------
Total 85,472 86,783
- ------------------------------------------------------------------
Deferred tax assets:
Pension and other benefits 12,792 11,403
Other 14,132 10,560
- ------------------------------------------------------------------
Total 26,924 21,963
- ------------------------------------------------------------------
Total deferred tax liabilities, net 58,548 64,820
Portion included in current assets, net 20,422 12,511
- ------------------------------------------------------------------
Accumulated deferred income taxes
in the Balance Sheets $78,970 $77,331
==================================================================
In accordance with regulatory requirements, 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 per year in 2002,
2001, and 2000. At December 31, 2002, 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:
2002 2001 2000
----------------------------
Federal statutory tax rate 35% 35% 35%
State income tax, net of
federal income tax benefit 2 3 4
Other (2) (3) (2)
---------------------------------------------------------------
Effective income tax rate 35% 35% 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. In accordance with Internal
Revenue Service regulations, each company is jointly and severally liable for
the tax liability.
II-243
NOTES (continued)
Savannah Electric and Power Company 2002 Annual Report
6. CAPITALIZATION
Trust Preferred Securities
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
trust 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.
Long-Term Debt and Capital Leases
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.
Maturities and retirements of long-term debt were $53.6 million in 2002,
$50.7 million in 2001, and $0.4 million in 2000.
In September 2002, the Company borrowed $25 million under a $30 million
variable rate revolving credit agreement which terminates September 6, 2005. The
proceeds were used to repay a portion of the Company's short-term indebtedness.
In November 2002, the Company issued $55 million of Series D 5.50% senior notes
maturing November 15, 2017. The Company used these proceeds to redeem all of the
remaining $23.1 million 7.40% Series First Mortgage Bonds due July 1, 2023, to
redeem its $30 million Series A 6 5/8% Senior Retail Intermediate Bonds due
March 17, 2015 and for general corporate purposes.
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.
Securities Due Within One Year
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:
2002 2001
----------------------
(in thousands)
Bond sinking fund requirement $ 200 $ 436
Less:
Portion to be satisfied by
certifying property additions 200 -
- --------------------------------------------------------------------
Cash sinking fund requirement - 436
Other long-term debt maturities 20,892 742
- --------------------------------------------------------------------
Total $20,892 $1,178
====================================================================
The first mortgage bond improvement (sinking) fund requirements amount to 1
percent of each outstanding series of bonds authenticated under the first
mortgage bond 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 2002 and 2001. The 2003 requirement will be satisfied by
certifying property additions. Sinking fund requirements and/or maturities
through 2007 applicable to long-term debt are as follows: $20.9 million in 2003;
$0.8 million in 2004; $25.8 million in 2005; $20.7 million in 2006; and $0.7
million in 2007.
Bank Credit Arrangements
At the end of 2002, credit arrangements with four banks totaled $80 million and
expire at various times during 2003 and 2005. In September 2002, the Company
borrowed $25 million under a $30 million variable rate revolving credit
agreement which terminates in 2005.
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. Commitment fees are less than 1/8 of 1
II-244
NOTES (continued)
Savannah Electric and Power Company 2002 Annual Report
percent for the Company. Compensating balances are not legally restricted from
withdrawal.
The credit arrangements contain covenants that limit the level of
indebtedness to capitalization to 65 percent. Not meeting these limits would
result in an event of default under the credit arrangements. In addition, the
credit arrangements contain cross default provisions to other indebtedness that
would trigger an event of default if the borrower defaulted on indebtedness over
a specified threshold. The cross default provisions are restricted only to
indebtedness of the Company. The Company is currently in compliance with all
such covenants. Borrowings under unused credit arrangements totaling $5 million
would be prohibited if the Company experiences a material adverse change (as
defined in such arrangements).
The Company may also meet short-term cash needs through a Southern Company
subsidiary organized to issue and sell commercial paper and extendible
commercial notes at the request and for the benefit of the Company and the other
Southern Company operating companies. At December 31, 2002, the Company had
outstanding $2.9 million of commercial paper and no extendible commercial notes.
The Company's committed credit arrangements provide liquidity support to
the Company's variable rate obligations and to its commercial paper program. At
December 31, 2002, the amount of variable rate obligations outstanding requiring
liquidity support was $25.0 million, which includes the $2.9 million outstanding
commercial paper.
Assets Subject to Lien
As amended and supplemented, the Company's first mortgage bond indenture 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.
Common Stock Dividend Restrictions
The Company's first mortgage bond indenture contains certain limitations on the
payment of cash dividends on common stock. At December 31, 2002, approximately
$68 million of retained earnings was restricted against the payment of cash
dividends on common stock under the terms of the Indenture.
7. QUARTERLY FINANCIAL INFORMATION
(UNAUDITED)
Summarized quarterly financial data for 2002 and 2001 are as follows (in
thousands):
Operating Operating Net
Quarter Ended Revenues Income Income
- -------------------------------------------------------------
March 2002 $57,378 $ 6,865 $ 1,802
June 2002 78,360 14,594 7,035
September 2002 96,971 24,654 13,148
December 2002 66,843 4,701 895
March 2001 $61,691 $ 6,799 $ 1,476
June 2001 73,970 14,620 6,246
September 2001 93,583 22,332 11,309
December 2001 54,608 5,791 3,032
- -------------------------------------------------------------
The Company's business is influenced by seasonal weather
conditions and a seasonal rate structure, among other factors.
II-245
SELECTED FINANCIAL AND OPERATING DATA 1998-2002
Savannah Electric and Power Company 2002 Annual Report
- ---------------------------------------------------------------------------------------------------------------------------------
2002 2001 2000 1999 1998
- ---------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands) $299,552 $283,852 $295,718 $251,594 $254,455
Net Income after Dividends
on Preferred Stock (in thousands) $22,880 $22,063 $22,969 $23,083 $23,644
Cash Dividends
on Common Stock (in thousands) $22,700 $21,700 $24,300 $25,200 $23,500
Return on Average Common Equity (percent) 12.83 12.54 13.13 13.16 13.44
Total Assets (in thousands) $617,205 $594,743 $594,227 $570,218 $555,799
Gross Property Additions (in thousands) $32,481 $31,296 $27,290 $29,833 $18,071
- ---------------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $179,804 $176,918 $174,994 $174,847 $175,865
Company obligated mandatorily
redeemable preferred securities 40,000 40,000 40,000 40,000 40,000
Long-term debt 168,052 160,709 116,902 147,147 163,443
- ---------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $387,856 $377,627 $331,896 $361,994 $379,308
=================================================================================================================================
Capitalization Ratios (percent):
Common stock equity 46.4 46.8 52.7 48.3 46.4
Company obligated mandatorily
redeemable preferred securities 10.3 10.6 12.1 11.0 10.5
Long-term debt 43.3 42.6 35.2 40.7 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+ AA- AA-
Preferred Stock -
Moody's Baa1 Baa1 a2 a2 a2
Standard and Poor's BBB+ BBB+ BBB+ A- A
Unsecured Long-Term Debt -
Moody's A2 A2 - - -
Standard and Poor's A A - - -
=================================================================================================================================
Customers (year-end):
Residential 120,131 117,199 115,646 112,891 110,437
Commercial 16,512 16,121 15,727 15,433 15,328
Industrial 81 76 75 67 63
Other 494 474 444 417 377
- ---------------------------------------------------------------------------------------------------------------------------------
Total 137,218 133,870 131,892 128,808 126,205
=================================================================================================================================
Employees (year-end): 550 550 554 533 542
- --------------------------------------------------------------------------------------------------------------------------------
II-246
SELECTED FINANCIAL AND OPERATING DATA 1998-2002 (continued)
Savannah Electric and Power Company 2002 Annual Report
- ------------------------------------------------------------------------------------------------------------------------------
2002 2001 2000 1999 1998
- ------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $139,262 $123,819 $129,520 $112,371 $109,393
Commercial 104,195 100,835 102,116 88,449 86,231
Industrial 32,504 34,971 40,839 32,233 37,865
Other 9,810 9,547 10,147 9,212 8,838
- ------------------------------------------------------------------------------------------------------------------------------
Total retail 285,771 269,172 282,622 242,265 242,327
Sales for resale - non-affiliates 6,354 8,884 4,748 3,395 4,548
Sales for resale - affiliates 4,075 3,205 4,974 4,151 3,016
- ------------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 296,200 281,261 292,344 249,811 249,891
Other revenues 3,352 2,591 3,374 1,783 4,564
- ------------------------------------------------------------------------------------------------------------------------------
Total $299,552 $283,852 $295,718 $251,594 $254,455
==============================================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 1,793,330 1,658,735 1,671,089 1,579,068 1,539,792
Commercial 1,477,224 1,388,357 1,369,448 1,287,832 1,236,337
Industrial 793,181 787,674 800,150 713,448 900,012
Other 139,891 133,967 135,824 132,555 131,142
- ------------------------------------------------------------------------------------------------------------------------------
Total retail 4,203,626 3,968,733 3,976,511 3,712,903 3,807,283
Sales for resale - non-affiliates 150,795 111,145 77,481 51,548 53,294
Sales for resale - affiliates 125,882 87,799 88,646 76,988 58,415
- ------------------------------------------------------------------------------------------------------------------------------
Total 4,480,303 4,167,677 4,142,638 3,841,439 3,918,992
==============================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 7.77 7.46 7.75 7.12 7.10
Commercial 7.05 7.26 7.46 6.87 6.97
Industrial 4.10 4.44 5.10 4.52 4.21
Total retail 6.80 6.78 7.11 6.52 6.36
Sales for resale 3.77 6.08 5.85 5.87 6.77
Total sales 6.61 6.75 7.06 6.50 6.38
Residential Average Annual
Kilowatt-Hour Use Per Customer 15,085 14,241 14,593 14,100 14,061
Residential Average Annual
Revenue Per Customer $1,171.46 $1,063.07 $1,131.08 $1,003.39 $998.94
Plant Nameplate Capacity
Ratings (year-end) (megawatts) 788 788 788 788 788
Maximum Peak-Hour Demand (megawatts):
Winter 738 758 724 719 582
Summer 921 846 878 875 846
Annual Load Factor (percent) 54.5 55.9 53.4 51.2 54.9
Plant Availability Fossil-Steam (percent): 81.4 81.2 78.5 72.8 72.9
- ------------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 44.4 50.5 51.6 44.6 41.6
Oil and gas 4.2 4.0 6.9 12.3 12.9
Purchased power -
From non-affiliates 3.1 5.3 7.7 5.3 3.4
From affiliates 48.3 40.2 33.8 37.8 42.1
- ------------------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0 100.0 100.0
==============================================================================================================================
II-247
SOUTHERN POWER COMPANY
FINANCIAL SECTION
II-248
MANAGEMENT'S REPORT
Southern Power Company 2002 Annual Report
The management of Southern Power Company has prepared this annual report and is
responsible for the financial statements and related information. These
statements were prepared in accordance with accounting principles generally
accepted in the United States 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 accounting 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 Southern Company audit committee of its board of directors, composed of
five independent directors, provides a broad overview of management's financial
reporting and control functions. This committee meets periodically 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 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 Southern Power Company in conformity with accounting principles generally
accepted in the United States.
/s/William P. Bowers
William P. Bowers
President and Chief Executive Officer
/s/Cliff S. Thrasher
Cliff S. Thrasher
Senior Vice President, Comptroller
and Chief Financial Officer
February 17, 2003
II-249
INDEPENDENT AUDITORS' REPORT
Southern Power Company:
We have audited the accompanying balance sheets of Southern Power Company (a
wholly owned subsidiary of Southern Company) as of December 31, 2002 and 2001,
and the related statements of income, comprehensive income, common stockholder's
equity, and cash flows for the year ended December 31, 2002 and for the period
from January 8, 2001 (inception) to December 31, 2001. These financial
statements are the responsibility of Southern Power 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 of America. 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, such financial statements (pages II-260 through II-274)
present fairly, in all material respects, the financial position of Southern
Power Company at December 31, 2002 and 2001, and the results of its operations
and its cash flows for the year ended December 31, 2002 and for the period from
January 8, 2001 (inception) to December 31, 2001 in conformity with accounting
principles generally accepted in the United States of America.
/s/Deloitte & Touche LLP
Atlanta, Georgia
February 17, 2003
II-250
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Southern Power Company 2002 Annual Report
RESULTS OF OPERATIONS
In January 2001, Southern Power Company was formed as a wholly-owned subsidiary
of Southern Company. Southern Power constructs, owns, and manages wholesale
generating assets in the Southeast and is the primary growth engine for Southern
Company's competitive wholesale energy business.
Earnings
The Company's 2002 earnings totaled $54.3 million, representing a $46.1 million
increase over 2001. The 2002 increase was the result of increased sales of
wholesale capacity and energy to affiliated and non-affiliated companies. The
increased sales resulted primarily from the initiation of Power Purchase
Agreements (PPAs) with Georgia Power and Savannah Electric and requirements
agreements with 11 electric municipal cooperatives (EMCs) that went into effect
in June 2002. Earnings for 2002 also reflect commercial operation of Wansley
Units 6 and 7 and Franklin Unit 1 (the New Units) beginning in June 2002 and a
full year of Plant Dahlberg operations. As of December 31, 2002, the Company
had approximately 2,400 megawatts in commercial operation.
The Company began significant operations in July 2001 when Plant Dahlberg
was transferred from Georgia Power, another wholly-owned subsidiary of Southern
Company. The Company's 2001 earnings totaled $8.2 million and were derived
primarily from the sales of wholesale capacity and energy to affiliated and
non-affiliated companies.
Increase (Decrease)
Amount From Prior Year
------------------------------
2002 2002
- ---------------------------------------------------------
(in thousands)
Operating revenues $298,768 $269,467
- ---------------------------------------------------------
Fuel 97,965 94,186
Purchased power 53,663 48,937
Other operation and
maintenance 28,351 21,726
Depreciation and
amortization 18,319 15,028
Taxes other than
Income taxes 4,275 3,882
- ---------------------------------------------------------
Total operating
expenses 202,573 183,759
- ---------------------------------------------------------
Operating income 96,195 85,708
Other income, net 35,599 32,630
Less --
Interest expense
and other, net 49,067 46,329
Income taxes 28,457 25,946
- ---------------------------------------------------------
Net Income $54,270 $46,063
=========================================================
Revenues
Operating revenues in 2002 were $298.8 million, reflecting a $269.5 million
increase from 2001. In 2002, operating revenues were positively impacted by
commercial operation of the New Units and the initiation of PPAs with Georgia
Power and Savannah Electric and requirements agreements with 11 EMCs in June
2002. A majority of the revenues resulted from wholesale energy sales to
affiliated companies under PPAs. The remaining operating revenues are
attributed to wholesale energy sales to non-affiliated companies under PPAs and
sales through the Southern Company system power pool (Southern Pool).
Capacity revenues for 2002 were $123.9 million, or 41.5% of total revenues.
These revenues are an integral component of the PPAs with both associated and
non-associated customers.
In 2001, operating revenues of $29.3 million were solely attributed to
operations at Plant Dahlberg. The majority of the revenues, $26.4 million, were
from capacity and energy sales to non-affiliated companies under PPAs. The
remainder, $2.9 million, was from sales to affiliated companies through the
Southern Pool.
II-251
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company 2002 Annual Report
Revenues from sales to affiliated companies through the Southern Pool that
are not covered by PPAs will vary depending on demand and the availability and
cost of generating resources at each company within the Southern Pool. These
transactions do not have a significant impact on earnings since the energy is
generally sold at variable cost.
Expenses
Natural gas fuel costs constitute the single largest expense for the Company.
The increase in fuel expense in 2002 is primarily due to the commercial
operation of the New Units in 2002 and a full year of operation for Plant
Dahlberg. In addition, the average price of natural gas increased 33.4% from
2002 to 2001. The Company's PPAs provide that the purchasers are responsible for
substantially all of the cost of fuel relating to energy delivered under such
PPAs; therefore, these expense increases do not have a significant impact on net
income.
In 2002, purchased power from non-affiliates and affiliates increased by
$33.3 million and $15.6 million, respectively, to meet the demands of the
Company's contractual sales commitments.
Expenses from purchased power transactions will vary depending on demand
and the availability and cost of generating resources accessible throughout the
Southern Pool. Load requirements are submitted to the Southern Pool on an hourly
basis and are fulfilled with the lowest cost alternative, whether that is
Southern Power-owned, or affiliate-owned generation or external purchases.
In 2001, purchased power from non-affiliates and affiliates totaled $4.7
million. These expenses reflected the demand and the availability and cost of
generating resources accessible through the Southern Pool.
In 2002, other operation expense increased by $17.6 million mainly due to
increased administrative and general expenses of $12.3 million and other
production expenses of $5.2 million. These increases are primarily attributed to
the June 2002 commercial operation of the New Units.
Other operation expense in 2001 included administrative and general
expenses of $5.6 million and other production expenses of $0.6 million related
to the startup of the Company and the transfer of Plant Dahlberg in July 2001.
In 2002, depreciation and amortization increased as a direct result of the
New Units. Depreciation and amortization in 2001 all related to Plant Dahlberg
which was placed into service in July 2001.
In 2002, the increase in taxes other than income taxes is related to
property taxes for the New Units.
Interest expense in 2002 increased by $40.9 million from the amount
recorded in 2001. This increase in 2002 is primarily attributed to increased
debt associated with the Company's ongoing construction program. The majority of
the additional debt is comprised of $575 million in senior notes issued in June
2002 which accounted for $20.0 million of the increased expense. Increased
borrowing against the revolving line of credit increased expense by $15.7
million and an increase in the note payable to Southern Company of $209.5
million contributed $5.2 million of the increase. In 2001, interest expense
represented interest on long-term debt and interest on borrowings from Southern
Company to support the Company's on-going construction program.
These expenses were offset by interest capitalized related to borrowings
used to finance the Company's on-going construction program.
Other, net in 2002 decreased primarily due to unrealized losses on
derivative energy contracts.
Effects of Inflation
The Company is subject to long-term contracts and income tax laws that are based
on the recovery of historical costs. 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 generating facilities 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.
FUTURE EARNINGS POTENTIAL
General
The results of operations for 2002 and 2001 are not necessarily indicative of
future earnings. The level of future earnings depends on numerous factors
including completion of construction on new generating facilities, regulatory
II-252
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company 2002 Annual Report
matters, energy sales, creditworthiness of customers, total generating capacity
available in the Super Southeast, and the remarketing of capacity.
The Company is working to maintain and expand its share of wholesale energy
sales in the Southeastern power markets. By the end of 2005, the Company plans
to have approximately 6,600 megawatts of available generating capacity in
commercial operation. At December 31, 2002, 2,400 megawatts were in commercial
operation.
The Company currently has general authorization from the Federal Energy
Regulatory Commission (FERC) to sell power to non-affiliates at market-based
prices. Specific FERC approval must be obtained with respect to a market-based
contract with an affiliate. As with any seller that has been authorized to sell
at market-based rates, the FERC retains the authority to modify or withdraw the
Company's market-based rate authority if it determines that the underlying
requirements for having such authority are no longer applicable. In that event,
the Company would be required to obtain FERC approval of rates based on cost of
service, which may be lower than those in negotiated market-based rates.
In June 2002, PPAs with Georgia Power and Savannah Electric and
requirements agreements with 11 EMCs went into effect. Additionally, in June
2002 commercial operation of the New Units began.
In 2003, the Company expects Plant Franklin Unit 2, Plant Harris Units 1
and 2 and Plant Stanton A to be completed and placed into commercial operation.
In 2004, the Company's PPA with Georgia Power will begin for Plant Harris Unit
2. The Company also expects Plant Franklin Unit 3 and Plant McIntosh Units 10
and 11 to begin commercial operation in 2005. Substantially all of the Company's
generating capacity in operation, under construction or planned has been sold
under PPAs. (See Note 5 to the financial statements herein for additional
details.)
Also, effective in January 2003, the Company entered into contracts with
North Carolina Municipal Power Authority 1 (North Carolina) and the City of
Dalton (Dalton). Under the North Carolina contract, the Company will be
responsible for supplying North Carolina's capacity and energy needs in excess
of its existing resources and disposing of its surplus energy. The contract term
is January 1, 2003 through December 31, 2004. Under the Dalton contract, the
Company is responsible for supplying Dalton's requirements for capacity and
energy in excess of Dalton's existing resources. The contract term is for 15
years, beginning January 1, 2003, with a customer option to convert to a fixed
capacity purchase at the end of year 10.
Although under some of the Company's PPAs energy will be sold to Southern
Company's five regulated operating companies, the Company's generating
facilities will not be in the operating companies' regulated rate bases, and the
Company will not be able to seek recovery from the affiliated companies'
ratepayers for construction, repair or maintenance costs. It is expected that
the capacity payments in the PPAs will produce sufficient cash flow to meet
these costs, pay debt service and provide an equity return. However, the
Company's overall profit will depend on numerous factors, including efficient
operation of its generating facilities.
As a general matter, existing PPAs provide that the purchasers are
responsible for substantially all of the cost of fuel relating to the energy
delivered under such PPA. To the extent a particular generating facility does
not meet the operational requirements contemplated in most PPAs, the Company may
be responsible for excess fuel costs. With respect to fuel transportation risk,
most of the Company's PPAs provide that the purchasers are responsible for
procuring and transporting the fuel to the particular generating facility.
The Company's PPAs with non-affiliated counterparties have provisions that
require the posting of collateral or an acceptable substitute guarantee in the
event that Standard & Poor's or Moody's downgrades the credit ratings of such
counterparty to below-investment grade, or, if the counterparty is not rated or
fails to maintain a minimum coverage ratio. The PPAs are expected to provide the
Company with a stable source of revenue during their respective terms.
The Company has PPAs with subsidiaries of Dynegy Inc. (Dynegy) which are
now rated below investment grade. Minimum capacity revenues under one of these
contracts average approximately $13 million annually through May 2005. Dynegy
has provided a letter of credit expiring in April 2003 totaling $20 million
(approximately 18 months of capacity payments) to the Company. In addition, two
one-year letters of credit totaling $50 million (approximately 14 months of
capacity payments) were provided in April 2002 as security for obligations of
II-253
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company 2002 Annual Report
Dynegy affiliates under the Plant Franklin Unit 3 PPAs beginning in 2005. These
letters of credit can be drawn in the event of a default under the PPA or
failure to renew the letters of credit prior to expiration. In the event of such
a default, and if the Company was unable to resell that capacity in the market,
future earnings could be affected. The outcome of this matter cannot now be
determined.
In 2002, the Company executed additional PPAs whereby the Company will sell
capacity and energy from planned generating facilities at Plant McIntosh to
Georgia Power and Savannah Electric beginning in 2005. These PPAs are subject to
regulatory approval. Under these contracts and all other existing PPAs, the
Company has the right, at its sole discretion, to supply capacity and energy
under these arrangements from any resource available to it as part of the
Southern Pool. Reference is made to Note 3 to the financial statements herein
for additional information.
Fixed and variable operation and maintenance (O&M) costs will be covered
either through capacity charges or other charges based on dollars per kilowatt
year or dollars per megawatt hour. The Company has also entered into long-term
service contracts with General Electric International, Inc. (GE) to reduce its
exposure to certain O&M costs relating to GE equipment. See Note 5 to the
financial statements herein for additional information.
Industry Restructuring
The electric utility industry in the United States is continuing to evolve as a
result of regulatory and competitive factors. Among the early primary agents of
change was 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 enhanced the incentive for
IPPs to build power plants for a utility's large industrial and commercial
customers where retail access is allowed and sell energy to other utilities.
Also, electricity sales for resale rates were affected by numerous new energy
suppliers, including power marketers and brokers.
This past year, merchant energy companies and traditional electric utilities
with significant energy marketing and trading activities came under severe
financial pressures. Many of these companies have completely exited or
drastically reduced all energy marketing and trading activities and sold foreign
and domestic electric infrastructure assets. The Company has not experienced any
material financial impact regarding its limited energy trading operations and
recent generating capacity additions. In general, the Company only constructs
new generating capacity after entering into long-term capacity contracts for the
new facilities.
FERC Matters
In December 1999, the FERC issued its final rule on Regional Transmission
Organizations (RTOs). The order encouraged utilities owning transmission systems
to form RTOs on a voluntary basis. Southern Company has submitted a series of
status reports informing the FERC of progress toward the development of a
Southeastern RTO. In these status reports, Southern Company explained that it is
developing a for-profit RTO known as SeTrans with a number of non-jurisdictional
cooperative and public power entities. In 2001, Entergy Corporation and Cleco
Power joined the SeTrans development process. In 2002, the sponsors of SeTrans
established a Stakeholder Advisory Committee, which will participate in the
development of the RTO, and held public meetings to discuss the SeTrans
proposal. On October 10, 2002, the FERC granted Southern Company's and other
SeTrans' sponsors petition for a declaratory order regarding the governance
structure and the selection process for the Independent System Administrator
(ISA) of the SeTrans RTO. The FERC also provided guidance on other issues
identified in the petition. The SeTrans sponsors announced the selection of ESB
International, Ltd. (ESBI) to be the preferred ISA candidate. Should
negotiations with this candidate successfully conclude with final agreement
among the parties, the SeTrans sponsors intend to seek any state and federal
regulatory or other approvals necessary for formation of the SeTrans RTO and the
approval of ESBI to serve in the capacity of the SeTrans ISA. The creation of
SeTrans is not expected to have a material impact on the Company's financial
statements; however, the outcome of this matter cannot now be determined.
In July 2002, the FERC issued a notice of proposed rulemaking regarding
open access transmission service and standard electricity market design. The
proposal, if adopted, would among other things: (1) require transmission assets
of jurisdictional utilities to be operated by an independent entity; (2)
II-254
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company 2002 Annual Report
establish a standard market design; (3) establish a single type of transmission
service that applies to all customers; (4) assert jurisdiction over the
transmission component of bundled retail service; (5) establish a generation
reserve margin; (6) establish bid caps for a day ahead and spot energy markets;
and (7) revise the FERC policy on the pricing of transmission expansions.
Comments on certain aspects of the proposal have been submitted by Southern
Company. Any impact of this proposal on Southern Company and its subsidiaries
will depend on the form in which final rules may be ultimately adopted; however,
the Company's revenues, expenses, assets, and liabilities could be adversely
affected by changes in the transmission regulatory structure in its regional
power market.
Environmental Matters
The Company's business activities are subject to extensive governmental
regulation related to public health and the environment. Litigation over
environmental issues and claims of various types, including property damage,
personal injury and citizen enforcement of environmental requirements, has
increased generally throughout the United States; in particular, personal injury
claims for damages caused by alleged exposure to hazardous materials have become
more frequent.
Several major bills to amend the Clean Air Act to impose more stringent
emissions limitations have been proposed. Three of these, the Bush
Administration's Clear Skies Act, the Clean Power Act of 2002, and the Clean Air
Planning Act of 2002, proposed to further limit power plant emissions of sulfur
dioxide, nitrogen oxides, and mercury. The latter two bills also proposed to
limit emissions of carbon dioxide. None of these bills were enacted into law in
the last Congress. Similar bills have been, and are anticipated to be,
introduced this year. The Bush Administration's Clear Skies Act was recently
reintroduced, and President Bush has stated that it will be a high priority for
the administration. Other bills already introduced include the Climate
Stewardship Act of 2003, which proposes capping greenhouse gas emissions.
Federal and state environmental regulatory agencies are actively
considering and developing additional control strategies for emission of air
pollution from all major sources of air pollution, particularly electric
generating facilities. This includes the overall reduction of emission of
nitrogen oxides (NOx) in the eastern United States, the reduction of NOx and
particulate matter emissions to reduce regional haze and visibility impairment
in sensitive areas, the development of appropriate control standards and
technologies for emissions of mercury and the reduction of so-called "greenhouse
gases" (such as carbon dioxide) to address concerns over global climate change.
Development and implementation of final federal and state rules on these
issues could require substantial further reductions in all air emissions
associated with electricity generation. Additional compliance costs and capital
expenditures resulting from the implementation of such rules and standards
cannot be determined until the results of legal challenges are known and final
rules have been adopted at both the federal and state level.
The EPA and state environmental regulatory agencies are reviewing and
evaluating various other matters including: control strategies to reduce
regional haze; limits on pollutant discharges to impaired waters; cooling water
intake restrictions; 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
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 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.
All of the Company's PPAs contain provisions that permit charging the
purchaser with some of the new costs incurred as a result of change in law,
including environmental regulations.
Certain environmental, natural resource and land use concerns could have an
effect on site selection for future plants. This includes the potential for
designation of target areas as non-attainment for ozone or particulate matter
under newly adopted National Ambient Air Quality Standards, the availability of
water withdrawal rights, uncertainties regarding aesthetic impacts such as
II-255
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company 2002 Annual Report
increased light or noise or regarding any potential for adverse health impacts
associated with electric and magnetic fields. Such concerns and uncertainties
can increase the cost of siting and operating any type of electric generating
facility.
Accounting Policies
Critical Policies
The Company's significant accounting policies are described in Note 1 to the
financial statements. The Company has three critical accounting policies that
require a significant amount of judgment and are considered to be the most
important to the presentation of the Company's financial position and results of
operations. The first critical policy is the recognition of capacity revenues
from long-term contracts at the lesser of the levelized basis or the cash
collected over the contract periods. Second, the Company designates qualifying
derivative instruments as cash flow or fair value hedges under FASB Statement
No. 133, Accounting for Derivative Instruments and Hedging Activities, and marks
such derivative instruments to market based primarily on quoted market prices.
The unrealized changes in fair value of qualifying cash flow hedges are deferred
in other comprehensive income. Any ineffectiveness in those hedges and changes
in non-qualifying positions are reported as a component of current period
income. Finally, the Company uses flow-through accounting for state
manufacturer's tax credits. This means that the Company recognizes the credit as
a reduction of tax expense when it is more likely than not to be allowed by the
Georgia Department of Revenue.
Derivatives
Effective January 2001, the Company adopted FASB Statement No. 133, Accounting
for Derivative Instruments and Hedging Activities, as amended. In October 2002,
the Emerging Issues Task Force (EITF) of the FASB announced accounting changes
related to energy trading contracts in Issue No. 02-03. In October 2002, the
Company prospectively adopted the EITF's requirements to reflect the impact of
certain energy trading contracts on a net basis. This change had no material
impact on the company's income statement. Another change also required certain
energy trading contracts to be accounted for on an accrual basis effective
January 2003. This change had no impact on the Company's current accounting
treatment.
Asset Retirement Obligations
In January 2003, the Company adopted FASB Statement No. 143, Accounting for
Asset Retirement Obligations. Statement No. 143 establishes new accounting and
reporting standards for legal obligations associated with the ultimate cost of
retiring long-lived assets. The present value of the ultimate costs for an
asset's future retirement must be recorded in the period in which the liability
is incurred. The cost must be capitalized as part of the related long-lived
asset and depreciated over the asset's useful life. Additionally, Statement No.
143 does not permit non-regulated companies to continue accruing future
retirement costs for long-lived assets that they do not have a legal
obligation to retire.
The Company has no liability for asset retirement obligations. In January
2003, the Company recorded a reduction to the accumulated reserve for
depreciation and a cumulative effect of change in accounting principle of $0.6
million. This represents removal costs accrued prior to the implementation of
Statement No. 143.
FINANCIAL CONDITION
Plant Additions
The major change in the Company's financial condition during 2002 was the
addition of approximately $1.2 billion to utility plant related to on-going
construction of combined-cycle units and the transfer of two units at Plant
Wansley from Georgia Power. The funds for these additions were provided by the
Company's credit facility, the issuance of senior notes in June 2002, and
capital contributions and subordinated loans from Southern Company. The
Statements of Cash Flows provide additional information.
Credit Rating Risk
The Company does not have any credit agreements that would require material
changes in payment schedules or terminations as a result of a credit rating
downgrade. There are contracts that could require collateral -- but not
accelerated payment -- in the event of a credit rating change to below
investment grade. These contracts are primarily for physical electricity sales,
fixed-price physical gas purchases and agreements covering interest rate swaps
and currency swaps. At December 31, 2002, the maximum potential collateral
II-256
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company 2002 Annual Report
requirements under the electricity sale contracts and financial instruments were
approximately $194 million. Generally, collateral may be provided for by a
Southern Company guaranty, a letter of credit or cash. At December 31, 2002,
there were no material collateral requirements for the gas purchase contracts.
Exposure to Market Risks
The 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. The Company's policy is that
derivatives are to be used primarily for hedging purposes. Derivative positions
are monitored using techniques that include market valuation and sensitivity
analysis.
The weighted average interest rate on variable long-term debt outstanding
at December 31, 2002 was 3.65%. If the Company sustained a 100 basis-point
change in interest rates for all variable rate long-term debt, the change would
affect annualized gross interest cost by approximately $5.6 million at December
31, 2002. Most or all of that change would be capitalized, given the size of the
Company's construction program. To further mitigate the Company's exposure to
interest rates, it has entered into interest rate swaps that were designated as
cash flow hedges for planned debt issuances. The Company is not aware of any
facts or circumstances that would significantly affect such exposures in the
near term. See "Financing Activities" herein and Notes 1 and 7 to the financial
statements under the heading "Financial Instruments" for additional information.
The Company has firm purchase commitments that require payment in Euros. As
a hedge against fluctuations in the exchange rate for Euros, the Company entered
into forward contracts to purchase Euros and has designated these contracts as
fair value hedges. Since the terms of these Euro contracts mirror the purchase
commitment terms, there is no ineffectiveness recognized in income. At December
31, 2002, the Company had outstanding contracts covering a notional amount of
$5.5 million in commitments through May 2003.
Because energy from the Company's facilities is primarily sold under
long-term PPAs with tolling agreements and provisions shifting substantially all
of the responsibility for fuel cost to the purchasers, the Company's exposure to
market volatility in commodity fuel prices and prices of electricity is limited.
To mitigate residual risks in those areas, the Company enters into fixed-price
contracts for the purchase or sale of fuel and electricity. In connection with
the transfers of Plant Franklin in 2001 and Plant Wansley in 2002 to the
Company, Georgia Power transferred approximately $5.6 million and $1.6 million,
respectively, in derivative assets relating to electric and gas forward
contracts in effect at the date of the transfers. These contracts were recorded
at fair value on the date of the transfer, which was equal to Georgia Power's
carrying amount. Following the transfer, these contracts are marked to market
through income until realized and settled.
At December 31, 2002 and 2001, the fair value of changes in derivative
energy contracts and year-end valuations were as follows:
Changes in Fair Value
-------------------------------------------------------------
2002 2001
-------------------------------------------------------------
(in thousands)
Contracts beginning of year $ 5,496 $ -
Contracts realized or settled (4,336) -
New contracts at inception 1,576 5,617
Changes in valuation techniques - -
Current period changes 1,128 (121)
------------------------------------------------------------
Contracts end of year $ 3,864 $5,496
=============================================================
At December 31, 2002, all of these contracts are actively quoted
and mature within one year.
Unrealized gains and losses on electric and gas contracts used to hedge
anticipated purchases and sales are deferred in other comprehensive income.
Gains and losses on contracts that do not represent hedges are recognized in the
income statement as incurred. At December 31, 2002, the fair value of derivative
energy contracts was as follows:
Amounts
- ------------------------------------------------------------
(in thousands)
Other comprehensive income $2,706
Net income 1,158
- ------------------------------------------------------------
Total fair value $3,864
============================================================
II-257
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company 2002 Annual Report
Approximately $(4.9) million and $0.6 million of gains (losses) were
recognized in income in 2002 and 2001, respectively. The Company is exposed to
market-price risk in the event of nonperformance by parties to the derivative
energy contracts. The Company's policy is to enter into agreements with
counterparties that have investment grade credit ratings by Moody's and Standard
& Poor's, or with counterparties who have posted collateral to cover potential
credit exposure. Therefore, the Company does not anticipate market risk exposure
from nonperformance by the counterparties. For additional information, see Note
1 to the financial statements under "Financial Instruments."
Financing Activities
During 2002, Southern Company made to the Company equity contributions of
approximately $279.1 million, plus subordinated loans of approximately $209.5
million. Equity contributions and subordinated loans from Southern Company total
$941.7 million to the Company at the end of 2002. No dividends were paid in
2002.
In June 2002, the Company issued $575 million of 6.25% Senior Notes, Series
A due July 15, 2012. The net proceeds were used to reduce outstanding
indebtedness under a revolving credit agreement and to reduce loans from
Southern Company. The Company also settled several interest rate swap agreements
entered into in anticipation of this issuance at a $16.9 million loss. This
amount has been deferred in other comprehensive income and will be amortized to
interest expense over the life of the senior notes.
Also in June 2002, the Company issued a long-term note payable to Chilton
County, Alabama for $2.1 million. The proceeds of the note were used for the
purchase of land for a potential future generation site. The note is payable
over the next 5 years at an imputed interest rate of 6.25%.
Capital Requirements for Construction
The Company estimates that construction expenditures for the years 2003 through
2005 will total $377 million, $381 million and $278 million, respectively.
Actual construction costs may vary from this estimate because of changes in such
factors as: business conditions; environmental regulations; FERC rules and
transmission regulations; the cost and efficiency of construction labor,
equipment, and materials; and the cost of capital.
The Company has approximately 4,100 megawatts of new generating capacity
scheduled to be placed in service by 2005.
Other Capital Requirements
In addition to the funds needed for the construction program, approximately
$380.6 million will be required by the end of 2005 for maturities of long-term
debt.
These capital requirements and purchase commitments -- discussed in Notes 3
and 5 to the financial statements -- are as follows:
2003 2004 2005
- -----------------------------------------------------------------
(in millions)
Notes payable to Chilton County $ 0.2 $ 0.2 $ 0.2
Purchase commitments
- -----------------------------------------------------------------
Fuel $22.7 $22.9 $18.6
- -----------------------------------------------------------------
Long-term service agreements $17.1 $22.7 $21.4
- -----------------------------------------------------------------
Sources of Capital
The Company will use both external funds and equity capital from Southern
Company to finance its construction program. External funds will be from the
issuance of unsecured senior debt and commercial paper or utilization of
existing credit arrangements from banks.
At December 31, 2002, the Company had approximately $19.5 million of cash
and cash equivalents to meet short-term cash needs and contingencies. To meet
liquidity and capital resource requirements, the Company had at December 31,
2002 approximately $470 million of unused committed credit arrangements with
banks as shown in the following table.
At the beginning of 2003, bank arrangements are as follows:
Unused Expiring In
--------------------------------
Total Unused 2003 2004 & beyond
- -------------------------------------------------------------
(in millions)
$850 $470 $-- $470
- -------------------------------------------------------------
Amounts drawn under the arrangements are used to finance acquisition and
construction costs related to gas-fired electric generating facilities and for
II-258
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company 2002 Annual Report
general corporate purposes, subject to borrowing limitations for each generating
facility. The arrangements permit the Company to fund construction of future
generating facilities upon meeting certain requirements. At December 31, 2002,
the Company had $380 million in outstanding bank borrowings. See Note 7 to the
financial statements under "Long-Term Debt" for additional information.
Cautionary Statement Regarding
Forward-Looking Information
The Company's 2002 Annual Report includes forward-looking statements in addition
to historical information. Forward-looking information includes, among other
things, statements concerning scheduled completion of new generation, capacity
projections and the strategic goals for the Company's wholesale business. In
some cases, forward-looking statements can be identified by terminology such as
"may," "will," "could," "should," "expects," "plans," "anticipates," "believes,"
"estimates," "projects," "predicts," "potential," or "continue" or the negative
of these terms or other comparable terminology. The Company cautions that there
are various important factors that could cause actual results to differ
materially from those indicated in the forward-looking statements; accordingly,
there can be no assurance that such indicated results will be realized. These
factors include the impact of recent and future federal and state regulatory
change, including legislative and regulatory initiatives regarding deregulation
and restructuring of the electric utility industry, and also changes in
environmental and other laws and regulations to which the Company is subject, as
well as changes in application of existing laws and regulations; current and
future litigation; the effects, extent, and timing of the entry of additional
competition in the markets in which the Company operates; the impact of
fluctuations in commodity prices, interest rates, and customer demand; state and
federal rate regulations; political, legal, and economic conditions and
developments in the United States; the performance of projects undertaken by the
Company and the success of efforts to invest in and develop new opportunities;
internal restructuring or other restructuring options that may be pursued;
potential business strategies, including acquisitions or dispositions of assets
or businesses, which cannot be assured to be completed or beneficial to the
Company; the ability of counterparties of the Company to make payments as and
when due; the effects of, and changes in, economic conditions in the areas in
which the Company operates, including the current soft economy; the direct or
indirect effects on the Company's business resulting from the terrorist
incidents on September 11, 2001, or any similar such incidents or responses to
such incidents; financial market conditions and the results of financing
efforts; the ability of the Company to obtain additional generating capacity at
competitive prices; weather and other natural phenomena; and other factors
discussed elsewhere herein and in other reports (including the Form 10-K) filed
from time to time by the Company with the Securities and Exchange Commission.
II-259
STATEMENTS OF INCOME
For the Year Ended December 31, 2002 and For the Period from January 8, 2001
(Inception) to December 31, 2001
Southern Power Company 2002 Annual Report
- --------------------------------------------------------------------------------------------------------------------------
2002 2001
- --------------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Revenues:
Sales for resale --
Non-affiliates $114,919 $26,390
Affiliates 183,111 2,906
Other revenues 738 5
- --------------------------------------------------------------------------------------------------------------------------
Total operating revenues 298,768 29,301
- --------------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Operation --
Fuel 97,965 3,779
Purchased power --
Non-affiliates 34,499 1,209
Affiliates 19,164 3,517
Other 23,800 6,243
Maintenance 4,551 382
Depreciation and amortization 18,319 3,291
Taxes other than income taxes 4,275 393
- --------------------------------------------------------------------------------------------------------------------------
Total operating expenses 202,573 18,814
- --------------------------------------------------------------------------------------------------------------------------
Operating Income 96,195 10,487
Other Income and (Expense):
Interest income 288 78
Interest expense, net of amounts capitalized (8,886) (427)
Other income (expense), net (4,870) 580
- --------------------------------------------------------------------------------------------------------------------------
Total other income and (expense) (13,468) 231
- --------------------------------------------------------------------------------------------------------------------------
Earnings Before Income Taxes 82,727 10,718
Income taxes 28,457 2,511
- --------------------------------------------------------------------------------------------------------------------------
Net Income $ 54,270 $ 8,207
==========================================================================================================================
The accompanying notes are an integral part of these financial statements.
II-260
STATEMENTS OF CASH FLOWS
For the Year Ended December 31, 2002 and For the Period from January 8, 2001 (Inception) to December 31, 2001
Southern Power Company 2002 Annual Report
- -------------------------------------------------------------------------------------------------------------------------
2002 2001
- -------------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Activities:
Net income $ 54,270 $8,207
Adjustments to reconcile net income
to net cash provided from operating activities --
Depreciation and amortization 18,319 3,291
Deferred income taxes and investment tax credits, net 2,739 3,534
Other, net 17,955 5,406
Changes in certain current assets and liabilities --
Receivables, net (12,433) (5,381)
Fossil fuel stock (7,606) (3,425)
Materials and supplies (822) (5,731)
Other current assets (10,198) (183)
Accounts payable 8,628 2,242
Taxes accrued 7,834 394
Interest accrued 20,713 -
Other current liabilities - 250
- -------------------------------------------------------------------------------------------------------------------------
Net cash provided from (used for) operating activities 99,399 8,604
- -------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (1,214,677) (765,511)
Increase in construction related payables 3,229 28,171
Other (885) (10,126)
- -------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities (1,212,333) (747,466)
- -------------------------------------------------------------------------------------------------------------------------
Financing Activities:
Increase (decrease) in notes payable to parent, net 209,538 950
Proceeds --
Senior notes 575,000 -
Other long-term debt 87,873 293,205
Capital contributions from parent company 279,133 452,097
Settlement of interest rate swaps on senior note (16,884) -
Other (5,963) (3,679)
- -------------------------------------------------------------------------------------------------------------------------
Net cash provided from (used for) financing activities 1,128,697 742,573
- -------------------------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents 15,763 3,711
Cash and Cash Equivalents at Beginning of Period 3,711 -
- -------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ 19,474 $3,711
=========================================================================================================================
Supplemental Cash Flow Information:
Cash paid during the period for --
Interest (net of $35,311 and $2,891 capitalized for 2002 and 2001, respectively) $ - $ 427
Income taxes (net of refunds) 23,937 (423)
- -------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
II-261
BALANCE SHEETS
At December 31, 2002 and 2001
Southern Power Company 2002 Annual Report
- ------------------------------------------------------------------------------------------------------------------------------
Assets 2002 2001
- ------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Current Assets:
Cash and cash equivalents $ 19,474 $ 3,711
Receivables --
Customer accounts receivable 6,609 3,766
Affiliated companies 11,555 1,965
Accumulated provision for uncollectible accounts (350) (350)
Fossil fuel stock, at average cost 11,031 3,425
Materials and supplies, at average cost 6,553 5,731
Prepayments 8,796 183
Other 9,954 9,208
- ------------------------------------------------------------------------------------------------------------------------------
Total current assets 73,622 27,639
- ------------------------------------------------------------------------------------------------------------------------------
Property, Plant, and Equipment:
In service 896,163 265,153
Less accumulated provision for depreciation 21,590 3,291
- ------------------------------------------------------------------------------------------------------------------------------
874,573 261,862
Construction work in progress 1,082,987 500,358
- ------------------------------------------------------------------------------------------------------------------------------
Total property, plant, and equipment 1,957,560 762,220
- ------------------------------------------------------------------------------------------------------------------------------
Assets from risk management activities - 9,059
- ------------------------------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets:
Accumulated deferred income taxes 38,591 11,915
Other 16,203 12,024
- ------------------------------------------------------------------------------------------------------------------------------
Total deferred charges and other assets 54,794 23,939
- ------------------------------------------------------------------------------------------------------------------------------
Total Assets $2,085,976 $822,857
==============================================================================================================================
The accompanying notes are an integral part of these financial statements.
II-262
BALANCE SHEETS
At December 31, 2002 and 2001
Southern Power Company 2002 Annual Report
- -----------------------------------------------------------------------------------------------------------------------
Liabilities and Stockholder's Equity 2002 2001
- -----------------------------------------------------------------------------------------------------------------------
(in thousands)
Current Liabilities:
Securities due within one year $ 200 $ -
Notes payable to parent 210,488 950
Accounts payable --
Affiliated 37,748 26,135
Other 4,522 4,278
Taxes accrued --
Income taxes 3,915 394
Other 4,313 -
Interest accrued 20,713 -
Other 3,484 886
- -----------------------------------------------------------------------------------------------------------------------
Total current liabilities 285,383 32,643
- -----------------------------------------------------------------------------------------------------------------------
Long-Term Debt:
Senior notes 575,000 -
Other long-term debt 382,089 293,205
Unamortized debt (discount) premium, net (1,210) -
- -----------------------------------------------------------------------------------------------------------------------
Long-term debt 955,879 293,205
- -----------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Obligations under risk management activities 63,191 365
Deferred capacity revenues --
Affiliated 13,075 -
Other 3,147 1,717
Other --
Affiliated 15,644 23,415
Other 3,053 4,519
- -----------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 98,110 30,016
- -----------------------------------------------------------------------------------------------------------------------
Common stockholder's equity
Common stock, par value $0.01 per share --
Authorized - 1,000,000 shares
Outstanding - 1,000 shares - -
Paid-in capital 731,230 452,097
Retained earnings 62,477 8,207
Accumulated other comprehensive (loss) income (47,103) 6,689
- -----------------------------------------------------------------------------------------------------------------------
Total common stockholder's equity 746,604 466,993
- -----------------------------------------------------------------------------------------------------------------------
Total Liabilities and Stockholder's Equity $2,085,976 $822,857
=======================================================================================================================
Commitments and Contingent Matters (See notes)
- -----------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
II-263
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
For the Year Ended December 31, 2002 and For the Period from January 8, 2001 (Inception) to December 31, 2001
Southern Power Company 2002 Annual Report
- ---------------------------------------------------------------------------------------------------------------------------
Other
Common Paid-In Retained Comprehensive
Stock Capital Earnings Income (loss) Total
- ---------------------------------------------------------------------------------------------------------------------------
(in thousands)
Balance at December 31, 2000 $ - $ - $ - $ - $ -
Net income - - 8,207 - 8,207
Capital contributions from parent company - 452,097 - - 452,097
Other comprehensive income - - - 6,689 6,689
- ---------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2001 - 452,097 8,207 6,689 466,993
Net income - - 54,270 - 54,270
Capital contributions from parent company - 279,133 - - 279,133
Other comprehensive (loss) - - - (53,792) (53,792)
- ---------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2002 $ - $731,230 $62,477 $(47,103) $746,604
===========================================================================================================================
The accompanying notes are an integral part of these financial statements.
STATEMENTS OF COMPREHENSIVE INCOME
For the Year Ended December 31, 2002 and For the Period from January 8, 2001 (Inception) to December 31, 2001
Southern Power Company 2002 Annual Report
- ----------------------------------------------------------------------------------------------------------------
2002 2001
- ----------------------------------------------------------------------------------------------------------------
(in thousands)
Net income $ 54,270 $ 8,207
- ----------------------------------------------------------------------------------------------------------------
Other comprehensive (loss) income:
Changes in fair value of qualifying hedges, net of tax of (54,360) 6,689
$(34,030) and $4,219 for the years 2002 and 2001, respectively
Less: Reclassification adjustment for amounts included in net income, 568 -
net of tax of $355 and $0 for the years 2002 and 2001, respectively
- ----------------------------------------------------------------------------------------------------------------
Total other comprehensive (loss) income (53,792) 6,689
- ----------------------------------------------------------------------------------------------------------------
Comprehensive Income $ 478 $14,896
================================================================================================================
The accompanying notes are an integral part of these financial statements.
II-264
NOTES TO FINANCIAL STATEMENTS
Southern Power Company 2002 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING
POLICIES
General
Southern Power is a wholly owned subsidiary of Southern Company, which is also
the parent company of five operating companies, a system service company (SCS),
Southern Company Gas (Southern GAS), and other direct and indirect subsidiaries.
The operating companies --Alabama Power Company, Georgia Power Company, Gulf
Power Company, Mississippi Power Company, and Savannah Electric and Power
Company -- provide electric service in four southeastern states. Southern Power
constructs, owns and manages Southern Company's competitive generation assets
and sells electricity at market-based rates in the wholesale market. Contracts
among the operating companies and Southern Power -- related to jointly owned
generating facilities, interconnecting transmission lines or 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 subsidiary companies.
Southern GAS, which began operation in August 2002, is a competitive retail
natural gas marketer serving communities in Georgia.
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
follows accounting principles generally accepted in the United States. The
preparation of financial statements in conformity with accounting principles
generally accepted in the United States requires the use of estimates, and the
actual results may differ from these estimates.
Southern Power was formed on January 8, 2001. Southern Power began
commercial operations in August 2001 after Georgia Power transferred its
interest in Plant Dahlberg Units 1 through 10. See Note 2, Asset Transfers, for
further information regarding asset transfers from affiliates. The consolidated
financial statements include the accounts of Southern Power and its wholly-owned
subsidiary, Southern Company - Florida LLC (SCF) which was established to own,
operate and maintain Plant Stanton Unit A. See Note 4 for further information.
All intercompany accounts and transactions have been eliminated in
consolidation.
Certain prior years' data presented in the financial statements have been
reclassified to conform with current year presentation.
Affiliate Transactions
Southern Power has an agreement with SCS under which the following services are
rendered to the Company at direct or allocated cost: general and design
engineering, purchasing, accounting and statistical analysis, finance and
treasury, tax, information resources, marketing, auditing, insurance and pension
administration, human resources, systems and procedures and other services with
respect to business and operations and power pool transactions. SCS also enters
into fuel purchase and transportation arrangements and contracts, financial
instruments for purposes of hedging and wholesale energy purchase and sale
transactions for the benefit of Southern Power. As Southern Power has no
employees, all employee related charges are rendered at cost under agreements
with SCS or the operating companies. Costs for these services from SCS amounted
to approximately $29.5 million and $12 million during 2002 and 2001,
respectively, of which approximately $16.2 million in 2002 and $4.7 million in
2001 was general, administrative, operation and maintenance expenses; the
remainder was capitalized to construction work in progress. Cost allocation
methodologies used by SCS are approved by the SEC and management believes they
are reasonable.
Southern Power has an agreement with Georgia Power to provide operation and
maintenance services for Plants Dahlberg, Wansley and Franklin. These services
are billed at cost on a monthly basis and are recorded as operations and
maintenance expense in the accompanying statements of income. For the periods
ended December 31, 2002 and 2001, these services totaled approximately $5.3
million and $1.0 million, respectively.
Additionally, Southern Power has agreements with Alabama Power and Georgia
Power to provide procurement, payables and other functions related to the
construction at Plants Harris and Franklin in Alabama and Plant Wansley in
Georgia. Costs for these services are billed monthly and are capitalized.
Effective June 2002, Southern Power entered into Power Purchase Agreements
(PPAs) with Georgia Power and Savannah Electric for the sale of capacity and
energy. Billings under these agreements totaled $165 million, including $13.5
II-265
NOTES (continued)
Southern Power Company 2002 Annual Report
million of deferred capacity revenues included in deferred capacity revenues on
the Balance Sheet at December 31, 2002. See Note 5 herein for additional
information.
The operating companies, Southern Power, and Southern GAS may jointly enter
into various types of wholesale energy, natural gas and certain other contracts,
either directly or through SCS as agent. Each participating company may be
jointly and severally liable for the obligations incurred under these
agreements.
See Note 5 for information regarding PPAs between Southern Power and
Alabama Power, Georgia Power and Savannah Electric.
Southern Power and its affiliates generally settle amounts related to the
above transactions on a monthly basis in the month following the performance of
such services or the purchase or sale of electricity.
Also see Notes 2, 3, 4 and 7 for information related to various types of
financing support provided by Southern Company.
Revenues and Fuel Costs
Revenues are recognized as services are rendered. Capacity is sold at rates
specified under contractual terms and is recognized at the lesser of the
levelized basis or the cash collected over the respective contract periods.
Energy is generally sold at market-based rates and the associated revenue is
recognized as the energy is delivered.
Significant portions of Southern Power's revenues have been derived from
certain customers. For the year ended December 31, 2002, Georgia Power, Savannah
Electric, LG&E Energy Marketing, Inc. and Dynegy Power Marketing Inc. accounted
for approximately 33.5%, 17.2%, 15.8% and 4.4% of revenues, respectively. For
the period ended December 31, 2001, LG&E Energy Marketing, Inc. and Dynegy Power
Marketing Inc. accounted for approximately 66% and 21% of revenues,
respectively.
Fuel costs are expensed as the fuel is consumed. The Company relies mainly
on natural gas to fuel its generating units. See Note 3 herein for further
details on future commitments.
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. Materials and supplies are recorded at average cost.
Property, Plant and Equipment
Property, plant and equipment are stated at original cost. Original cost
includes materials, direct labor incurred by affiliated companies, minor items
of property and appropriate administrative costs. Interest is capitalized on
qualifying projects during the development and construction period. In 2002 and
2001, interest of approximately $35.3 million and $2.9 million, respectively,
was capitalized in connection with the development and construction of power
plants. The cost of maintenance, repairs and replacement of minor items of
property is charged to maintenance expense as incurred. The cost of replacements
of property that extend the useful life of the plant, exclusive of minor items
of property, is capitalized.
Depreciation
Depreciation of the original cost of assets is computed under the straight-line
method based on the assets' estimated useful lives determined by the Company.
The primary assets in property, plant and equipment are power plants all of
which have an estimated useful life of 35 years, except Plant Dahlberg which has
an estimated useful life of 40 years.
In January 2003, Southern Power adopted FASB Statement No. 143, Accounting
for Asset Retirement Obligations. Statement No. 143 establishes new accounting
and reporting standards for legal obligations associated with the ultimate cost
of retiring long-lived assets. The present value of the ultimate costs for an
asset's future retirement must be recorded in the period in which the liability
is incurred. The cost must be capitalized as part of the related long-lived
II-266
NOTES (continued)
Southern Power Company 2002 Annual Report
asset and depreciated over the asset's useful life. Additionally, Statement No.
143 does not permit the continued accrual of future retirement costs for
long-lived assets that the company does not have a legal obligation to retire.
The Company has no liability for asset retirement obligations. In January
2003, the Company recorded a reduction to the accumulated reserve for
depreciation and a cumulative effect of change in accounting principle of $0.6
million. This represents removal costs accrued prior to the implementation of
Statement No. 143.
Impairment of Long-Lived Assets
The Company evaluates long-lived assets for impairment whenever events or
changes in circumstances indicate that the carrying amount 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 the 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.
Deferred Project Development Costs
The Company capitalizes project development costs once it is determined that it
is probable that a specific site will be acquired and a power plant constructed.
These costs include professional services, permits and other costs directly
related to the construction of a new project. These costs are generally
transferred to construction work in progress upon commencement of construction.
The total deferred project development costs at December 31, 2002 and December
31, 2001 were $3.6 million and $4.5 million, respectively.
Financial Instruments
The Company uses derivative financial instruments to hedge exposures to
fluctuations in interest rates, foreign currency exchange rates, the prices of
certain fuel purchases and electricity purchases and sales. All derivative
financial instruments are recognized as either assets or liabilities and are
measured at fair value.
The Company and its affiliates, through SCS acting as their agent, enter into
commodity related forward and option contracts to limit exposure to changing
prices on certain fuel purchases and electricity purchases and sales.
Substantially all of the Company's bulk energy purchases and sales contracts are
derivatives. However, in many cases, these contracts qualify as normal purchases
and sales and are accounted for under the accrual method. Other contracts
qualify as cash flow hedges of anticipated transactions, resulting in the
deferral of related gains and losses, and are recorded in other comprehensive
income until the hedged transactions occur. Any ineffectiveness is recognized
currently in net income. Contracts that do not qualify for the normal purchase
and sale exception and that do not meet the hedge requirements are marked to
market through current period income and are recorded on a net basis in the
consolidated Statements of Income.
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 has firm purchase commitments for equipment that require payment
in Euros. As a hedge against fluctuations in the exchange rate for Euros, the
Company entered into forward contracts to purchase Euros. The Company has
designated these contracts as fair value hedges. At December 31, 2002, Southern
Power had outstanding contracts covering a notional amount of $5.5 million in
commitments through May 2003. The forward contracts to purchase Euros are on the
same dates and in the same amounts as the Euro payments that the Company owes
for the equipment. As all of the critical terms of the forward Euro purchases
(dates and amounts) match those of the Euro payment obligations, the changes in
fair value attributable to the risk being hedged are expected to completely
offset at inception and on an ongoing basis. Therefore, there is no
ineffectiveness related to this hedge.
II-267
NOTES (continued)
Southern Power Company 2002 Annual Report
Other Southern Power financial instruments for which the carrying amounts
did not equal fair value at December 31, 2002 were as follows:
Carrying Fair
Amount Value
------------------------
Long-term debt: (in millions)
At December 31, 2002 $956 $990
- --------------------------------------------------------------
The fair values for securities were based on either closing market prices
or closing prices of comparable instruments.
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.
Comprehensive Income
Comprehensive income -- consisting of net income and changes in the fair value
of qualifying cash flow hedges, net of income taxes less reclassifications of
amounts included in net income-- is presented in the financial statements. The
objective of comprehensive income 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.
2. ASSET TRANSFERS
On July 31, 2001, Georgia Power transferred its interests in Plant Dahlberg
Units 1 through 10 and related working capital to Southern Power. In accordance
with the affiliate transaction rules of PUHCA, these assets were transferred at
Georgia Power's net carrying costs of $260.1 million. The transferred assets
consist primarily of 10 combustion turbine units (810 MW) in operation, all
located in Jackson County, Georgia. In connection with the asset transfer,
Georgia Power also assigned to the Company its interest in three PPAs related to
Plant Dahlberg. The results of operations of Plant Dahlberg were included in the
financial statements from August 1, 2001.
The following projects, which were under construction, were transferred
from Alabama Power and Georgia Power to Southern Power and recorded in
construction work in progress at the respective affiliate's book value:
Transferred Amount
Plant from Date (in millions)
- -------------------------------------------------------------------
Harris Alabama Power 06/2001 $ 91.4
Units 1 & 2
Franklin
Units 1 & 2 Alabama Power 11/2001 267.9
and
Georgia Power
Wansley Georgia Power 01/2002 389.9
Units 6 & 7
- -------------------------------------------------------------------
In conjunction with these transfers, Alabama Power and Georgia Power have
assigned PPAs related to these plants and certain vendor contracts related to
the on-going construction of these facilities to Southern Power. Southern
Company has entered into limited keep-well arrangements with Alabama Power and
Georgia Power whereby Southern Company will contribute funds to the Company via
loans or capital contributions to fund the performance of Southern Power as
equipment purchaser under certain arrangements. As of December 31, 2002,
Southern Power's remaining purchase obligations to equipment vendors under these
contracts totaled $12.2 million.
In addition, Southern Company has entered into keep-well agreements with
Alstom Power for the transfer of an equipment contract at the Company's Plant
Franklin Unit 3. At December 31, 2002, the amount outstanding under this
contract was $0.1 million.
3. CONTINGENCIES AND COMMITMENTS
General Litigation Matters
Southern Power is subject to certain claims and legal actions arising in the
ordinary course of business. The Company's business activities are subject to
extensive governmental regulation related to public health and the environment.
Litigation over environmental issues and claims of various types, including
property damage, personal injury and citizen enforcement of environmental
requirements, has increased generally throughout the United States. In
particular, personal injury claims for damages caused by alleged exposure to
hazardous materials have become more frequent.
The ultimate outcome of such litigation currently filed against the Company
cannot be predicted at this time; however, after consultation with legal
II-268
NOTES (continued)
Southern Power Company 2002 Annual Report
counsel, management does not anticipate that the liabilities, if any, arising
from such proceedings would have a material adverse effect on the Company's
financial statements.
Fuel
SCS, as agent for the operating companies and Southern Power, has entered into
various fuel transportation and procurement agreements to supply a portion of
the fuel (primarily natural gas) requirements for the operating facilities. In
most cases, these contracts contain provisions for firm transportation costs,
storage costs, minimum purchase levels and other financial commitments. The
total estimated firm costs are as follows:
Fuel
Purchases
Year (in thousands)
- ---- ------------------
2003 $ 22,692
2004 22,890
2005 18,577
2006 18,577
2007 18,577
2008 and beyond 449,588
- ----------------------------------------
Total $550,901
========================================
Natural gas purchases (in dollars) are based on various indices at the
actual time of delivery; therefore, only the volume commitments are firm and
disclosed in the following chart.
Total estimated long-term obligations at December 31, 2002 were as follows:
Natural
Gas
Year MMBtu
- ---- ---------------
2003 20,180,312
2004 7,125,668
2005 4,046,104
2006 2,250,859
2007 830,151
2008 and beyond -
- ----------------------------------------
Total 34,433,094
========================================
Purchases of natural gas were approximately $133.5 million and $4.4 million
for the periods ended December 31, 2002 and 2001, respectively. Additional
commitments for fuel will be required to supply the Company's future needs.
Acting as an agent for all of Southern Company's operating companies,
Southern Power and Southern GAS, SCS may enter into various types of wholesale
energy and natural gas contracts. Under these agreements, each of the operating
companies, Southern Power and Southern GAS may be jointly and severally liable
for the obligations of each of the operating companies, Southern Power and
Southern GAS. The creditworthiness of Southern Power and Southern GAS is
currently inferior to the creditworthiness of the operating companies;
therefore, Southern Company has entered into keep-well agreements with each of
the operating companies to insure they will not subsidize nor be responsible for
any costs, losses, liabilities or damages resulting from the inclusion of
Southern Power as a contracting party under these agreements.
Construction Program
The Company currently estimates property additions to be $377 million, $381
million and $278 million in 2003, 2004 and 2005, respectively. Southern Power
has approximately 4,100 megawatts of additional generating capacity scheduled to
be placed in service by 2005.
Significant purchase commitments are outstanding in connection with the
construction program.
Southern Power's obligations for construction of transmission
interconnection facilities to these plants by Alabama Power and Georgia Power
totaled $13.5 million and $13 million at December 31, 2002 and 2001,
respectively, and are guaranteed by Southern Company.
Southern Company has also granted performance guarantees on behalf of
Southern Power and its subsidiary for construction payment obligations
associated with Plant Stanton. See Note 4 herein for additional information.
Long-Term Service Agreements
Southern Power has entered into several Long-Term Service Agreements (LTSAs)
with General Electric International, Inc. (GE) for the purpose of securing
maintenance support for its combined cycle and combustion turbine generating
facilities. The LTSAs stipulate that for a fee, GE will perform all planned
inspections on the covered equipment, which includes the cost of all labor and
II-269
NOTES (continued)
Southern Power Company 2002 Annual Report
materials. GE is also obligated to cover the costs of unplanned maintenance on
the covered equipment subject to a limit specified in each contract.
In general, except for Plant Dahlberg, these LTSAs are in effect through
two major inspection cycles per unit. The Dahlberg agreement is in effect
through the first major inspection of each unit. Scheduled payments to GE are
made at various intervals based on actual operation hours of the respective
units. Total payments to GE under these agreements are $852 million over the
life of the agreements, which are approximately 28 to 30 years per unit.
However, the LTSAs contain various cancellation provisions at the Company's
option.
Payments made to GE prior to the performance of any planned inspections are
recorded as a prepayment in the Balance Sheets. Costs are capitalized or charged
to expense based on the nature of the work performed.
4. JOINT-OWNERSHIP AGREEMENTS
Southern Power, through its wholly owned subsidiary SCF, is a 65% owner of Plant
Stanton Unit A (Stanton A), a combined-cycle project that will total 633 MW upon
completion. The unit is co-owned by Orlando Utilities Commission (OUA) (28%),
Florida Municipal Power Agency (FMPA) (3.5%), and Kissimmee Utility Authority
(KUA) (3.5%). Southern Power has a services agreement with SCS where SCS will be
responsible for the operation and maintenance of Stanton A and the overall
project management of the construction process. Construction on Stanton A began
in October 2001 with an expected completion date of October 1, 2003. At December
31, 2002 and 2001, Southern Power's share of the construction costs for Stanton
A was $128.3 million and $31.4 million, respectively, and is recorded in
construction work in progress in the consolidated Balance Sheets.
Southern Company has agreed to grant performance guarantees on behalf of
Southern Power and its subsidiary, SCF, for SCF's payment obligations under
ownership and PPAs associated with the Stanton A project. Southern Power's
maximum exposure is $53 million under the construction and ownership agreement
and $20 million under the PPAs. See Note 5 herein for additional information.
5. LONG-TERM POWER SALES AGREEMENTS
The Company has entered into long-term power sales agreements for portions of
its generating unit capacity, as follows:
Project Capacity Contract
(megawatts) Term
---------------------------------------------------
Affiliated
-----------
Franklin Unit 1 571 * 6/02-5/10
Franklin Unit 2 615 ** 6/03-5/11
Wansley Units 6
& 7 1,134 6/02-12/09
Harris Unit 1 618 6/03-5/10
Harris Unit 2 618 *** 6/04-5/19
McIntosh 1,240 6/04-5/20
---------------------------------------------------
Total Affiliated 4,796
---------------------------------------------------
Non-Affiliated
---------------
Dahlberg Units
1-7 578 6/00-12/04
Dahlberg Units
8-10 225 6/00-5/05
Stanton A 396 11/03-11/13
Franklin Unit 3 625 6/05-5/30
-----------------------------------------------------
Total Non
-affiliated 1,824
-----------------------------------------------------
* 370 megawatts during the first year
** 400 megawatts during the first year
*** Contract does not begin until second year of operation of Harris Unit
2.
Capacity revenues from these long-term power sales agreements amounted to
$120.1 million and $18.6 million for the periods ended December 31, 2002 and
2001, respectively. Future capacity payments to be received under these power
sales agreements as of December 31, 2002 are as follows:
Year Payments
- ------------------------------------------------------------
Affiliated Non-Affiliated
(in millions)
2003 $ 172.5 $ 53.6
2004 241.1 76.2
2005 325.1 127.8
2006 338.2 156.8
2007 336.2 155.4
2008 and beyond 2,040.3 1,319.9
- ------------------------------------------------------------
Total $3,453.4 $1,889.7
- ------------------------------------------------------------
II-270
NOTES (continued)
Southern Power Company 2002 Annual Report
Included in the amounts above are capacity payments to be received related
to a five-year contract (beginning in 2000) with Dynegy of approximately $13
million annually through May 2005. As a result of Dynegy's liquidity problems,
it has provided a letter of credit totaling $20 million which can be drawn in
the event of a default under the PPA or the failure to renew the letter of
credit prior to expiration in April 2003.
Georgia Power required that certain counterparties to the Dahlberg PPAs
make prepayments for operational rights to the units. These prepayments were
recorded as liabilities by Georgia Power and were transferred to Southern Power
in connection with the Plant Dahlberg transfer. At December 31, 2002 and 2001,
the unamortized balance of these amounts totaled $2.8 million and $4.2 million,
respectively, and is being amortized into income over the life of the
agreements.
In June 2002, Southern Power began providing services under requirements
agreements with 11 Georgia electric municipal cooperatives (EMCs). Under the
agreements, Southern Power will coordinate the generating resources and meet
the additional capacity requirements of the EMCs. The contracts are in effect
through 2009 with options to renew.
Effective in January 2003, the Company entered into contracts with North
Carolina Municipal Power Authority 1 (North Carolina) and the City of Dalton
(Dalton). Under the North Carolina contract, the Company will be responsible for
supplying North Carolina's capacity and energy needs in excess of its existing
resources and disposing of its surplus energy. The contract term is for January
1, 2003 through December 31, 2004. Under the Dalton contract, the Company is
responsible for supplying Dalton's requirements for capacity and energy in
excess of Dalton's existing resources. The contract term is for 15 years,
beginning January 1, 2003, with a customer option to convert to a fixed capacity
purchase at the end of year 10.
6. INCOME TAXES
Details of the federal and state income tax provisions are as follows:
2002 2001
----------------------------
(in thousands)
Total provision for
income taxes:
Federal:
Current $26,990 $ 1,402
Deferred 2,338 3,017
- -------------------------------------------------------------
29,238 4,419
- -------------------------------------------------------------
State:
Current 4,622 240
Deferred 401 517
State manufacturer's
tax credits (5,804) (2,665)
- -------------------------------------------------------------
(781) (1,908)
- -------------------------------------------------------------
Total $28,457 $ 2,511
=============================================================
Southern Power recorded a reduction in 2002 and 2001 tax expense of
approximately $5.8 million and $2.7 million, respectively, under the
flow-through method of accounting for the State of Georgia manufacturer's tax
credits. The State of Georgia provides a tax credit for qualified investment
property to manufacturing companies that construct new facilities. The credit
ranges from 1% to 5% of construction expenditures depending upon the county in
which the new facility is located. Southern Power's policy is to recognize these
credits when management believes they are more likely than not to be allowed by
the Georgia Department of Revenue.
The tax effects of temporary differences between the carrying amounts of
assets and liabilities in the financial statements and their respective tax
bases, which give rise to deferred tax assets and liabilities, are as follows:
II-271
NOTES (continued)
Southern Power Company 2002 Annual Report
2002 2001
-----------------------
(in millions)
Deferred tax liabilities:
Accelerated depreciation $(17,401) $(4,444)
Other (729) (3,451)
- --------------------------------------------------------------
Total (18,130) (7,895)
- --------------------------------------------------------------
Deferred tax assets:
Book/tax basis difference on
asset transfer 15,644 19,810
Levelized capacity revenues 8,003 -
Other comprehensive on
interest rate swaps 30,745 -
Other 2,329 -
- --------------------------------------------------------------
Total 56,721 19,810
- --------------------------------------------------------------
Accumulated deferred income
taxes in the consolidated
Balance Sheets $38,591 $11,915
==============================================================
Deferred tax liabilities were primarily the result of property related
timing differences and derivative hedging instruments. Deferred tax assets were
primarily the result of a deferred tax gain related to the transfer of Plant
Dahlberg from Georgia Power. Southern Power has recognized a payable to Georgia
Power for Georgia Power's deferred tax liability resulting from this gain of
approximately $15.6 million and $19.8 million at December 31, 2002 and 2001,
respectively, which is recorded in other deferred credits on the accompanying
consolidated balance sheet.
A reconciliation of the federal statutory tax rate to the effective income
tax rate is as follows:
2002 2001
------------------
Federal statutory rate 35.0 35.0
State income tax, net of
federal deduction 3.9 4.6
State manufacturer's tax
Credits, net of federal effect (4.5) (16.2)
- -------------------------------------------------------
Effective income tax rate 34.4 23.4
=======================================================
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. In
accordance with Internal Revenue Service regulations, each company is jointly
and severally liable for the tax liability.
7. FINANCING
Southern Company is currently authorized by the SEC under the PUHCA to fund the
development of Southern Power up to an aggregate amount not to exceed $1.7
billion, which may take the form of purchases or contributions of equity
interests, loans and guarantees issued in support of Southern Power's securities
or obligations. Southern Power has SEC approval under the PUHCA to issue up to
an aggregate amount of $2.5 billion of preferred securities, long and short-term
debt and other equity issuances.
Common Stock
Southern Power has authorized common stock of 1 million shares at $.01 par value
per share. One thousand shares have been issued to Southern Company and were
outstanding at December 31, 2002.
Note Payable to Parent
In 2001, Southern Power entered into an intercompany note payable to Southern
Company. The note is payable on demand and bears interest at a variable rate. At
December 31, 2002 and 2001, $210.5 million and $1 million, respectively, were
outstanding with an interest rate of 5.04% and 2.49%, respectively. As part of
the Company's ongoing financing plan, in March 2003, $190 million of the note
was converted to a capital contribution from Southern Company, leaving a balance
of $51 million.
Long-Term Debt
In November 2001, the Company entered into an $850 million unsecured syndicated
revolving credit facility (Facility). The purpose of the Facility is to finance
the acquisition and construction costs related to gas-fired electric generating
facilities and general corporate purposes (subject to a $25 million limit), and
to pay or support commercial paper used to fund construction of facilities. At
December 31, 2002, Southern Power had borrowed approximately $380 million under
the Facility leaving an unused borrowing authority of approximately $470
million. Borrowings under the Facility bear interest at Southern Power's option
equal to either the Eurodollar rate plus a specified margin ranging from 1.125%
to 2.875%, depending on Southern Power's credit rating and the amount drawn down
under the facility, or a base rate plus a specified margin. The interest rate
II-272
NOTES (continued)
Southern Power Company 2002 Annual Report
and average interest rate on the Facility were 2.73% and 3.15% and 3.44% and
3.61%, respectively, at December 31, 2002 and 2001 and during the periods then
ended. Southern Power is required to pay a commitment fee on the unused balance
of the Facility. The commitment fee ranges from 0.3% to 0.45%, depending on
Southern Power's credit rating. For the periods ended December 31, 2002 and
2001, Southern Power paid approximately $1.1 million and $0.1 million in
commitment fees, respectively. All borrowings outstanding under the Facility are
due in November 2004.
The Facility contains certain financial covenants relating to Southern
Power's debt capitalization which require that additional debt incurred by
Southern Power must generally be unsecured and Southern Power must have its
ratings reaffirmed at investment grade including the new debt. The Facility also
contains restrictions related to the assumption of additional debt, which
require a maximum 60% debt ratio, excluding intercompany loans. Southern Power
was in compliance with such covenants at December 31, 2002. Initial borrowings
under the Facility for new projects would be prohibited if Southern Power or
Southern Company experiences a material adverse change (as defined in the
Facility). For Southern Power's bank credit arrangements, there is a cross
default to Southern Company's indebtedness, which if triggered would require
prepayment of debt related to projects financed under the credit arrangement
that are not complete.
In June 2002, Southern Power issued $575 million of 6.25% Senior Notes,
Series A due July 15, 2012. The net proceeds were used to reduce outstanding
indebtedness under the Facility and to reduce the intercompany note payable to
Southern Company. Southern Power also settled several interest rate swap
agreements entered into in anticipation of this issuance at a $16.9 million
loss. This amount has been deferred in other comprehensive income and will be
amortized to interest expense over the life of the senior notes. Also in June
2002, the Company issued a long-term note payable to Chilton County, Alabama for
$2.1 million. The proceeds of the note were used for the purchase of land for a
potential future generation site. The note is payable over the next 5 years at
an imputed interest rate of 6.25%.
Southern Company has committed to fund at least 40% of Southern Power's
construction project financing and to pay for construction cost overruns to the
extent that Southern Power's own cash flow is insufficient. Also, Southern
Company will prepay any portion of revolving credit arrangements used for
Southern Power's construction projects not completed within two years of the
proposed completion date.
Financial Instruments
At December 31, 2002, Southern Power had $500 million notional amount of
interest rate swaps outstanding with deferred losses of $63 million as follows:
Cash Flow Hedges
Weighted Average Fair
Variable Fixed Value
Rate Rate Notional Gain
Maturity Received Paid Amount (Loss)
- ------------------------------------------------------------------
(in millions)
Southern
Power 2013 * 6.23% $350 $(50)
Southern
Power 2008 * 5.48 150 (13)
- ------------------------------------------------------------------
*Rate has not been set.
For the year 2002, approximately $0.9 million was reclassified from other
comprehensive income to interest expense. These reclassifications related to
losses incurred upon settlement of interest rate swaps associated with the
issuance of senior notes in June 2002. (See "Long-Term Debt" herein). For the
year 2003, approximately $1.7 million is expected to be reclassified.
In February 2003, the Company initiated a commercial paper program to fund
a portion of the construction costs of new plants. The Company's strategy is to
refinance such short-term borrowings with long-term securities following plant
completion. The amount of commercial paper will initially represent about 45% of
total debt, but is forecasted to decline to about 7% at year-end 2005 as
increasingly more construction costs are refinanced with long-term securities.
The Company's commercial paper program is supported by the Facility. The
Facility was structured to accommodate commercial paper, and the conditions that
Southern Power must meet to reserve against the Facility for a project-specific
commercial paper issue are the same as those for a regular draw on the Facility.
The Company is not likely to be restricted from making draws on the Facility to
repay any commercial paper coming due, as those conditions include
representations and warranties that do not contain any material adverse effect
clauses or creditworthiness measures.
II-273
NOTES (continued)
Southern Power Company 2002 Annual Report
8. QUARTERLY FINANCIAL DATA (UNAUDITED)
Summarized quarterly financial information for 2002 and 2001 is as follows:
Operating Operating
Quarter Ended Revenues Income Net Income
- ------------------------------------------------------------------
(in millions)
-----------------------------------------
March 2002 $ 19,299 $ 7,862 $ 4,455
June 2002 57,777 16,271 8,858
September 2002 136,195 45,298 27,329
December 2002 85,497 26,764 13,628
March 2001 $ - $ (107) $ (65)
June 2001 - (1,569) (949)
September 2001 14,604 7,056 5,957
December 2001 14,697 5,107 3,264
- ------------------------------------------------------------------
The Company's business is influenced by seasonal weather conditions. The
Company's revenues initiated in July 2001 with the transfer of Plant Dahlberg
and three related PPAs from Georgia Power.
II-274
SELECTED FINANCIAL AND OPERATING DATA 2001-2002
Southern Power Company 2002 Annual Report
- --------------------------------------------------------------------------------------------------------
2002 2001
- --------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Sales for resale - non-affiliates 114,919 26,390
Sales for resale - affiliates 183,111 2,906
- --------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 298,030 29,296
Other revenues 738 5
- --------------------------------------------------------------------------------------------------------
Total $298,768 $29,301
========================================================================================================
Net Income (in thousands) $54,270 $8,207
Return on Average Common Equity (percent) 8.94 3.51
Total Assets (in thousands) $2,085,976 $822,857
Gross Property Additions (in thousands) $1,214,677 $765,511
- --------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $746,604 $466,993
Long-term debt 955,879 293,205
- --------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $1,702,483 $760,198
========================================================================================================
Capitalization Ratios (percent):
Common stock equity 43.9 61.4
Long-term debt 56.1 38.6
- --------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0
========================================================================================================
Security Ratings:
Unsecured Long-Term Debt -
Moody's Baa1 -
Standard and Poor's BBB+ -
Fitch BBB+ -
========================================================================================================
Kilowatt-Hour Sales (in thousands):
Sales for resale - non-affiliates 1,240,290 164,926
Sales for resale - affiliates 3,607,107 69,307
- --------------------------------------------------------------------------------------------------------
Total 4,847,397 234,233
========================================================================================================
Average Revenue Per Kilowatt-Hour (cents): 6.15 12.51
Plant Available Capacity
Ratings (year-end) (megawatts) 2,408 800
Maximum Peak-Hour Demand (megawatts):
Winter 949 -
Summer 1,426 -
Annual Load Factor (percent) 51.1 -
Plant Availability (percent): 95.1 83.7
Source of Energy Supply (percent):
Gas 77.4 100.0
Purchased power -
From non-affiliates 5.9 -
From affiliates 16.7 -
- --------------------------------------------------------------------------------------------------------
Total 100.0 100.0
========================================================================================================
II-275
PART III
Items 10, 11, 12 and 13 for Southern Company are incorporated by reference in
Southern Company's definitive Proxy Statement relating to the 2003 Annual
Meeting of Stockholders. Specifically, reference is made to "Nominees for
Election as Directors" for Item 10, "Executive Compensation" for Item 11, "Stock
Ownership Table" for Item 12 and "Certain Relationships and Related
Transactions" for Item 13 for Southern Company.
Additionally, Items 10, 11, 12 and 13 for Alabama Power, Georgia Power,
Gulf Power and Mississippi Power are incorporated by reference to the
Information Statements of Alabama Power, Georgia Power, Gulf Power and
Mississippi Power relating to each of their respective 2003 Annual Meetings of
Shareholders. Specifically, reference is made to "Nominees for Election as
Directors" for Item 10, "Executive Compensation Information" for Item 11, "Stock
Ownership Table" for Item 12 and "Certain Relationships and Related
Transactions" for Item 13.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS
The ages of directors and executive officers set forth below are as of December
31, 2002.
SAVANNAH ELECTRIC
Identification of directors of Savannah Electric.
Anthony R. James
President and Chief Executive Officer
Age 52
Served as Director since 5-3-01
Gus H. Bell, III (1)
Age 65
Served as Director since 7-20-99
Archie H. Davis (1)
Age 61
Served as Director since 2-18-97
Walter D. Gnann (1)
Age 67
Served as Director since 5-17-83
Robert B. Miller, III (1)
Age 57
Served as Director since 5-17-83
Arnold M. Tenenbaum (1)
Age 66
Served as Director since 5-17-77
(1) No position other than Director.
Each of the above is currently a director of Savannah Electric, serving a
term running from the last annual meeting of Savannah Electric's stockholder
(May 2, 2002) for one year until the next annual meeting or until a successor is
elected and qualified.
There are no arrangements or understandings between any of the individuals
listed above and any other person pursuant to which he was or is to be selected
as a director or nominee, other than any arrangements or understandings with
directors or officers of Savannah Electric acting solely in their capacities as
such.
Identification of executive officers of
Savannah Electric.
Anthony R. James
President, Chief Executive Officer and Director
Age 52
Served as Executive Officer since 7-27-00
W. Miles Greer
Vice President
Age 59
Served as Executive Officer since 11-20-85
Sandra R. Miller
Vice President
Age 50
Served as Executive Officer since 7-26-01
Kirby R. Willis
Vice President, Treasurer and
Chief Financial Officer
Age 51
Served as Executive Officer since 1-1-94
Each of the above is currently an executive officer of Savannah Electric,
serving a term running from the meeting of the directors held on July 25, 2002
for the ensuing year.
There are no arrangements or understandings between any of the individuals
listed above and any other person pursuant to which he or she was or is to be
selected as an officer, other than any arrangements or understandings with
officers of Savannah Electric acting solely in their capacities as such.
III-1
Identification of certain significant employees.
None.
Family relationships.
None.
Business experience.
Anthony R. James - President and Chief Executive Officer since 2001. Previously
served as Vice President of Power Generation and Senior Production Officer from
2000 to 2001; Central Cluster Manager at Georgia Power's Plant Scherer from 2000
to 2001; and Plant Manager at Georgia Power's Plant Scherer from 1996 to 2000.
He is a 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 since 1986. He is a
director of SunTrust Bank of Savannah.
Archie H. Davis - President, Chief Executive Officer and Director of Savannah
Bancorp, Inc., Savannah, Georgia since 1990 and Vice Chairman and a director
of The Savannah Bank, N.A. since January 2003. Previously served as Chief
Executive Officer of The Savannah Bank, N.A. from 2002 to 2003 and as President
and Chief Executive Officer of The Savannah Bank, N.A. from 1990 to 2002.
He is a director of Bryan Bank and Trust, Savannah, Georgia.
Walter D. Gnann - President of Walt's TV, Appliance and Furniture Co., Inc.,
Springfield, Georgia since 1958.
Robert B. Miller, III - President of American Building Systems, Inc. (general
contracting services), Savannah, Georgia since 1992.
Arnold M. Tenenbaum - President and Director of Chatham Steel Corporation
(specializing in carbon, stainless and specialty steel), Savannah, Georgia since
January 2001. Previously served as President and Chief Executive Officer of
Chatham Steel Corporation from 1981 to 2001. He serves on the advisory board of
Wachovia Bank, Savannah, Georgia.
W. Miles Greer - Vice President of Customer Operations and External Affairs
since 1998. Previously served as Vice President of Marketing and Customer
Service from 1994 to 1998.
Sandra R. Miller - Vice President of Power Generation since 2001. Previously
served as Manager of Technical Training at SCS from 1998 to 2001 and Group
Leader at Georgia Power's Plant Bowen from June 1996 to June 1998.
Kirby R. Willis - Vice President, Treasurer and Chief Financial Officer since
1994 and Assistant Corporate Secretary since 1998.
Involvement in certain legal proceedings.
None.
Section 16(a) Beneficial Ownership Reporting
Compliance.
No reporting person of Savannah Electric failed to file, on a timely basis,
the reports required by Section 16(a).
III-2
SOUTHERN POWER
Identification of directors of Southern Power.
W. Paul Bowers
President and Chief Executive Officer
Age 46
Served as Director since 5-1-01
H. Allen Franklin (1)
Age 58
Served as Director since 1-8-01
Gale E. Klappa (1)
Age 52
Served as Director since 5-8-01
Charles D. McCrary (1)
Age 51
Served as Director since 2-11-02 and also
served as Director from 1-8-01 to 4-16-01
David M. Ratcliffe (1)
Age 54
Served as Director since 1-8-01
(1) Each of the above is employed within the Southern Company system; however,
each holds no position at Southern Power other than Director.
Each of the above is currently a director of Southern Power, serving a term
running from the last annual meeting of Southern Power's stockholder (April 29,
2002) for one year until the next annual meeting or until a successor is elected
and qualified.
There are no arrangements or understandings between any of the individuals
listed above and any other person pursuant to which he was or is to be selected
as a director or nominee, other than any arrangements or understandings with
directors or officers of Southern Power acting solely in their capacities as
such.
Identification of executive officers of
Southern Power.
W. Paul Bowers
President and Chief Executive Officer
Age 46
Served as Executive Officer since 5-1-01
Robert G. Moore
Senior Vice President
Age 53
Served as Executive Officer since 1-4-02
Cliff S. Thrasher
Senior Vice President, Comptroller and
Chief Financial Officer
Age 52
Served as Executive Officer since 6-10-02
Anthony J. Topazi
Senior Vice President
Age 52
Served as Executive Officer since 3-1-01
Each of the above is currently an executive officer of Southern Power,
serving a term running from the meeting of the directors held on May 9, 2002 for
the ensuing year, except for Mr. Thrasher whose election was effective on the
date indicated.
There are no arrangements or understandings between any of the individuals
listed above and any other person pursuant to which he was or is to be selected
as an officer, other than any arrangements or understandings with officers of
Southern Power acting solely in their capacities as such.
Identification of certain significant employees.
None.
Family relationships.
None.
III-3
Business experience.
W. Paul Bowers - President, Chief Executive Officer and Director since May 2001;
Executive Vice President of SCS since May 2001. Previously served as Senior Vice
President of SCS and Chief Marketing Officer of Southern Company from March 2000
to May 2001; President and Chief Executive Officer of Western Power
Distribution, a subsidiary of Mirant located in Bristol, England from December
1998 to 2000; and Senior Vice President of Retail Marketing for Georgia Power
from 1995 to 1998.
H. Allen Franklin - Chairman, President and Chief Executive Officer of Southern
Company since April 2001. Previously served as President and Chief Executive
Officer from March 2001 to April 2001; President and Chief Operating Officer of
Southern Company from June 1999 to March 2001; and Executive Vice President of
Southern Company and President and Chief Executive Officer of Georgia Power from
January 1994 to June 1999. He is a director of SouthTrust Corporation, Vulcan
Materials Company, and Southern System companies - Southern Company, Alabama
Power, Georgia Power and Gulf Power.
Gale E. Klappa - Executive Vice President, Chief Financial Officer and Treasurer
of Southern Company since May 2001. Previously served as Financial Vice
President, Chief Financial Officer and Treasurer of Southern Company from March
2001 to May 2001; Senior Vice President and Chief Strategic Officer of Southern
Company from October 1999 to March 2001; President of Mirant's North America
Group and Senior Vice President of Mirant from December 1998 to October 1999;
and President and Chief Executive Officer of Western Power Distribution, a
subsidiary of Mirant located in Bristol, England, from September 1995 to
December 1998.
Charles D. McCrary - Executive Vice President of Southern Company since February
2002 and President and Chief Executive Officer of Alabama Power since October
2001. Previously served as President and Chief Operating Officer of Alabama
Power from April 2001 to October 2001; Vice President of Southern Company from
February 1998 to April 2001; and Executive Vice President of Alabama Power from
April 1994 to February 1998. He is a director of Alabama Power and AmSouth
Banccorporation.
David M. Ratcliffe - Executive Vice President of Southern Company since 1999 and
President and Chief Executive Officer of Georgia Power since June 1999.
Previously served as Executive Vice President, Treasurer and Chief Financial
Officer of Georgia Power from March 1998 to June 1999; and Senior Vice President
of Southern Company from March 1995 to March 1998. He is a director of Georgia
Power; Mississippi Chemical Company; Federal Reserve Bank of Atlanta and CSX
Corporation.
Robert G. Moore - Senior Vice President since January 2002 and Vice President of
SCS since August 1997. Previously served as Vice President of Gulf Power from
July 1997 to May 2002.
Cliff S. Thrasher - Senior Vice President, Comptroller and Chief Financial
Officer of Southern Power since November 2002 and Vice President of SCS since
June 2002. Previously served as Vice President, Comptroller and Chief Financial
Officer of Southern Power from June 2002 to November 2002 and Vice President,
Comptroller and Chief Accounting Officer of Georgia Power from September 1995 to
June 2002.
Anthony J. Topazi - Senior Vice President since November 2002 and Vice President
of SCS since December 1999. Previously served as Vice President of Southern
Power from March 2001 until November 2002 and Vice President of Alabama Power
from March 1991 to December 1999.
Section 16(a) Beneficial Ownership Reporting
Compliance.
Not applicable.
III-4
Item 11. EXECUTIVE COMPENSATION
Summary Compensation Table. The following table sets forth information
concerning any Chief Executive Officer and the three most highly compensated
executive officers of Savannah Electric serving during 2002.
ANNUAL COMPENSATION LONG-TERM COMPENSATION
---------------------- -------------------------------------
Number of
Securities Long-
Name Restricted Underlying Term
and Other Annual Stock Stock Incentive All Other
Principal Compensation Award Options Payouts Compensation
Position Year Salary($) Bonus($) ($)1 ($) (Shares) ($)2 ($)3
- -------------------------------------------------------------------------------------------------------------------------
Anthony R. James 4
President, Chief 2002 235,748 189,044 13,109 - 35,354 136,462 12,235
Executive Officer, 2001 210,856 177,858 1,328 - 31,363 87,577 30,195
Director 2000 175,048 161,442 - - 12,752 23,144 7,582
W. Miles Greer 2002 191,400 101,796 107 - 14,278 115,884 20,261
Vice President 2001 184,066 104,286 666 - 32,505 105,924 8,567
2000 177,013 100,923 601 - 13,416 26,434 16,982
Kirby R. Willis
Vice President, 2002 175,476 93,329 891 - 13,090 61,913 13,283
Chief Financial 2001 168,747 100,480 490 - 29,993 89,814 8,495
Officer, Treasurer 2000 162,279 97,394 4,908 - 8,785 24,565 12,159
Sandra R. Miller 5 2002 138,074 104,769 1,720 - 10,317 18,824 7,016
Vice President 2001 112,802 83,015 8,123 - 1,896 4,791 20,749
2000 - - - - - - -
- ---------------------------------------------
1 Tax reimbursement on certain personal benefits.
2 Payout of performance dividend equivalents on stock options granted after 1996
that were held by the executive at the end of the performance periods under the
Omnibus Incentive Compensation Plan for the four-year performance periods ended
December 31, 2000, 2001, and 2002, respectively. Dividend equivalents can range
from 25 percent of the common stock dividend paid during the last year of the
performance period if total shareholder return over the four-year period,
compared to a group of other large utility companies, is at the 30th percentile
to 100 percent of the dividend paid if it reaches the 90th percentile. The
Southern Company Compensation and Management Succession Committee can increase
the payout of performance dividends by up to 200 percent if necessary to
maintain the competitiveness of Southern Company's executive compensation
program. For eligible stock options held on December 31, 2000, 2001, and 2002,
all named executives received a payout of $.90, $1.34, and $1.355 per option,
respectively. The payout was not increased by the Committee.
3 Contributions in 2002 to the Employee Savings Plan (ESP), Employee Stock
Ownership Plan (ESOP) and Supplemental Benefit Plan (SBP) or Above-Market
Earnings on deferred compensation (AME) are as follows:
Name ESP ESOP SBP or AME
- ---- --- ---- ----------
Anthony R. James $7,696 $701 $3,838
W. Miles Greer 7,750 701 11,810
Kirby R. Willis 6,211 701 6,371
Sandra R. Miller 5,420 701 895
4 Mr. James became President and Chief Executive Officer effective May 1, 2001.
5 Ms. Miller became an executive officer of Savannah Electric on July 26, 2001.
III-5
Summary Compensation Table. The following table sets forth information
concerning any Chief Executive Officer and the four most highly compensated
executive officers of Southern Power serving during 2002.
ANNUAL COMPENSATION LONG-TERM COMPENSATION
------------------- ----------------------------------------
Number of
Securities Long-
Name Restricted Underlying Term
and Other Annual Stock Stock Incentive All Other
Principal Compensation Award Options Payouts Compensation
Position Year Salary($) Bonus($) ($)6 ($) (Shares) ($)7 ($)8
- --------------------------------------------------------------------------------------------------------------------------
W. Paul Bowers
President, Chief
Executive Officer, 2002 329,570 403,433 12,337 - 50,046 214,133 16,802
Director 2001 273,758 273,630 3,072 - 51,740 160,515 39,542
Anthony J. Topazi 2002 249,389 262,399 3,218 - 29,229 173,966 64,274
Senior Vice President 2001 237,095 185,293 112,839 - 49,800 145,178 213,144
Robert G. Moore 9 2002 217,233 206,785 2,820 - 20,835 111,206 13,396
Senior Vice President 2001 - - - - - - -
Carson B. Harreld, Jr. 10
Vice President, Comptroller 2002 215,014 189,839 1,352 - 17,265 109,251 32,293
& Chief Financial Officer 2001 204,132 123,944 811 - 47,616 143,735 110,053
Cliff S. Thrasher 9 2002 187,200 175,560 52,852 - 13,443 79,394 59,640
Senior Vice President, 2001 - - - - - - -
Comptroller & Chief
Financial Officer
- --------------------------
6 Tax reimbursement on certain personal benefits.
7 Payout of performance dividend equivalents on stock options granted after 1996
that were held by the executive at the end of the performance periods under the
Omnibus Incentive Compensation Plan for the four-year performance periods ended
December 31, 2000, 2001, and 2002, respectively. Dividend equivalents can range
from 25 percent of the common stock dividend paid during the last year of the
performance period if total shareholder return over the four-year period,
compared to a group of other large utility companies, is at the 30th percentile
to 100 percent of the dividend paid if it reaches the 90th percentile. The
Southern Company Compensation and Management Succession Committee can increase
the payout of performance dividends by up to 200 percent if necessary to
maintain the competitiveness of Southern Company's executive compensation
program. For eligible stock options held on December 31, 2000, 2001, and 2002,
all named executives received a payout of $.90, $1.34, and $1.355 per option,
respectively. The payout was not increased by the Committee.
8 Contributions in 2002 to the Employee Savings Plan (ESP), Employee Stock
Ownership Plan (ESOP), Supplemental Benefit Plan (SBP) and tax sharing benefits
paid to participants who elected receipt of dividends on Southern Company's
common stock held in the ESP are as follows:
Name ESP ESOP SBP ESP Tax Sharing Benefits
- ---- --- ---- --- ------------------------
W. Paul Bowers $7,701 $701 $8,400 $ -
Anthony J. Topazi 7,709 701 5,864 -
Robert G. Moore 7,683 701 2,886 2,626
Carson B. Harreld, Jr. 6,965 701 3,505 1,122
Cliff S. Thrasher 7,421 701 1,518 -
In 2002, these amounts include additional incentive compensation of $50,000
each for Mr. Topazi and Mr. Thrasher and $20,000 for Mr. Harreld. In 2001,
these amounts included additional incentive compensation for Messrs. Bowers,
Topazi and Harreld of $24,380, $200,000 and $100,000 respectively.
9 Mr. Moore became an executive officer of Southern Power in January 2002 and
Mr. Thrasher became an executive officer of Southern Power in June 2002.
10 Mr.Harreld ceased to be an executive officer of Southern Power effective
June 9, 2002. On May 28, 2002, he was elected Senior Vice President of SCS.
III-6
STOCK OPTION GRANTS IN 2002
Stock Option Grants. The following table sets forth all stock option grants to
the named executive officers of Savannah Electric and Southern Power during the
year ending December 31, 2002.
Individual Grants Grant Date Value
# of % of Total
Securities Options Exercise
Underlying Granted to or
Options Employees in Base Price Expiration Grant Date
Name Granted11 Fiscal Year12 ($/Sh)11 Date11 Present Value($)13
-------------------------------------------------------------------------------------------------------------
Savannah Electric
Anthony R. James 35,354 24.3 25.26 2/15/2012 119,143
W. Miles Greer 14,278 9.8 25.26 2/15/2012 48,117
Kirby R. Willis 13,090 9.0 25.26 2/15/2012 44,113
Sandra R. Miller 10,317 7.1 25.26 2/15/2012 34,768
Southern Power
W. Paul Bowers 50,046 1.6 25.26 2/15/2012 168,655
Anthony J. Topazi 29,229 1.0 25.26 2/15/2012 98,502
Robert G. Moore 20,835 0.7 25.26 2/15/2012 70,214
Carson B. Harreld, Jr. 17,265 0.6 25.26 2/15/2012 58,183
Cliff S. Thrasher 13,443 0.4 25.26 2/15/2012 45,269
- ------------------------------------------
11 Under the terms of the Omnibus Incentive Compensation Plan, stock option
grants were made on February 15, 2002 and vest annually at a rate of one-third
on the anniversary date of the grant. Grants fully vest upon termination as a
result of death, total disability or retirement and expire five years after
retirement, three years after death or total disability or their normal
expiration date if earlier. The exercise price is the average of the high and
low price of Southern Company's common stock on the date granted. Options may be
transferred to certain family members, family trusts and family limited
partnerships.
12 A total of 145,454 and 3,034,278 stock options were granted in
2002 to Savannah Electric and SCS, respectively. Southern Power has no
employees; therefore, SCS employees perform work on behalf of Southern Power
that is billed, at cost, to Southern Power.
13 Value was calculated using the Black-Scholes option valuation model. The
actual value, if any, ultimately realized depends on the market value of
Southern Company's common stock at a future date. Significant assumptions are
shown below:
Risk-free Dividend Expected
Volatility rate of return Yield Term
- ------------------------------------------------------------------
26.34% 2.79% 4.63% 4.28 years
- ------------------------------------------------------------------
III-7
AGGREGATED STOCK OPTION EXERCISES IN 2002 AND YEAR-END OPTION VALUES
Aggregated Stock Option Exercises. The following table sets forth information
concerning options exercised during the year ending December 31, 2002 by the
named executive officers and the value of unexercised options held by them as of
December 31, 2002.
Number of Securities Underlying Value of Unexercised
Unexercised Options at Fiscal In-the-Money Options
Year-End (#) At Year-End ($)14
------------------------------------------------------------------
Shares
Acquired on Value
Name Exercise (#) Realized ($)15 Exercisable Unexercisable Exercisable Unexercisable
- --------------------------------------------------------------------------------------------------------------------------
Savannah Electric
Anthony R. James - - 37,712 62,998 343,294 367,505
W. Miles Greer 7,803 90,452 42,488 43,035 479,011 309,143
Kirby R. Willis 34,423 352,882 7,967 37,725 92,642 258,703
Sandra R. Miller - - 1,752 12,140 20,620 50,492
Southern Power
W. Paul Bowers 11,801 156,131 63,861 94,171 727,111 551,603
Anthony J. Topazi 9,183 131,114 56,374 72,014 626,634 477,002
Robert G. Moore 15,247 188,410 33,374 48,697 375,465 321,306
Carson B. Harreld, Jr. 43,902 479,578 22,532 58,096 195,523 414,870
Cliff S. Thrasher 24,391 269,007 18,728 39,865 173,835 271,157
- ---------------------------
14 This column represents the excess of the fair market value of Southern
Company's common stock of $28.39 per share, as of December 31, 2002, 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, 2002.
15 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 above the exercise price.
III-8
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 non-qualified supplemental benefits, based on the stated
compensation and years of service with the Southern system for all named
executive officers of Savannah Electric and Southern Power, except for Messrs.
Greer and Willis. Compensation for pension purposes is limited to the average of
the highest three of the final 10 years' compensation. Compensation is base
salary plus the excess of annual incentive compensation over 15 percent of base
salary. These compensation components are reported under columns titled "Salary"
and "Bonus" in the Summary Compensation Tables on pages III-5 and III-6.
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, 2002, the applicable compensation levels and years of
accredited service are presented in the following tables:
Savannah Electric
Compensation Accredited
Name Level Years of Service
---- ----- ----------------
Anthony R. James $350,806 23
W. Miles Greer16 258,424 26
Kirby R. Willis 240,171 28
Sandra R. Miller 187,416 22
Southern Power
Compensation Accredited
Name Level Years of Service
---- ----- ----------------
W. Paul Bowers $528,397 22
Anthony J. Topazi 414,272 32
Robert G. Moore 331,584 28
Carson B. Harreld, Jr.17 349,358 29
Cliff S. Thrasher 287,468 31
- ------------------------------
16 The number of accredited years of service includes 7 years and 6 months
credited to Mr. Greer pursuant to a supplemental pension agreement.
17 The number of accredited years of service includes 10 years credited to
Mr. Harreld pursuant to a supplemental pension agreement.
III-9
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 or computation of Social Security offset that would apply
in most cases.
In 1998, Savannah Electric merged its pension plan into the Southern
Company Pension Plan. Savannah Electric 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 Company'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 Company's pension and Savannah Electric's supplemental
executive retirement plans in effect during 2002 which are payable to Messrs.
Greer and Willis, 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
- -------------------------- -- -- --
$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
350,000 245,000 245,000 245,000
400,000 280,000 280,000 280,000
430,000 301,000 301,000 301,000
460,000 322,000 322,000 322,000
Compensation of Directors.
- --------------------------
Standard Arrangements. The following table presents compensation paid to
Savannah Electric's directors during 2002 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. At the election of the director, all or a portion of the cash
retainer may be payable in Southern Company's common stock, and all or a portion
of the total fees may be deferred under the Deferred Compensation Plan until
membership on the board is terminated.
Cash Retainer Fee $10,000
Stock Retainer Fee 85 shares per quarter
Meeting Fee $750 for each Board or Committee meeting attended
Southern Power's directors are all employed within the Southern Company
system and receive no fees or compensation for service as a member of Southern
Power's board of directors.
Other Arrangements. No director received other compensation for services as
a director during the year ending December 31, 2002 in addition to or in lieu of
that specified by the standard arrangements specified above.
III-10
Employment Contracts and Termination of Employment and Change in Control
Arrangements.
- ------------------------------------------------------------------------
Southern Power's executive officers are employees of SCS. Savannah Electric and
SCS have adopted Southern Company'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 Savannah Electric, SCS or Southern Company, 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, stock appreciation rights and
restricted stock 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 any individual agreements.
A change in control is defined under the agreements as:
o acquisition of at least 20 percent of the Southern Company's stock,
o a change in the majority of the members of the Southern Company's board of
directors,
o a merger or other business combination that results in Southern Company'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 Company.
A change in control of Savannah Electric is defined under the agreements as:
o acquisition of at least 50 percent of Savannah Electric's stock,
o a merger or other business combination unless Southern Company controls the
surviving entity or
o a sale of substantially all the assets of Savannah Electric.
Southern Company 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.
Mr. W. Miles Greer and Savannah Electric entered into agreements that
provide for a monthly payment to Mr. Greer after his retirement equal to the
difference between the amount he will receive under the Southern Company Pension
Plan and Savannah Electric Supplemental Executive Retirement Plan and the amount
he would receive under those Plans had he been employed by Savannah Electric an
additional seven years and six months under the Pension Plan and an additional
eight years under the Supplemental Executive Retirement Plan.
Mr. Carson B. Harreld, Jr. and Georgia Power, Southern Company and SCS
entered into an agreement that provides for a monthly payment to Mr. Harreld
after his retirement equal to the difference between the amount he will receive
under the Southern Company Pension Plan and the amount he would receive under
the Plan had he been employed by the Southern Company system an additional 10
years.
Report on Repricing of Options.
- -------------------------------
None.
Compensation Committee Interlocks and Insider Participation.
- ------------------------------------------------------------
None.
III-11
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Security Ownership of Certain Beneficial Owners. Southern Company is the
beneficial owner of 100% of the outstanding common stock of Savannah Electric
and Southern Power.
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:
Savannah Electric 10,844,635
Southern Power 1,000
Security Ownership of Management. The following table shows the number of shares
of Southern Company Common stock owned by the directors, nominees and executive
officers as of December 31, 2002. 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 outstanding on December 31, 2002.
Shares Beneficially
Owned Include:
Name of Directors, Shares Shares Individuals
Nominees and Beneficially Have Rights to Acquire
Executive Officers Title of Class Owned (1) Within 60 days (2)
- ------------------ -------------- ----------- ---------------------
Savannah Electric
Gus H. Bell, III Southern Company Common 273 -
Archie H. Davis Southern Company Common 682 -
Walter D. Gnann Southern Company Common 9,702 -
Anthony R. James Southern Company Common 76,441 62,164
Robert B. Miller, III Southern Company Common 5,233 -
Arnold M. Tenenbaum Southern Company Common 1,209 -
W. Miles Greer Southern Company Common 65,019 60,004
Sandra R. Miller Southern Company Common 7,287 6,196
Kirby R. Willis Southern Company Common 27,402 22,168
The directors, nominees
and executive officers
as a group Southern Company Common 193,248 150,532
III-12
Shares Beneficially
Owned Include:
Name of Directors, Shares Shares Individuals
Nominees and Beneficially Have Rights to Acquire
Executive Officers Title of Class Owned (1) Within 60 days (2)
- ------------------ -------------- ----------- -----------------------
Southern Power
W. Paul Bowers Southern Company Common 105,348 98,696
H. Allen Franklin Southern Company Common 786,517 747,185
Gale E. Klappa Southern Company Common 159,116 134,656
Charles D. McCrary Southern Company Common 177,749 174,711
David M. Ratcliffe Southern Company Common 253,807 241,461
Robert G. Moore Southern Company Common 66,868 52,668
Cliff S. Thrasher Southern Company Common 36,872 33,148
Anthony J. Topazi Southern Company Common 94,854 84,061
The directors, nominees
and executive officers
as a group Southern Company Common 1,681,131 1,566,586
(1) As used in the tables, "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) Indicates shares of Southern Company common stock that directors and
executive officers have the right to acquire within 60 days.
Changes in control. Southern Company, Savannah Electric and Southern Power know
of no arrangements which may at a subsequent date result in any change in
control.
III-13
Equity Compensation Plan Information
The following table provides information as of December 31, 2002 concerning
shares of Southern Company common stock authorized for issuance under Southern
Company's existing non-qualified equity compensation plans.
Number of securities to Weighted-average Number of securities remaining
be issued upon exercise exercise price of available for future issuance under
of outstanding options, outstanding options, equity compensation plans (excluding
warrants and rights warrants and rights securities reflected in column (a))
Plan category (a) (b) (c)
- ------------------------------------------------------------------------------------------------------------------------
Equity compensation plans
approved by security
holders 32,675,731 $19.72 48,559,919 (1)
- ------------------------------------------------------------------------------------------------------------------------
Equity compensation plans
not approved by security
holders N/A N/A N/A
- ------------------------------------------------------------------------------------------------------------------------
(1) Includes securities available for future issuance under the Omnibus
Incentive Compensation Plan (46,789,131) and the Outside Directors Stock
Plans (1,770,788).
III-14
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
SAVANNAH ELECTRIC
Transactions with management and others.
Mr. Archie Davis is currently Vice Chairman of The Savannah Bank, N.A.,
Savannah, Georgia and was also President and Chief Executive Officer prior to
January 2003. Messrs. James and Bell are directors of SunTrust Bank of
Savannah. During 2002, these banks furnished a number of regular banking
services in the ordinary course of business to Savannah Electric. Savannah
Electric 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.
SOUTHERN POWER
Transactions with management and others.
None.
Certain business relationships.
None.
Indebtedness of management.
None.
Transactions with promoters.
None.
ITEM 14. CONTROLS AND PROCEDURES
(a) Evaluation of disclosure controls and procedures.
Within 90 days of the filing date of this annual report, Southern Company,
the operating companies and Southern Power conducted separate evaluations under
the supervision and with the participation of each company's management,
including the Chief Executive Officer and the Chief Financial Officer, of the
effectiveness of the design and operation of the disclosure controls and
procedures (as defined in Sections 13a-14(c) and 15d-14(c) of the Securities
Exchange Act of 1934). Based upon those evaluations, the Chief Executive Officer
and the Chief Financial Officer, in each case, concluded that the disclosure
controls and procedures are effective in alerting them in a timely manner to
material information relating to each company (including its consolidated
subsidiaries) required to be included in periodic filings with the SEC.
(b) Changes in internal controls.
There have been no significant changes in Southern Company's, the
operating companies' or Southern Power's internal controls or in other factors
that could significantly affect these internal controls subsequent to the date
each company carried out its evaluation.
III-15
PART IV
Item 15. 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:
Independent Auditors' Reports on the financial statements for Southern
Company and Subsidiary Companies, Alabama Power, Georgia Power, Gulf
Power, Mississippi Power, Savannah Electric and Southern Power are
listed under Item 8 herein.
The financial statements filed as a part of this report for Southern
Company and Subsidiary Companies, Alabama Power, Georgia Power, Gulf
Power, Mississippi Power, Savannah Electric and Southern Power are
listed under Item 8 herein.
Reports of Independent Public Accountants on the financial statements
for Southern Company and Subsidiary Companies, Alabama Power, Georgia
Power, Gulf Power, Mississippi Power and Savannah Electric are listed
under Item 8 herein.
(2) Financial Statement Schedules:
Independent Auditors' Reports as to Schedules for Southern Company and
Subsidiary Companies, Alabama Power, Georgia Power, Gulf Power,
Mississippi Power, Savannah Electric and Southern Power are included
herein on pages IV-23, IV-25, IV-27, IV-29, IV-31, IV-33 and IV-35.
Financial Statement Schedules for Southern Company and Subsidiary
Companies, Alabama Power, Georgia Power, Gulf Power, Mississippi Power,
Savannah Electric and Southern Power are listed in the Index to the
Financial Statement Schedules at page S-1.
Reports of Independent Public Accountants as to Schedules for Southern
Company and Subsidiary Companies, Alabama Power, Georgia Power, Gulf
Power, Mississippi Power and Savannah Electric are included herein on
pages IV-24, IV-26, IV-28, IV-30, IV-32 and IV-34.
(3) Exhibits:
Exhibits for Southern Company, Alabama Power, Georgia Power, Gulf
Power, Mississippi Power, Savannah Electric and Southern Power are
listed in the Exhibit Index at page E-1.
(b) Reports on Form 8-K during the fourth quarter of 2002 were as follows:
Southern Company filed a Current Report on
Form 8-K:
Date of event: November 25, 2002
Item reported: 5
Alabama Power filed Current Reports on Form 8-K:
Date of event: October 16, 2002
Items reported: 5 and 7
Date of event: November 20, 2002
Items reported: 5 and 7
Date of event: December 6, 2002
Items reported: 5 and 7
Georgia Power filed Current Reports on Form 8-K:
Date of event: October 30, 2002
Items reported: 5 and 7
Date of event: November 15, 2002
Items reported: 5 and 7
Gulf Power filed a Current Report on Form 8-K:
Date of event: December 5, 2002
Items reported: 5 and 7
Savannah Electric filed a Current Report on
Form 8-K:
Date of event: November 4, 2002
Items reported: 5 and 7
IV-1
THE SOUTHERN COMPANY
SIGNATURES
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: H. Allen Franklin, Chairman, President and
Chief Executive Officer
By: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 7, 2003
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities and on the dates indicated. The signature of each of the
undersigned shall be deemed to relate only to matters having reference to the
above-named company and any subsidiaries thereof.
H. Allen Franklin
Chairman, President and
Chief Executive Officer
(Principal Executive Officer)
Gale E. Klappa
Executive Vice President, Chief Financial Officer and
Treasurer
(Principal Financial Officer)
W. Dean Hudson
Comptroller and Chief Accounting Officer
(Principal Accounting Officer)
Directors:
Daniel P. Amos Donald M. James
Dorrit J. Bern Zack T. Pate
Thomas F. Chapman J. Neal Purcell
L. G. Hardman III Gerald J. St. Pe'
By: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 7, 2003
IV-2
THE SOUTHERN COMPANY
Certification Of Chief Executive Officer Per Section 302 Of
The Sarbanes-Oxley Act
I, Allen Franklin, certify that:
1. I have reviewed this annual report on Form 10-K of The Southern Company;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have: a)
designed such disclosure controls and procedures to ensure that material
information relating to the registrant,
including its consolidated subsidiaries, is made known to us by others
within those entities, particularly during the period in which this
annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of
the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent functions): a) all significant deficiencies in the design or
operation of internal controls which could adversely affect the
registrant's ability to record, process, summarize and report financial
data and have identified for the registrant's auditors any material
weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officer and I have indicated in this
annual report whether there were significant changes in internal controls
or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any
corrective actions with regard to significant deficiencies and material
weaknesses.
Date: March 7, 2003 /s/ Allen Franklin
-----------------------------------
Allen Franklin
Chairman and Chief Executive Officer
IV-3
THE SOUTHERN COMPANY
Certification Of Chief Financial Officer Per Section 302 Of
The Sarbanes-Oxley Act
I, Gale E. Klappa, certify that:
1. I have reviewed this annual report on Form 10-K of The Southern Company;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have: a)
designed such disclosure controls and procedures to ensure that material
information relating to the registrant,
including its consolidated subsidiaries, is made known to us by others
within those entities, particularly during the period in which this
annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of
the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent functions): a) all significant deficiencies in the design or
operation of internal controls which could adversely affect the
registrant's ability to record, process, summarize and report financial
data and have identified for the registrant's auditors any material
weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officer and I have indicated in this
annual report whether there were significant changes in internal controls
or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any
corrective actions with regard to significant deficiencies and material
weaknesses.
Date: March 7, 2003 /s/ Gale E. Klappa
-----------------------------------
Gale E. Klappa
Executive Vice President, Chief Financial Officer and Treasurer
IV-4
ALABAMA POWER COMPANY
SIGNATURES
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: Charles D. McCrary, President and
Chief Executive Officer
By: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 7, 2003
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.
Charles D. McCrary
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 Mayer Mitchell
David J. Cooper Robert D. Powers
H. Allen Franklin C. Dowd Ritter
R. Kent Henslee James H. Sanford
Carl E. Jones, Jr. John Cox Webb, IV
Patricia M. King James W. Wright
James K. Lowder
Wallace D. Malone, Jr.
By: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 7, 2003
IV-5
ALABAMA POWER COMPANY
Certification Of Chief Executive Officer Per Section 302 Of
The Sarbanes-Oxley Act
I, Charles D. McCrary, certify that:
1. I have reviewed this annual report on Form 10-K of Alabama Power Company;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have: a)
designed such disclosure controls and procedures to ensure that material
information relating to the registrant,
including its consolidated subsidiaries, is made known to us by others
within those entities, particularly during the period in which this
annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of
the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent functions): a) all significant deficiencies in the design or
operation of internal controls which could adversely affect the
registrant's ability to record, process, summarize and report financial
data and have identified for the registrant's auditors any material
weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officer and I have indicated in this
annual report whether there were significant changes in internal controls
or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any
corrective actions with regard to significant deficiencies and material
weaknesses.
Date: March 7, 2003 /s/ Charles D. McCrary
-----------------------------------
Charles D. McCrary
President and Chief Executive Officer
IV-6
ALABAMA POWER COMPANY
Certification Of Chief Financial Officer Per Section 302 Of
The Sarbanes-Oxley Act
I, William B. Hutchins, III, certify that:
1. I have reviewed this annual report on Form 10-K of Alabama Power Company;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have: a)
designed such disclosure controls and procedures to ensure that material
information relating to the registrant,
including its consolidated subsidiaries, is made known to us by others
within those entities, particularly during the period in which this
annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of
the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent functions): a) all significant deficiencies in the design or
operation of internal controls which could adversely affect the
registrant's ability to record, process, summarize and report financial
data and have identified for the registrant's auditors any material
weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officer and I have indicated in this
annual report whether there were significant changes in internal controls
or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any
corrective actions with regard to significant deficiencies and material
weaknesses.
Date: March 7, 2003 /s/ William B. Hutchins, III
-----------------------------------
William B. Hutchins, III
Executive Vice President, Chief Financial Officer and Treasurer
IV-7
GEORGIA POWER COMPANY
SIGNATURES
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 7, 2003
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)
Allen L. Leverett
Executive Vice President, Chief Financial Officer
and Treasurer
(Principal Financial Officer)
W. Ron Hinson
Vice President, Comptroller and Chief Accounting Officer
(Principal Accounting Officer)
Directors:
Juanita P. Baranco Richard W. Ussery
Anna R. Cablik William Jerry Vereen
H. Allen Franklin Carl Ware
L. G. Hardman III E. Jenner Wood, III
G. Joseph Prendergast
By: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 7, 2003
IV-8
GEORGIA POWER COMPANY
Certification Of Chief Executive Officer Per Section 302 Of
The Sarbanes-Oxley Act
I, David M. Ratcliffe, certify that:
1. I have reviewed this annual report on Form 10-K of Georgia Power Company;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have: a)
designed such disclosure controls and procedures to ensure that material
information relating to the registrant,
including its consolidated subsidiaries, is made known to us by others
within those entities, particularly during the period in which this
annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of
the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent functions): a) all significant deficiencies in the design or
operation of internal controls which could adversely affect the
registrant's ability to record, process, summarize and report financial
data and have identified for the registrant's auditors any material
weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officer and I have indicated in this
annual report whether there were significant changes in internal controls
or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any
corrective actions with regard to significant deficiencies and material
weaknesses.
Date: March 7, 2003 /s/ David M. Ratcliffe
-----------------------------------
David M. Ratcliffe
President and Chief Executive Officer
IV-9
GEORGIA POWER COMPANY
Certification Of Chief Financial Officer Per Section 302 Of
The Sarbanes-Oxley Act
I, Allen L. Leverett, certify that:
1. I have reviewed this annual report on Form 10-K of Georgia Power Company;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have: a)
designed such disclosure controls and procedures to ensure that material
information relating to the registrant,
including its consolidated subsidiaries, is made known to us by others
within those entities, particularly during the period in which this
annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of
the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent functions): a) all significant deficiencies in the design or
operation of internal controls which could adversely affect the
registrant's ability to record, process, summarize and report financial
data and have identified for the registrant's auditors any material
weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officer and I have indicated in this
annual report whether there were significant changes in internal controls
or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any
corrective actions with regard to significant deficiencies and material
weaknesses.
Date: March 7, 2003 /s/ Allen L. Leverett
-----------------------------------
Allen L. Leverett
Executive Vice President, Chief Financial Officer and Treasurer
IV-10
GULF POWER COMPANY
SIGNATURES
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: Thomas A. Fanning, President and
Chief Executive Officer
By: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 7, 2003
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.
Thomas A. Fanning
President, Chief Executive Officer and Director
(Principal Executive Officer)
Ronnie R. Labrato
Vice President, Chief Financial Officer and Comptroller
(Principal Financial and Accounting Officer)
Directors:
C. LeDon Anchors H. Allen Franklin
William C. Cramer, Jr. William A. Pullum
Fred C. Donovan, Sr. Joseph K. Tannehill
By: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 7, 2003
IV-11
GULF POWER COMPANY
Certification Of Chief Executive Officer Per Section 302 Of
The Sarbanes-Oxley Act
I, Thomas A. Fanning, certify that:
1. I have reviewed this annual report on Form 10-K of Gulf Power Company;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have: a)
designed such disclosure controls and procedures to ensure that material
information relating to the registrant,
including its consolidated subsidiaries, is made known to us by others
within those entities, particularly during the period in which this
annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of
the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent functions): a) all significant deficiencies in the design or
operation of internal controls which could adversely affect the
registrant's ability to record, process, summarize and report financial
data and have identified for the registrant's auditors any material
weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officer and I have indicated in this
annual report whether there were significant changes in internal controls
or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any
corrective actions with regard to significant deficiencies and material
weaknesses.
Date: March 7, 2003 /s/ Thomas A. Fanning
-----------------------------------
Thomas A. Fanning
President and Chief Executive Officer
IV-12
GULF POWER COMPANY
Certification Of Chief Financial Officer Per Section 302 Of
The Sarbanes-Oxley Act
I, Ronnie R. Labrato, certify that:
1. I have reviewed this annual report on Form 10-K of Gulf Power Company;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have: a)
designed such disclosure controls and procedures to ensure that material
information relating to the registrant,
including its consolidated subsidiaries, is made known to us by others
within those entities, particularly during the period in which this
annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of
the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent functions): a) all significant deficiencies in the design or
operation of internal controls which could adversely affect the
registrant's ability to record, process, summarize and report financial
data and have identified for the registrant's auditors any material
weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officer and I have indicated in this
annual report whether there were significant changes in internal controls
or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any
corrective actions with regard to significant deficiencies and material
weaknesses.
Date: March 7, 2003 /s/ Ronnie R. Labrato
-----------------------------------
Ronnie R. Labrato
Vice President, Chief Financial Officer and Comptroller
IV-13
MISSISSIPPI POWER COMPANY
SIGNATURES
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: Michael D. Garrett, President and
Chief Executive Officer
By: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 7, 2003
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.
Michael D. Garrett
President, Chief Executive Officer and Director
(Principal Executive Officer)
Michael W. Southern
Vice President, Treasurer and
Chief Financial Officer
(Principal Financial and Accounting Officer)
Directors:
Tommy E. Dulaney George A. Schloegel
Robert C. Khayat Philip J. Terrell
Aubrey K. Lucas Gene Warr
By: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 7, 2003
IV-14
MISSISSIPPI POWER COMPANY
Certification Of Chief Executive Officer Per Section 302 Of
The Sarbanes-Oxley Act
I, Michael D. Garrett, certify that:
1. I have reviewed this annual report on Form 10-K of Mississippi Power
Company;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have: a)
designed such disclosure controls and procedures to ensure that material
information relating to the registrant,
including its consolidated subsidiaries, is made known to us by others
within those entities, particularly during the period in which this
annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of
the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent functions): a) all significant deficiencies in the design or
operation of internal controls which could adversely affect the
registrant's ability to record, process, summarize and report financial
data and have identified for the registrant's auditors any material
weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officer and I have indicated in this
annual report whether there were significant changes in internal controls
or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any
corrective actions with regard to significant deficiencies and material
weaknesses.
Date: March 7, 2003 /s/ Michael D. Garrett
-----------------------------------
Michael D. Garrett
President and Chief Executive Officer
IV-15
MISSISSIPPI POWER COMPANY
Certification Of Chief Financial Officer Per Section 302 Of
The Sarbanes-Oxley Act
I, Michael W. Southern, certify that:
1. I have reviewed this annual report on Form 10-K of Mississippi Power
Company;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have: a)
designed such disclosure controls and procedures to ensure that material
information relating to the registrant,
including its consolidated subsidiaries, is made known to us by others
within those entities, particularly during the period in which this
annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of
the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent functions): a) all significant deficiencies in the design or
operation of internal controls which could adversely affect the
registrant's ability to record, process, summarize and report financial
data and have identified for the registrant's auditors any material
weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officer and I have indicated in this
annual report whether there were significant changes in internal controls
or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any
corrective actions with regard to significant deficiencies and material
weaknesses.
Date: March 7, 2003 /s/ Michael W. Southern
-----------------------------------
Michael W. Southern
Vice President, Chief Financial Officer and Treasurer
IV-16
SAVANNAH ELECTRIC AND POWER COMPANY
SIGNATURES
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: Anthony R. James, President and
Chief Executive Officer
By: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 7, 2003
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.
Anthony R. James
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 7, 2003
IV-17
SAVANNAH ELECTRIC AND POWER COMPANY
Certification Of Chief Executive Officer Per Section 302 Of
The Sarbanes-Oxley Act
I, Anthony R. James, certify that:
1. I have reviewed this annual report on Form 10-K of Savannah Electric and
Power Company;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have: a)
designed such disclosure controls and procedures to ensure that material
information relating to the registrant,
including its consolidated subsidiaries, is made known to us by others
within those entities, particularly during the period in which this
annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of
the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent functions): a) all significant deficiencies in the design or
operation of internal controls which could adversely affect the
registrant's ability to record, process, summarize and report financial
data and have identified for the registrant's auditors any material
weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officer and I have indicated in this
annual report whether there were significant changes in internal controls
or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any
corrective actions with regard to significant deficiencies and material
weaknesses.
Date: March 7, 2003 /s/ Anthony R. James
-----------------------------------
Anthony R. James
President and Chief Executive Officer
IV-18
SAVANNAH ELECTRIC AND POWER COMPANY
Certification Of Chief Financial Officer Per Section 302 Of
The Sarbanes-Oxley Act
I, Kirby R. Willis, certify that:
1. I have reviewed this annual report on Form 10-K of Savannah Electric and
Power Company;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have: a)
designed such disclosure controls and procedures to ensure that material
information relating to the registrant,
including its consolidated subsidiaries, is made known to us by others
within those entities, particularly during the period in which this
annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of
the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent functions): a) all significant deficiencies in the design or
operation of internal controls which could adversely affect the
registrant's ability to record, process, summarize and report financial
data and have identified for the registrant's auditors any material
weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officer and I have indicated in this
annual report whether there were significant changes in internal controls
or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any
corrective actions with regard to significant deficiencies and material
weaknesses.
Date: March 7, 2003 /s/ Kirby R. Willis
-----------------------------------
Kirby R. Willis
Vice President, Chief Financial Officer and Treasurer
IV-19
SOUTHERN POWER COMPANY
SIGNATURES
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.
SOUTHERN POWER COMPANY
By: William P. Bowers, President and
Chief Executive Officer
By: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 7, 2003
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.
William P. Bowers
President, Chief Executive Officer and Director
(Principal Executive Officer)
Cliff S. Thrasher
Senior Vice President, Comptroller and
Chief Financial Officer
(Principal Financial and Accounting Officer)
Directors:
H. Allen Franklin Charles D. McCrary
Gale E. Klappa David M. Ratcliffe
By: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 7, 2003
IV-20
SOUTHERN POWER COMPANY
Certification Of Chief Executive Officer Per Section 302 Of
The Sarbanes-Oxley Act
I, William P. Bowers, certify that:
1. I have reviewed this annual report on Form 10-K of Southern Power Company;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have: a)
designed such disclosure controls and procedures to ensure that material
information relating to the registrant,
including its consolidated subsidiaries, is made known to us by others
within those entities, particularly during the period in which this
annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of
the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent functions): a) all significant deficiencies in the design or
operation of internal controls which could adversely affect the
registrant's ability to record, process, summarize and report financial
data and have identified for the registrant's auditors any material
weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officer and I have indicated in this
annual report whether there were significant changes in internal controls
or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any
corrective actions with regard to significant deficiencies and material
weaknesses.
Date: March 7, 2003 /s/ William P. Bowers
-----------------------------------
William P. Bowers
President and Chief Executive Officer
IV-21
SOUTHERN POWER COMPANY
Certification Of Chief Financial Officer Per Section 302 Of
The Sarbanes-Oxley Act
I, Cliff S. Thrasher, certify that:
1. I have reviewed this annual report on Form 10-K of Southern Power Company;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have: a)
designed such disclosure controls and procedures to ensure that material
information relating to the registrant,
including its consolidated subsidiaries, is made known to us by others
within those entities, particularly during the period in which this
annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of
the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent functions): a) all significant deficiencies in the design or
operation of internal controls which could adversely affect the
registrant's ability to record, process, summarize and report financial
data and have identified for the registrant's auditors any material
weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officer and I have indicated in this
annual report whether there were significant changes in internal controls
or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any
corrective actions with regard to significant deficiencies and material
weaknesses.
Date: March 7, 2003 /s/ Cliff S. Thrasher
-----------------------------------
Cliff S. Thrasher
Senior Vice President, Comptroller and Chief Financial Officer
IV-22
Deloitte & Touche LLP
191 Peachtree Street, NE
Suite 1500
Atlanta, Georgia 30303-1924
www.deloitte.com
Deloitte
& Touche
INDEPENDENT AUDITORS' REPORT
To the Board of Directors and Stockholders of
Southern Company:
We have audited the consolidated financial statements of Southern Company and
Subsidiary Companies as of and for the year ended December 31, 2002, and have
issued our report thereon dated February 17, 2003; such consolidated financial
statement and report are included elsewhere in this Form 10-K. Our audit also
included the consolidated financial statement schedule of Southern Company and
Subsidiary Companies (page S-2) listed in the accompanying index at Item 15.
This financial statement schedule is the responsibility of Southern Company's
management. Our responsibility is to express an opinion based on our audit. The
consolidated financial statement schedules of Southern Company and Subsidiary
Companies as of December 31, 2001 and 2000 and for the two years then ended were
audited by other auditors who have ceased operations. Those auditors expressed
an unqualified opinion on those consolidated financial statement schedules, when
considered in relation to the basic consolidated financial statements taken as a
whole, in their report dated February 13, 2002. In our opinion, the consolidated
financial statement schedule as of and for the year ended December 31, 2002,
when considered in relation to the basic consolidated financial statements taken
as a whole, presents fairly in all material respects the information set forth
therein.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
February 17, 2003
IV-23
THIS IS A COPY OF THE REPORT PREVIOUSLY ISSUED IN CONNECTION WITH THE SOUTHERN
COMPANY'S 2001 ANNUAL REPORT AND HAS NOT BEEN REISSUED BY 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 13, 2002. 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 13, 2002
IV-24
Deloitte & Touche LLP
Suite 1000
417 North 20th Street
Birmingham, Alabama 35203-3289
www.deloitte.com
Deloitte
& Touche
INDEPENDENT AUDITORS' REPORT
Alabama Power Company:
We have audited the financial statements of Alabama Power Company as of and for
the year ended December 31, 2002, and have issued our report thereon dated
February 17, 2003; such financial statements and report are included elsewhere
in this Form 10-K. Our audit also included the financial statement schedule of
Alabama Power Company (page S-3) listed in the accompanying index at Item 15.
This financial statement schedule is the responsibility of Alabama Power
Company's management. Our responsibility is to express an opinion based on our
audit. The financial statement schedules of Alabama Power Company as of
December 31, 2001 and 2000 and for the two years then ended were audited by
other auditors who have ceased operations. Those auditors expressed an
unqualified opinion on those financial statement schedules, when considered in
relation to the basic financial statements taken as a whole, in their report
dated February 13, 2002. In our opinion, the financial statement schedule as
of and for the year ended December 31, 2002, when considered in relation to the
basic financial statements taken as a whole, presents fairly in all material
respects the information set forth therein.
/s/ Deloitte & Touche LLP
Birmingham, Alabama
February 17, 2003
IV-25
THIS IS A COPY OF THE REPORT PREVIOUSLY ISSUED IN CONNECTION WITH ALABAMA POWER
COMPANY'S 2001 ANNUAL REPORT AND HAS NOT BEEN REISSUED BY 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 13, 2002. 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 13, 2002
IV-26
Deloitte & Touche LLP
191 Peachtree Street, NE
Suite 1500
Atlanta, Georgia 30303-1924
www.deloitte.com
Deloitte
& Touche
INDEPENDENT AUDITORS' REPORT
Georgia Power Company:
We have audited the financial statements of Georgia Power Company as of and for
the year ended December 31, 2002, and have issued our report thereon dated
February 17, 2003; such financial statements and report are included elsewhere
in this Form 10-K. Our audit also included the financial statement schedule of
Georgia Power Company (page S-4) listed in the accompanying index at Item 15.
This financial statement schedule is the responsibility of Georgia Power
Company's management. Our responsibility is to express an opinion based on our
audit. The financial statement schedules of Georgia Power Company as of
December 31, 2001 and 2000 and for the two years then ended were audited by
other auditors who have ceased operations. Those auditors expressed an
unqualified opinion on those financial statement schedules, when considered in
relation to the basic financial statements taken as a whole, in their report
dated February 13, 2002. In our opinion, the financial statement schedule as of
and for the year ended December 31, 2002, when considered in relation to the
basic financial statements taken as a whole, presents fairly in all material
respects the information set forth therein.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
February 17, 2003
IV-27
THIS IS A COPY OF THE REPORT PREVIOUSLY ISSUED IN CONNECTION WITH GEORGIA POWER
COMPANY'S 2001 ANNUAL REPORT AND HAS NOT BEEN REISSUED BY 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 13, 2002.
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 13, 2002
IV-28
Deloitte & Touche LLP
191 Peachtree Street, NE
Suite 1500
Atlanta, Georgia 30303-1924
www.deloitte.com
Deloitte
& Touche
INDEPENDENT AUDITORS' REPORT
Gulf Power Company:
We have audited the financial statements of Gulf Power Company as of and for the
year ended December 31, 2002, and have issued our report thereon dated February
17, 2003; such financial statements and report are included elsewhere in this
Form 10-K. Our audit also included the financial statement schedule of Gulf
Power Company (page S-5) listed in the accompanying index at Item 15. This
financial statement schedule is the responsibility of Gulf Power Company's
management. Our responsibility is to express an opinion based on our
audit. The financial statement schedules of Gulf Power Company as of December
31, 2001 and 2000 and for the two years then ended were audited by other
auditors who have ceased operations. Those auditors expressed an unqualified
opinion on those financial statement schedules, when considered in relation to
the basic financial statements taken as a whole, in their report
dated February 13, 2002. In our opinion, the financial statement schedule as of
and for the year ended December 31, 2002, when considered in relation to the
basic financial statements taken as a whole, presents fairly in all material
respects the information set forth therein.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
February 17, 2003
IV-29
THIS IS A COPY OF THE REPORT PREVIOUSLY ISSUED IN CONNECTION WITH GULF POWER
COMPANY'S 2001 ANNUAL REPORT AND HAS NOT BEEN REISSUED BY 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 13, 2002. 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 13, 2002
IV-30
Deloitte & Touche LLP
191 Peachtree Street, NE
Suite 1500
Atlanta, Georgia 30303-1924
www.deloitte.com
Deloitte
& Touche
INDEPENDENT AUDITORS' REPORT
Mississippi Power Company:
We have audited the financial statements of Mississippi Power Company as of and
for the year ended December 31, 2002, and have issued our report thereon dated
February 17, 2003; such financial statements and report are included elsewhere
in this Form 10-K. Our audit also included the financial statement schedule of
Mississippi Power Company (page S-6) listed in the accompanying index at Item
15. This financial statement schedule is the responsibility of Mississippi
Power Company's management. Our responsibility is to express an opinion based
on our audit. The financial statement schedules of Mississippi Power Company as
of December 31, 2001 and 2000 and for the two years then ended were audited by
other auditors who have ceased operations. Those auditors expressed an
unqualified opinion on those financial statement schedules, when considered in
relation to the basic financial statements taken as a whole, in their report
dated February 13, 2002. In our opinion, the financial statement schedule as of
and for the year ended December 31, 2002, when considered in relation to the
basic financial statements taken as a whole, presents fairly in all material
respects the information set forth therein.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
February 17, 2003
IV-31
THIS IS A COPY OF THE REPORT PREVIOUSLY ISSUED IN CONNECTION WITH MISSISSIPPI
POWER COMPANY'S 2001 ANNUAL REPORT AND HAS NOT BEEN REISSUED BY 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
13, 2002. 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 13, 2002
IV-32
Deloitte & Touche LLP
191 Peachtree Street, NE
Suite 1500
Atlanta, Georgia 30303-1924
www.deloitte.com
Deloitte
& Touche
INDEPENDENT AUDITORS' REPORT
Savannah Electric and Power Company:
We have audited the financial statements of Savannah Electric and Power Company
as of and for the year ended December 31, 2002, and have issued our report
thereon dated February 17, 2003; such financial statements and report are
included elsewhere in this Form 10-K. Our audit also included the financial
statement schedule of Savannah Electric and Power Company (page S-7) listed in
the accompanying index at Item 15. This financial statement schedule is the
responsibility of Savannah Electric and Power Company's management. Our
responsibility is to express an opinion based on our audit. The financial
statement schedules of Savannah Electric and Power Company as of December 31,
2001 and 2000 and for the two years then ended were audited by other auditors
who have ceased operations. Those auditors expressed an unqualified opinion on
those financial statement schedules, when considered in relation to the basic
financial statements taken as a whole, in their report dated February 13, 2002.
In our opinion, the financial statement schedule as of and for the year ended
December 31, 2002, when considered in relation to the basic financial statements
taken as a whole, presents fairly in all material respects the information set
forth therein.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
February 17, 2003
IV-33
THIS IS A COPY OF THE REPORT PREVIOUSLY ISSUED IN CONNECTION WITH SAVANNAH
ELECTRIC AND POWER COMPANY'S 2001 ANNUAL REPORT AND HAS NOT BEEN REISSUED BY
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 13, 2002. 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 13, 2002
IV-34
Deloitte & Touche LLP
191 Peachtree Street, NE
Suite 1500
Atlanta, Georgia 30303-1924
www.deloitte.com
Deloitte
& Touche
INDEPENDENT AUDITORS' REPORT
Southern Power Company:
We have audited the financial statements of Southern Power Company as of
December 31, 2002 and 2001, and for the year ended December 31, 2002 and for the
period from January 8, 2001 (inception) to December 31, 2001, and have issued
our report thereon dated February 17, 2003; such financial statements and
report are included elsewhere in this Form 10-K. Our audits also included the
financial statement schedules of Southern Power Company (page S-8) listed in the
accompanying index at Item 15. These financial statement schedules are the
responsibility of Southern Power Company's management. Our responsibility is to
express an opinion based on our audits. In our opinion, such financial statement
schedules, when considered in relation to the basic financial statements taken
as a whole, present fairly in all material respects the information set forth
therein.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
February 17, 2003
IV-35
INDEX TO FINANCIAL STATEMENT SCHEDULES
Schedule Page
II Valuation and Qualifying Accounts and Reserves
2002, 2001 and 2000
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
Valuation and Qualifying Accounts and Reserves
2002 and 2001
Southern Power Company........................................ S-8
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, 2002, 2001 AND 2000
(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
2002..................... $24,383 $40,313 $5,961 (a) $45,111 (b) $25,546
2001..................... 21,799 44,272 269 41,957 (b) 24,383
2000..................... 21,834 31,329 39 31,403 (b) 21,799
- -------------------
(a) Included in this amount are uncollectible accounts acquired by Southern GAS through its June 2002 purchase of certain
assets of The New Power Company.
(b) Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off.
S-2
ALABAMA POWER COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
(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
2002...................... $5,237 $10,804 $- $11,214 (Note) $4,827
2001...................... 6,237 7,419 - 8,419 (Note) 5,237
2000...................... 4,117 9,093 - 6,973 (Note) 6,237
- -------------------
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, 2002, 2001 AND 2000
(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
2002.......................... $8,895 $14,117 $- $17,187 (Note) $5,825
2001.......................... 5,100 22,913 - 19,118 (Note) 8,895
2000.......................... 7,000 10,794 - 12,694 (Note) 5,100
- -------------------
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, 2002, 2001 AND 2000
(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
2002.......................... $1,342 $1,620 $- $2,073(Note) $ 889
2001.......................... 1,302 2,282 - 2,242(Note) 1,342
2000.......................... 1,026 2,702 - 2,426(Note) 1,302
- -------------------
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, 2002, 2001 AND 2000
(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
2002.......................... $856 $2,045 $ 7 $2,190 (Note) $718
2001.......................... 571 2,877 (165) 2,427 (Note) 856
2000.......................... 697 1,156 14 1,296 (Note) 571
- -------------------
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, 2002, 2001 AND 2000
(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
2002.......................... $500 $1,137 $- $955 (Note) $682
2001.......................... 407 978 - 885 (Note) 500
2000.......................... 237 999 - 829 (Note) 407
- -------------------
Note: Represents write-off of accounts receivable considered to be uncollectible, less recoveries of amounts previously written
off.
S-7
SOUTHERN POWER COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2002 AND 2001
(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
2002.......................... $- $350 $- $- $350
2001.......................... - - - - -
S-8