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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, 2003
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
Mandatorily redeemable
preferred securities, $25 liquidation amount
7.125% Trust Preferred Securities 2
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Class A preferred, cumulative, $25 stated capital Alabama Power Company
5.20% Series 5.83% Series
Senior Notes
6.75% Series J
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Senior Notes Georgia Power Company
6 5/8% Series D 5.90% Series O
6% Series R
Mandatorily redeemable preferred securities,
$25 liquidation amount
6.85% Trust Preferred Securities3
7 1/8% Trust Preferred Securities4
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Senior Notes Gulf Power Company
5.25% Series H
5.75% Series I
Mandatorily redeemable preferred securities,
$25 liquidation amount
7.375% Trust Preferred Securities5
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1 As of December 31, 2003.
2 Issued by Southern Company Capital Trust VI and guaranteed by The Southern
Company.
3 Issued by Georgia Power Capital Trust IV and guaranteed by Georgia Power
Company.
4 Issued by Georgia Power Capital Trust V and guaranteed by Georgia Power
Company.
5 Issued by Gulf Power Capital Trust III and guaranteed by Gulf Power
Company.
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Senior Notes Mississippi Power Company
5 5/8% Series E
Depositary preferred shares, each representing one-fourth
of a share of preferred stock, cumulative, $100 par value
6.32% Series 6.65% Series
Mandatorily redeemable preferred securities,
$25 liquidation amount
7.20% Trust Originated Preferred Securities 6
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Mandatorily redeemable preferred securities, Savannah Electric and Power Company
$25 liquidation amount
6.85% Trust Preferred Securities7
Securities registered pursuant to Section 12(g) of the Act: 8
Title of each class Registrant
- ------------------- ----------
Preferred stock, cumulative, $100 par value Alabama Power Company
4.20% Series 4.60% Series 4.72% Series
4.52% Series 4.64% Series 4.92% Series
Class A Preferred Stock, cumulative, $100,000 stated capital
Flexible Money Market (Series 2003A)
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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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6 Issued by Mississippi Power Capital Trust II and guaranteed by Mississippi Power Company.
7 Issued by Savannah Electric Capital Trust I and guaranteed by Savannah Electric and Power Company.
8 As of December 31, 2003.
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Indicate by check mark whether the registrants (1) have filed all
reports required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period that the
registrants were required to file such reports), and (2) have been subject to
such filing requirements for the past 90 days. Yes X No___
Indicate by check mark if disclosure of delinquent filers pursuant
to Item 405 of Regulation S-K is not contained herein, and will not be
contained, to the best of registrants' knowledge, in definitive proxy or
information statements incorporated by reference in Part III of this Form 10-K
or any amendment to this Form 10-K. ( )
Indicate by checkmark if the registrants are accelerated filers as
defined in Rule 12b-2 of the Securities Exchange Act of 1934.
Yes X No___
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Aggregate market value of voting and non-voting stock held by non-affiliates of The Southern Company at
June 30, 2003: $22.7 billion and at January 30, 2004: $21.9 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 January 31, 2004
- ---------- -------------- -------------------
The Southern Company Par Value $5 Per Share 735,504,409
Alabama Power Company Par Value $40 Per Share 7,250,000
Georgia Power Company Without Par Value 7,761,500
Gulf Power Company Without 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 2004 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 2004 Annual Meetings 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
Retail Operating Companies...................................................... I-2
Southern Power.................................................................. I-2
Other Business.................................................................. I-3
Mirant Corporation.............................................................. I-3
Risk Factors.................................................................... I-3
Construction Programs........................................................... I-10
Financing Programs.............................................................. I-12
Fuel Supply..................................................................... I-13
Territory Served by the Utilities............................................... I-14
Competition..................................................................... I-17
Regulation...................................................................... I-18
Rate Matters.................................................................... I-20
Employee Relations.............................................................. I-22
Item 2 Properties........................................................................ I-23
Item 3 Legal Proceedings................................................................. I-27
Item 4 Submission of Matters to a Vote of Security Holders............................... I-33
Executive Officers of Southern Company............................................ I-34
Executive Officers of Alabama Power............................................... I-36
Executive Officers of Georgia Power............................................... I-37
Executive Officers of Gulf Power.................................................. I-39
Executive Officers of Mississippi Power........................................... I-40
PART II
Item 5 Market for Registrants' Common Equity, Related Stockholder Matters and
Issuer Purchases of Equity Securities........................................... 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
Item 9A Controls and Procedures........................................................... II-6
PART III
Item 10 Directors and Executive Officers of the Registrants.............................. III-1
Item 11 Executive Compensation........................................................... III-6
Item 12 Security Ownership of Certain Beneficial Owners and
Management and Related Stockholder Matters..................................... III-13
Item 13 Certain Relationships and Related Transactions................................... III-15
Item 14 Principal Accountant Fees and Services........................................... III-16
PART IV
Item 15 Exhibits, Financial Statement Schedules, and Reports
on Form 8-K.................................................................... IV-1
Signatures....................................................................... IV-2
i
DEFINITIONS
When used in Items 1 through 5 and Items 9A 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
EITF.......................................... Emerging Issues Task Force of the Financial Accounting
Standards Board
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
FMPA.......................................... Florida Municipal Power Agency
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
IRC........................................... Internal Revenue Code
IRS........................................... Internal Revenue Service
ISA........................................... Independent System Administrator
JEA........................................... Jacksonville Electric Authority
KUA........................................... Kissimmee Utility 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
OUA........................................... Orlando Utilities Commission
PPA........................................... Power Purchase Agreement
PSC........................................... Public Service Commission
registrants................................... The Southern Company, Alabama Power Company, Georgia Power
Company, Gulf Power Company, Mississippi Power Company,
Savannah Electric and Power Company and Southern Power
Company
retail operating companies.................... Alabama Power Company, Georgia Power Company, Gulf Power Company,
Mississippi Power Company and Savannah Electric and Power
Company
ii
DEFINITIONS
(continued)
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
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 utilities, including Southern Company, the
work on which was suspended in December 2003
SMEPA......................................... South Mississippi Electric Power Association
Southern Company.............................. The Southern Company
Southern Company GAS.......................... Southern Company Gas LLC
Southern Company system....................... Southern Company, the retail operating companies,
Southern Power, SEGCO, Southern Nuclear, SCS,
Southern LINC, Southern Management Development,
Southern Company GAS and other subsidiaries
Southern Holdings............................. Southern Company Holdings, Inc.
Southern LINC................................. Southern Communications Services, Inc.
Southern Nuclear.............................. Southern Nuclear Operating Company, Inc.
Southern Power................................ Southern Power Company
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 statements
in addition tohistorical information. Forward-looking information includes,
among other things, statements concerning the strategic goals for Southern
Company's wholesale business, estimated construction and other expenditures and
Southern Company's projections for energy sales and its goals for future
generating capacity, dividend payout 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. The
registrants caution 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:
o 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, tax 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;
o current and future litigation, regulatory investigations, proceedings or
inquiries, including the pending EPA civil actions against certain Southern
Company subsidiaries and current IRS audits;
o the effects, extent and timing of the entry of additional competition in
the markets in which Southern Company's subsidiaries operate;
o the impact of fluctuations in commodity prices, interest rates and customer
demand;
o available sources and costs of fuels;
o ability to control costs;
o investment performance of Southern Company's employee benefit plans;
o advances in technology;
o state and federal rate regulations and pending and future rate cases and
negotiations;
o effects of and changes in political, legal and economic conditions and
developments in the United States, including the current soft economy;
o the performance of projects undertaken by the non-traditional business and
the success of efforts to invest in and develop new opportunities;
o internal restructuring or other restructuring options that may be pursued;
o 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;
o the ability of counterparties of Southern Company and its subsidiaries to
make payments as and when due;
o the ability to obtain new short- and long-term contracts with neighboring
utilities;
o the direct or indirect effect on Southern Company's business resulting from
the terrorist incidents on September 11, 2001, or any similar incidents or
responses to such incidents;
o financial market conditions and the results of financing efforts, including
Southern Company's and its subsidiaries' credit ratings;
o the ability of Southern Company and its subsidiaries to obtain additional
generating capacity at competitive prices;
o weather and other natural phenomena;
o the direct and indirect effects on Southern Company's business resulting
from the August 2003 power outage in the Northeast, or any similar
incidents;
o the effect of accounting pronouncements issued periodically by standard-
setting bodies; and
o other factors discussed elsewhere herein and in other reports filed by the
registrants from time to time with the SEC.
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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 retail operating companies supply electric
service in the states of Alabama, Georgia, Florida, Mississippi and Georgia,
respectively. More particular information relating to each of the retail
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
constructs, owns and manages Southern Company's competitive generation assets
and sells electricity at market-based rates in the wholesale market. Southern
Power is a corporation 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 Telecom, Southern
Holdings and other direct and indirect subsidiaries. Southern LINC provides
digital wireless communications services to Southern Company's retail 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 Telecom provides wholesale fiber
optic solutions to telecommunication providers in the Southeastern United
States. Southern Holdings is an intermediate holding subsidiary for Southern
Company's investments in leveraged leases and synthetic 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
Gaston to the Georgia state line at which point connection is made with the
Georgia Power transmission line system.
I-1
Reference is made to Note 10 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
Retail Operating Companies
The transmission facilities of each of the retail 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
retail 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 Utilities" herein.)
Operating contracts covering arrangements in effect with principal
neighboring utility systems provide for capacity exchanges, capacity purchases
and sales, transfers of economy energy and other similar transactions.
Additionally, the retail 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 retail 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 retail 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 retail 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 retail 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 each of the companies.
SCS has contracted with Southern Company, each retail operating company,
Southern Power, Southern Nuclear, SEGCO and other subsidiaries 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 Power,
Southern Company GAS, Southern LINC and Southern Telecom have also secured from
the retail operating companies certain services which are furnished at cost.
Southern Nuclear has contracts with Alabama Power to operate Plant Farley
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 with market-based
rates. Southern Power constructs, owns and manages generating facilities and
sells the output under long-term, fixed-price capacity contracts both to
unaffiliated wholesale purchasers as well as to the retail operating companies
(under PPAs approved by the respective PSCs). Southern Power's business
activities are not subject to traditional state regulation of utilities but are
subject to regulation by the FERC. 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
I-2
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. By the end of 2005, Southern Power plans to have
approximately 6,000 megawatts of available generating capacity in commercial
operation. At December 31, 2003, Southern Power had approximately 4,800
megawatts of generating capacity in commercial operation.
Other Business
In June 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. Southern Company GAS completed its acquisition out of bankruptcy
from The New Power Company (New Power) and began operations in July 2002.
Southern Company GAS also purchased proprietary risk management software and
hardware systems, natural gas inventory and accounts receivable from New Power.
The total purchase price was approximately $60 million. Southern Company GAS has
a 13.5% market share as of December 31, 2003.
Southern Holdings is an intermediate holding subsidiary for Southern
Company's investments in leveraged leases and synthetic fuel products, in
addition to Southern Company Energy Solutions LLC (SCES LLC), which provides
energy services.
In 1996, Southern LINC began serving Southern Company's retail 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 2001, MESH filed
an amended plan of reorganization, which the U. S. Bankruptcy Court confirmed in
September 2003. The plan became effective in late 2003, and Southern Company's
equity interest in MESH, which had been written off entirely prior to 2001, was
extinguished. 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
"Mirant Related Matters - Mobile Energy Services' Petition for Bankruptcy" for
additional information relating to this matter.
Mirant Corporation
In April 2001, the spin off of Mirant was completed. As a result of the spin
off, Southern Company's financial statements and related information reflect
Mirant as discontinued operations. Reference is made to Note 3 to the financial
statements of Southern Company in Item 8 herein under the heading "Mirant
Related Matters" for additional information regarding Mirant.
Risk Factors
In addition to the other information in this Form 10-K and other documents filed
by Southern Company and/or its subsidiaries with the SEC from time to time, the
following factors should be carefully 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,
I-3
hydroelectric and nuclear generating facilities. For example, the rates charged
to wholesale customers by the retail operating companies and by Southern Power
must be approved by the FERC. In addition, the respective state PSCs must
approve the retail 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 retail 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 retail 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
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, investigations by governmental
authorities into energy trading activities and the August 2003 power outage in
the Northeast, companies generally in the regulated and unregulated utility
businesses have been under an increased amount of public and regulatory scrutiny
with respect to, among other things, accounting practices, financial disclosures
and relationships with independent auditors. 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.
I-4
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 retail
operating companies. Increased competition could result in increased pressure to
lower the cost of electricity. Any adoption in the territories served by the
retail operating companies of retail competition and the unbundling of regulated
energy service could have a significant adverse financial impact on Southern
Company and the retail operating companies due to an impairment of assets, a
loss of retail customers, lower profit margins, an inability to recover
reasonable costs 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. In addition, in
April 2003, the FERC issued a White Paper in response to public comments
received on such proposed rulemaking on standard electricity market design.
Reactions to the White Paper by Southeastern state regulators reflect
significant continuing differences in opinion between the FERC and various state
regulatory commissions over questions of jurisdiction and protection of retail
customers. 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.
Southern Power currently has general authorization from the FERC to sell
power to nonaffiliates at market-based prices. In addition, each of the retail
operating companies has obtained FERC approval to sell power to nonaffiliates at
market-based prices under specific contracts. Southern Power and the retail
operating companies also have FERC authority to make short-term opportunity
sales at market rates. Specific FERC approval must be obtained with respect to a
market-based contract with an affiliate. In November 2001, the FERC modified the
test it uses to consider utilities' applications to charge market-based rates
and adopted a new test called the Supply Margin Assessment (SMA). The FERC
applied the SMA to several utilities, including Southern Company, and found
Southern Company and others to be "pivotal suppliers" in their service areas and
ordered the implementation of several mitigation measures. Southern Company and
others sought rehearing of the FERC order, and the FERC delayed the
implementation of certain mitigation measures. Southern Company and others
submitted comments to the FERC in 2002 regarding these issues. In December 2003,
the FERC issued a staff paper discussing alternatives and held a technical
conference in January 2004. Southern Company anticipates that the FERC will
address the requests for rehearing in the near future. Regardless of the outcome
of the SMA proposal, the FERC retains the ability to modify or withdraw the
authorization for any seller to sell at market-based rates, 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. The final outcome of this matter will depend on
the form in which the SMA test and mitigation measures' rules may be ultimately
adopted and cannot be determined at this time.
PPAs by Georgia Power and Savannah Electric for Southern Power's Plant
McIntosh capacity were certified by the Georgia PSC in December 2002 after a
I-5
competitive bidding process. In April 2003, Southern Power applied for FERC
approval of these PPAs. Interveners opposed the FERC's acceptance of the PPAs,
alleging that the PPAs do not meet the applicable standards for market-based
rates between affiliates. In July 2003, the FERC accepted the PPAs to become
effective as scheduled on June 1, 2005, subject to refund, and ordered that
hearings be held. For additional information, see Note 3 to the financial
statements of Southern Company, Georgia Power, Savannah Electric and Southern
Power under "FERC Matters" in Item 8 herein.
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 Title IV of the Clean
Air Act totaled approximately $400 million. Construction expenditures for
compliance with the nitrogen oxide emission reduction requirements totaled
approximately $980 million through 2003.
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 and electromagnetic fields have become more frequent.
Although the ultimate outcome of such litigation cannot be predicted, management
does not anticipate that the liabilities, if any, arising from such current
proceedings would have a material adverse effect on the financial statements of
Southern Company and its subsidiaries.
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 significant additional expense and 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. The cost impact of such legislation would depend
upon the specific requirements enacted and cannot be determined at this time.
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. In addition, the Holding
Company Act rules limit the dividends that Southern Company's subsidiaries may
pay from unearned surplus.
I-6
Southern Company's financial performance may be adversely affected if its
subsidiaries are unable to successfully operate their facilities.
Southern Company's financial performance depends on the successful
operation of its subsidiaries' electric generating, transmission and
distribution facilities. Operating these 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 terrorist attacks;
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.
Southern Company's revenues depend in part on sales under PPAs. The failure of a
counterparty to one of these PPAs to perform its obligations, or the failure to
renew the PPAs, could have a negative impact on Southern Company's earnings.
Most of Southern Power's generating capacity under construction, or
planned, has been sold to purchasers under PPAs having initial terms of five to
15 years. Southern Power's revenues are dependent on the continued performance
by the purchasers of their obligations under the PPAs. Even though Southern
Power has a rigorous credit evaluation, the failure of one of the purchasers to
perform its obligations could have a negative impact on Southern Power's
earnings. Although Southern Power's credit evaluations take into account the
possibility of default by a purchaser, Southern Power's actual exposure to a
default by a purchaser may be greater than Southern Power's credit evaluation
predicts. Further, while the PPAs are currently a substantial portion of
Southern Power's business, Southern Power cannot predict whether they will be
renewed at the end of their respective terms or on what terms any renewals may
be made. If a PPA is not renewed, Southern Power cannot predict whether it will
be replaced.
Southern Company and its subsidiaries may incur additional costs or delays in
power plant construction and may not be able to recover their investment.
Southern Company's facilities require ongoing capital expenditures.
Southern Power is in the process of constructing new generating facilities
and intends to continue its strategy of developing and constructing other new
facilities and expanding existing facilities. The completion of these facilities
without delays or cost overruns is subject to substantial risks, including:
o shortages and inconsistent quality of equipment, materials and
labor;
o work stoppages;
o permits, approvals and other regulatory matters;
o adverse weather conditions;
o unforeseen engineering problems;
o environmental and geological conditions;
o delays or increased costs to interconnect its facilities to
transmission grids;
o unanticipated cost increases; and
o attention to other projects.
If Southern Power is unable to complete the development or construction of
a facility, or if Southern Power decides to delay or cancel construction of a
facility, Southern Power may not be able to recover its investment in that
facility. In addition, construction delays and contractor performance shortfalls
can result in the loss of revenues and may, in turn, adversely affect Southern
Power's results of operations and financial position. Furthermore, if
construction projects are not completed according to specification, Southern
Power may incur liabilities and suffer reduced plant efficiency, higher
operating costs and reduced earnings.
Once facilities come into commercial operation, ongoing capital
expenditures are required to maintain reliable levels of operation.
I-7
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.
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 9.5% of Southern
Company's generation capacity as of December 31, 2003. 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 dispose of such 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 energy 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 energy 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;
I-8
o liquidity in the general wholesale electricity market;
o weather conditions impacting demand for electricity;
o seasonality;
o transmission or transportation constraints or inefficiencies;
o availability of competitively priced alternative energy sources;
o economy in the service territory;
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 retail operating companies, such increases may not be fully recoverable
through rates. Other of these factors could reduce Southern Company's revenues.
The use of derivative contracts by Southern Company and its subsidiaries in the
normal course of business could result in financial losses that negatively
impact the results of operations of Southern Company and its subsidiaries.
Southern Company and its subsidiaries use derivative instruments, such as
swaps, options, futures and forwards, to manage their commodity and financial
market risks and, to a lesser extent, engage in limited trading activities.
Southern Company and its subsidiaries could recognize financial losses as a
result of volatility in the market values of these contracts, or if a
counterparty fails to perform.
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 retail operating companies to pass all of these
purchase or construction costs on to their customers, the retail operating
companies may not be able to 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 retail operating companies' recovery
in customers' rates. Under Southern Power's long-term fixed price PPAs, Southern
Power 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
I-9
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;
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 were disrupted in general. 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. Any economic downturn or
disruption of financial markets could 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 expenditures during 2004 through 2006 by
the retail operating companies, Southern Power, SEGCO, SCS, Southern LINC and
other subsidiaries are estimated as follows:
------------------------------------------------------------
2004 2005 2006
--------------------------------
(in millions)
Alabama Power $ 791 $ 863 $ 884
Georgia Power 747 812 1,043
Gulf Power 166 149 108
Mississippi Power 80 70 98
Savannah Electric 52 43 41
Southern Power 259 254 356
SEGCO 13 9 7
SCS 27 24 20
Southern LINC 22 22 20
Other 7 3 2
------------------------------------------------------------
Southern Company system
$2,164 $2,249 $2,579
================================================================
Also included in the foregoing construction expenditure estimates are the
estimates for environmental expenditures. Reference is made to each registrant's
"Management Discussion and Analysis - Capital Requirements and Contractual
Obligations" in Item 7 herein for information on estimated environmental
expenditures.
I-10
Estimated construction costs in 2004 are expected to be apportioned approximately as follows: (in
millions)
---------------------------------------------------------------------------------------------------------------------------------
Southern Alabama Georgia Gulf Mississippi Savannah Southern Power
Company Power Power Power Power Electric
system*
----------------------------------------------------------------------------------------------------
New generation $ 259 $ - $ - $- $ - $- $259
Other generating
facilities including
associated plant
substations 646 324 169 101 29 11 -
New business 365 130 187 24 13 11 -
Transmission 342 128 167 18 13 15 -
Joint line and substation 56 - 48 4 4 - -
Distribution 221 110 70 12 16 13 -
Nuclear fuel 92 40 52 - - - -
General plant 183 59 54 7 5 2 -
----------------------------------------------------------------------------------------------------
$2,164 $791 $747 $166 $80 $52 $259
====================================================================================================
*SCS, Southern LINC and other businesses plan capital additions to general
plant in 2004 of $27 million, $22 million and $7 million, respectively, while
SEGCO plans capital additions of $12 million to generating facilities and $1
million to transmission 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; acquisition of additional generating
assets; 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.
Southern Company has approximately 1,200 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. Reference
is made to Note 3 to the financial statements of Southern Company, Georgia
Power, Savannah Electric and Southern Power in Item 8 herein under the heading
"FERC Matters" for additional information regarding contracts for this capacity.
In addition, capital improvements, including those needed to meet the
environmental standards previously discussed for the retail operating companies'
generation, transmission, and distribution facilities are ongoing.
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 and Note 3 to the financial statements of Southern Company in Item 8
herein under the heading "FERC Matters" for information regarding PPAs by
Georgia Power and Savannah Electric for Southern Power's Plant McIntosh
capacity.)
See Item 1 - BUSINESS - "Regulation - Environmental Statutes and
Regulations" 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-11
Financing Programs
The amount and timing of additional equity capital to be raised in 2004, 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 retail 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.
Southern Company and each retail operating company obtain financing
separately without credit support from any affiliate. Currently, Southern
Company provides limited credit support to Southern Power. Reference is made to
Note 6 to the financial statements of Southern Company and Southern Power in
Item 8 herein under the headings, "Bank Credit Arrangements" and "Parent Company
Transactions," respectively, for additional information. The Southern Company
system does not maintain a centralized cash or money pool. Therefore, funds of
each company are not commingled with funds of any other company. In accordance
with the Holding Company Act, most loans between affiliated companies must be
approved by the SEC.
Short-term debt is utilized as appropriate at Southern Company, the retail
operating companies 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, 2003
-------------- -------------------
(in millions)
Alabama Power $1,000(1) $ 0
Georgia Power 3,200(2) 137
Gulf Power 600(1) 38
Mississippi 500(1) 0
Power
Savannah 120(2) 20
Electric
Southern Power 2,500(3) 1,264
Southern 2,000(1) 259
Company
----------------------------------------------------
Notes:
(1) Alabama Power's authority is based on authorization received from the
Alabama PSC, which expires December 31, 2005. 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 January 1, 2007, 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 $75 million remaining authority for long-term debt and term loans expiring
December 31, 2005. At February 25, 2004, Georgia Power has $681 million
remaining refunding authority from the Georgia PSC expiring December 31, 2005.
Georgia Power also has Georgia PSC authority for borrowings under the term loan
provisions of its credit facilities of $725 million.
(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.
I-12
Reference is made to Note 6 to the financial statements for each of the
registrants under the heading "Bank Credit Arrangements" in Item 8 herein for
information regarding the registrants' bank credit arrangements.
Fuel Supply
The retail 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 2001 through 2003
are shown below:
Coal Nuclear Hydro Gas Oil
% % % % %
---------------------------------------------
Alabama Power
2001 64 18 6 12 *
2002 62 19 6 13 *
2003 64 19 8 9 *
Georgia Power
2001 75 23 1 1 *
2002 78 21 1 * *
2003 75 22 3 * *
Gulf Power
2001 99 ** ** 1 *
2002 82 ** ** 18 *
2003 87 ** ** 13 *
Mississippi Power
2001 59 ** ** 41 *
2002 57 ** ** 43 *
2003 74 ** ** 26 *
Savannah Electric
2001 93 ** ** 6 1
2002 91 ** ** 8 1
2003 94 ** ** 4 2
SEGCO
2001 100 ** ** * *
2002 100 ** ** * *
2003 100 ** ** * *
Southern Power
2001 ** ** ** 100 *
2002 ** ** ** 100 *
2003 ** ** ** 99 1
Southern Company system***
2001 72 16 3 9 *
2002 69 16 3 12 *
2003 71 16 4 9 *
- ------------------------------------------------------------------
* Less than 0.5%.
** Not applicable.
*** Amounts shown for the Southern Company system are weighted averages of the
retail operating companies, Southern Power and SEGCO.
The average costs of fuel in cents per net kilowatt-hour generated for 2001
through 2003 are shown below:
2001 2002 2003
-----------------------------------
Alabama Power 1.56 1.47 1.67
Georgia Power 1.38 1.42 1.46
Gulf Power 1.76 2.08 2.11
Mississippi Power 1.89 2.03 1.95
Savannah Electric 2.16 2.44 2.38
SEGCO 1.44 1.50 1.52
Southern Power 4.07 2.81 2.01
Southern Company
system* 1.56 1.61 1.72
- ------------------------------------------------------------------
* Amounts shown for the Southern Company system are weighted averages of
the retail operating companies, Southern Power and SEGCO.
I-13
The retail operating companies have long-term agreements in place from which
they expect to receive approximately 80% of their coal burn requirements in
2004. These agreements cover remaining terms up to 8 years. In 2003, the
weighted average sulfur content of all coal burned by the retail operating
companies was 0.75% sulfur. This sulfur level, along with banked sulfur dioxide
allowances, allowed the retail operating companies to remain within limits as
set forth by Phase II of the Clean Air Act. As 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
Regulations" herein.
The retail operating companies, Southern Power and Southern Company GAS also
have long-term agreements in place for their natural gas burn requirements. For
2004, the retail operating companies, Southern Power and Southern Company GAS
have contracted for 130 billion cubic feet of natural gas supply. These
agreements cover remaining terms up to 4 years. In addition to gas supply, the
retail 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 to the retail operating companies and Southern
Company GAS 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 2015. At Plant Hatch, an on-site dry storage
facility became operational in 2000 and can be expanded to accommodate spent
fuel through the life of the plant. Construction of an on-site dry storage
facility at Plant Farley is in progress and scheduled for operation in 2005.
Construction of an on-site dry storage facility 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. For
additional information, reference is made to Note 1 to the financial statements
of Southern Company, Alabama Power and Georgia Power in Item 8 herein under the
heading "Revenues and Fuel Costs."
Territory Served by the Utilities
The territory in which the retail 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 retail
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
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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
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.
Through the Southern Company system power pool, the retail operating
companies are also engaged in the transmission and sale of wholesale energy.
For information relating to kilowatt-hour sales by classification for the
retail operating companies, 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
retail operating companies and Southern Power, reference is made to Item 6
herein.
A portion of the area served by the retail 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 retail 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 1,776 megawatts of nameplate capacity, including an undivided
8.25% 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.
I-15
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.
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.
Starting in January 2005, 30 electric cooperative organizations served by
OPC will start purchasing a total of 700 megawatts of steam capacity from
Georgia Power under individual contracts for a 10 year term and starting in
April 2006, AMEA will start purchasing the 250 megawatts, currently being
purchased by OPC, for a 10 year term.
There are 65 municipally-owned electric distribution systems operating in
the territory in which the retail 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 6 to Alabama Power's financial statements under the heading "First Mortgage
Bonds" 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 134 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.)
SCS, acting on behalf of the retail operating companies, 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
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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.
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 2013.
In July 2003, Southern Power entered into a requirements service agreement
with Piedmont Municipal Power Agency (PMPA). PMPA is a full requirements
provider to 10 South Carolina cities. Under this agreement, Southern Power will
be responsible for supplying PMPA's capacity and energy needs in excess of
PMPA's existing resources and will purchase PMPA's surplus energy. The initial
contract term is for 5 years beginning in 2006 with mutual renewal options
through 2015.
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 allowed IPPs to access a utility's
transmission network in order to sell electricity to other utilities. 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 information.
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 2003, Alabama Power
purchased approximately 151.7 million kilowatt-hours from such companies at a
cost of $3.8 million.
I-17
Georgia Power currently has contracts in effect with nine small power
producers whereby Georgia Power purchases their excess generation. During 2003,
Georgia Power purchased 12.3 million kilowatt-hours from such companies at a
cost of $0.5 million. Georgia Power has PPAs for electricity with two
cogeneration facilities. Payments are subject to reductions for failure to meet
minimum capacity output. During 2003, Georgia Power purchased 545 million
kilowatt-hours at a cost of $77 million from these facilities. Reference is made
to Note 7 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 various industrial,
commercial and qualifying facilities pursuant to which Gulf Power purchases "as
available" energy from customer-owned generation. During 2003, Gulf Power
purchased 54 million kilowatt-hours from such companies for $1.3 million.
During 2003, 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 2003, Savannah
Electric purchased a total of 14 million kilowatt-hours from the six suppliers
at a cost of approximately $556 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 retail 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 Utilities" herein for information concerning suppliers
of electricity operating within or near the areas served at retail by the retail
operating companies.)
Regulation
State Commissions
The retail 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 Utilities" 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 retail operating companies, Southern Power
and SEGCO to regulation by the FERC as companies engaged in the transmission or
sale at wholesale of electric energy in interstate commerce, including
regulation of accounting policies and practices.
Alabama 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 1,608,550
kilowatts and 18 existing Georgia Power generating stations having an aggregate
installed capacity of 1,074,696 kilowatts.
I-18
Georgia Power filed a relicensing application with the FERC for the Middle
Chattahoochee project in December 2002 and is currently waiting for the FERC to
issue the public notice declaring that the application is ready for
environmental analysis. 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 and filed the Notice of Intent and Preliminary
Document required by FERC's Integrated Licensing Process on January 15, 2004.
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.
Alabama Power filed an application with the NRC in September 2003 to extend the
operating license for Plant Farley for an additional 20 years.
Reference is made to Notes 1 and 9 to Southern Company's financial
statements and Notes 1 and 8 to each of Alabama Power's financial statements
and Georgia Power's financial statements in Item 8herein 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
Reference is made to Southern Company, Alabama Power, Georgia Power, Gulf Power,
Mississippi Power, Savannah Electric and Southern Power, "Management's
Discussion and Analysis - Future Earnings Potential - FERC Matters" in Item 7
herein for information on matters regarding the FERC.
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 involves 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
I-19
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.
Additionally, each retail operating company and SEGCO has incurred costs
for environmental remediation of various sites. Reference is made to each
registrant's "Management's Discussion and Analysis - Financial Condition and
Liquidity" in Item 7 herein for information regarding the registrants'
environmental remediation efforts. Also, see Note 3 to the financial statements
of Southern Company, Georgia Power, Gulf Power and Mississippi Power in Item 8
herein under "Georgia Power Potentially Responsible Party Status," "Potentially
Responsible Party Status," "Environmental Cost Recovery" and "Potentially
Responsible Party Status," respectively, for information regarding the
identification of sites that may require environmental remediation.
The retail operating companies, Southern Power and SEGCO are unable to
predict at this time what additional steps they may be required to take as a
result of the implementation of existing or future quality control requirements
for air, water and hazardous or toxic materials, but such steps could adversely
affect system operations and result in substantial additional costs.
The outcome of the matters mentioned above under "Regulation" cannot now be
determined, except that these developments may result in delays in obtaining
appropriate licenses for generating facilities, increased construction and
operating costs or reduced generation, the nature and extent of which, while not
determinable at this time, could be substantial.
Rate Matters
Rate Structure
The rates and service regulations of the retail 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 retail 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.
On January 30, 2004, Georgia Power and Savannah Electric filed the 2004 IRP
with the Georgia PSC. In the 2004 IRP, Georgia Power requested the
de-certification of the Atkinson combustion turbine Units 5A and 5B totaling
approximately 80 megawatts of capacity. Plans for meeting Georgia Power's future
supply-side capacity needs identified in the 2004 IRP (2009 and beyond) will be
provided to the Georgia PSC in 2005. Georgia Power will also continue the
residential load management program, Power Credit, which was certified by the
Georgia PSC for up to 40 megawatts of equivalent supply-side capacity. Georgia
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Power will continue to utilize approximately 8 megawatts of capacity from
existing Qualifying Facilities under firm contracts and continue to add
additional resources as outlined in the Georgia PSC's Avoided Cost Order, Docket
No. 4822-U.
In December 2002, the Georgia PSC approved Georgia Power's and Savannah
Electric's 2005 certification and plant retirement request. The request was
filed June 7, 2002 for approximately 1,800 megawatts of purchased power and 414
megawatts of generation to be retired in December 2002. The certification
request included a seven-year PPA with Duke Energy for one gas-fired, combined
cycle unit at Plant Murray near Dalton, Georgia and a 15 year PPA with Southern
Power for two gas-fired, combined cycle units to be constructed at Plant
McIntosh. The Duke Energy (Murray) PPA is for 620 megawatts to be purchased for
Georgia Power beginning in 2005. The Southern Power (McIntosh) units will
produce a combined 1,240 megawatts of which Georgia Power will purchase 1,040
megawatts and Savannah Electric will purchase 200 megawatts. This new generation
will be available by June 2005.
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 to be
constructed at Plant Franklin. Plant Franklin Units 1 and 2 began commercial
operation in June 2002 and June 2003, respectively. 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.
Reference is made to Note 3 to the financial statements of Southern
Company, Georgia Power, Savannah Electric and Southern Power in Item 8 herein
under "FERC Matters" for information regarding PPAs by Georgia Power and
Savannah Electric for Southern Power's Plant McIntosh capacity.
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. For additional information,
reference is made to Note 3 to the financial statements of Gulf Power in Item 8
herein under "Environmental Cost Recovery".
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 2004 ECO Plan in
January 2004, which, if approved as filed, will result in a slight decrease in
customer prices.
I-21
Employee Relations
The Southern Company system had a total of 25,762 employees on its payroll at
December 31, 2003.
-------------------------------- --- -------------------------
Employees
at
December 31, 2003
-------------------------
Alabama Power 6,730
Georgia Power 8,714
Gulf Power 1,337
Mississippi Power 1,290
Savannah Electric 549
SCS 3,294
Southern Nuclear 3,264
Southern Power *
Other 584
--------------------------------------------------------------
Total 25,762
==============================================================
* Southern Power has no employees. Southern Power has agreements with SCS and
the retail operating companies whereby employee services are rendered at cost.
The retail 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.
Savannah Electric has three-year labor agreements with the IBEW and the
Office and Professional Employees International Union that expire April 15, 2006
and December 1, 2006, respectively.
Southern Nuclear has agreements with the IBEW on a five-year contract
extending to August 15, 2006 for Plant Farley, and a three-year contract
extending to June 30, 2005 for Plants Hatch and Vogtle. Southern Nuclear also
has 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.
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.
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Item 2. PROPERTIES
Electric Properties - The Electric Utilities
The retail operating companies, Southern Power and SEGCO, at December 31, 2003,
owned and/or operated 34 hydroelectric generating stations, 32 fossil fuel
generating stations, three nuclear generating stations and 10 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 1,022,500
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 2,112,000
---------
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 21,252,743
-----------
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
-----------
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 1,786,189
------------
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
---------
Boulevard Savannah, GA 59,100
Kraft Port Wentworth, GA 22,000
McIntosh Units Effingham
5&6 County, GA 160,000
-------
Savannah Electric Total 241,100
-------
------------------------------------------------------------------
I-23
-----------------------------------------------------------------
Generating Station Location Nameplate
Capacity
-----------------------------------------------------------------
(Kilowatts)
Dahlberg Jackson County, GA
Southern Power Total 756,000
----------
Gaston (SEGCO) Wilsonville, AL 19,680 (7)
-----------
Total Combustion Turbines 3,803,421
-----------
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 Lynn Haven, FL
Gulf Power Total 619,650
-------
Daniel (Leased) Pascagoula, MS
Mississippi Power Total 1,070,424
---------
Stanton Unit A Orlando, FL 428,649(13)
Harris Autaugaville, AL 1,318,920
Franklin Smiths, AL 1,198,360
Wansley Carrollton, GA 1,073,000
---------
Southern Power Total 4,018,929
---------
Total Combined Cycle 6,779,427
---------
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 175,000
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 1,620,400
-----------
------------------------------------------------------------------
Generating Station Location Nameplate
Capacity
------------------------------------------------------------------
(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 (12)
Sinclair Dam Milledgeville, GA 45,000
Tallulah Falls Clayton, GA 72,000
Terrora Clayton, GA 16,000
Tugalo Clayton, GA 45,000
Wallace Dam Eatonton, GA 321,300
Yonah Toccoa, GA 22,500
6 Other Plants 18,080
-----------
Georgia Power Total 1,077,736
-----------
Total Hydroelectric Facilities 2,698,136
-----------
Total Generating Capacity 38,678,225
===========
------------------------------------------------------------------
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)Capacity shown is Georgia Power's portion (25.4%) of total plant capacity.
OPC operates the plant.
(13)Capacity shown is Southern Power's portion (65%) of total plant capacity.
Except as discussed below under "Titles to Property," the principal plants
and other important units of the retail operating companies, Southern Power and
I-24
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, 2003, the unamortized
portion of this cost was approximately $30.6 million.
The all-time maximum demand on the retail operating companies, Southern
Power and SEGCO was 32,949,200 kilowatts and occurred in August 2003. 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 retail operating companies,
Southern Power and SEGCO at that time was 21.4%. For additional information on
peak demands, reference is made to Item 6 - SELECTED FINANCIAL DATA 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. Southern Power also owns an undivided interest
in a facility with non-affiliated parties. The percentages of ownership
resulting from these transactions are as follows:
Percentage Ownership
------------------------------------------------------------------------------------------- ------
Total Alabama Georgia Southern
Capacity Power AEC Power OPC MEAG DALTON FPC Power OUA FMPA KUA
-----------------------------------------------------------------------------------------------------------------
(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 848 - - 25.4 74.6 - - - - - - -
Mountain
Intercession 143 - - 33.3 - - - 66.7 - - - -
City, FL
Plant Stanton
Unit A 660 - - - - - - - 65% 28% 3.5% 3.5%
---------------------------------------------------------------------------------------------------------------------------------
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 agent for the joint owners. SCS provides operation and
maintenance services for Plant Stanton Unit A.
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.
I-25
Titles to Property
The retail 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, combined cycle units
at Plant Daniel leased by Mississippi Power 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 retail 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-26
Item 3. LEGAL PROCEEDINGS
(1) United States of America v. Alabama Power
(United States District Court for the Northern District of Alabama)
United States of America v. Georgia Power and Savannah Electric
(United States District Court for the Northern District of Georgia)
In November 1999, the EPA brought a civil action in the U.S. District
Court for the Northern District of Georgia against Alabama Power, Georgia
Power, and SCS. The complaint alleged violations of the New Source Review
(NSR) provisions of the Clean Air Act with respect to five coal-fired
generating facilities in Alabama and Georgia and violations of related
state laws. The civil action requested 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 retail operating companies notices of violation relating to 10
generating facilities, which include the five facilities mentioned
previously. In early 2000, the EPA filed a motion to amend its complaint
to add the violations alleged in its notices of violation and to add Gulf
Power, Mississippi Power, and Savannah Electric as defendants.
In August 2000, the U.S. District Court in Georgia granted Alabama
Power's motion to dismiss for lack of jurisdiction in Georgia and granted
SCS' motion to dismiss on the grounds that it neither owned nor operated
the generating units involved in the proceedings. In March 2001, 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 in Georgia 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. In addition, the EPA
refiled its claims against Alabama Power in the U.S. District Court for
the Northern District of Alabama. These complaints allege violations with
respect to eight coal-fired generating facilities in Alabama and Georgia,
and they request the same kinds of relief as was requested in the
original complaint, i.e. penalties and injunctive relief, including
installation of the best available control technology. The EPA has not
refiled against Gulf Power, Mississippi Power, or SCS.
The actions against Alabama Power, Georgia Power, and Savannah Electric
were stayed in the spring of 2001 during the appeal of a very similar NSR
enforcement action against the Tennessee Valley Authority (TVA) before
the U.S. Court of Appeals for the Eleventh Circuit. The TVA appeal
involves many of the same legal issues raised by the actions against
Alabama Power, Georgia Power, and Savannah Electric. Because the final
resolution of the TVA appeal could have a significant impact on Alabama
Power and Georgia Power, both companies have been involved in that
appeal. On June 24, 2003, the court of appeals issued its ruling in the
TVA case. It found unconstitutional the statutory scheme set forth in the
Clean Air Act that allowed the EPA to impose penalties for failing to
comply with an administrative compliance order, like the one issued to
TVA, without the EPA having to prove the underlying violation. Thus, the
court of appeals held that the compliance order was of no legal
consequence, and TVA was free to ignore it. The court did not, however,
rule directly on the substantive legal issues about the proper
interpretation and application of certain NSR provisions that had been
raised in the TVA appeal. On September 16, 2003, the court of appeals
denied the EPA's request for a rehearing of the decision. On February 13,
2004, the EPA petitioned the U.S. Supreme Court to review the decision of
the court of appeals. The EPA also filed a motion to lift the stay in the
action against Alabama Power. At this time, no party to the Georgia Power
and Savannah Electric action, which was administratively closed two years
ago, has asked the court to reopen that case.
Since the inception of the NSR proceedings against Georgia Power, Alabama
Power, and Savannah Electric, the EPA has also been proceeding with
similar NSR enforcement actions against other utilities, involving many
of the same legal issues. In each case, the EPA alleged that the
I-27
Item 3. LEGAL PROCEEDINGS
(Continued)
utilities failed to comply with the NSR permitting requirements
when performing maintenance and construction activities at
coal-burning plants, which activities the utilities considered
to be routine or otherwise not subject to NSR. In 2003, district
courts addressing these cases have issued opinions that reached
conflicting conclusions.
In October 2003, the EPA issued final revisions to its NSR regulations
under the Clean Air Act clarifying the scope of the existing Routine
Maintenance, Repair, and Replacement exclusion. On December 24, 2003, the
U.S. Court of Appeals for the District of Columbia Circuit stayed the
effectiveness of these revisions pending resolution of related
litigation. In January 2004, the Bush Administration announced
that it would continue to enforce the existing rules.
Southern Company believes that its retail 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.
(2) Cooper et al. v. Georgia Power, Southern Company, SCS and Energy
Solutions
(Superior Court of Fulton County, Georgia)
In July 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
indirect subsidiary of 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. On March 31, 2003, the
U.S. District Court for the Northern District of Georgia granted summary
judgment in favor of the defendants on all claims raised by all seven
plaintiffs. On April 23, 2003, plaintiffs filed an appeal to the U.S.
Court of Appeals for the Eleventh Circuit challenging these adverse
summary judgment rulings, as well as the District Court's October 2001
ruling denying class certification. Oral argument occurred on January 27,
2004, and the parties await the court's decision. The final outcome of
this matter cannot now be determined.
(3) 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. Georgia Power has recognized $34 million in
I-28
Item 3. LEGAL PROCEEDINGS
(Continued)
cumulative expenses through December 31, 2003, 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, 2003, 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 Georgia Power's additional liability, if
any, at these sites would be material to the financial statements.
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 "Potentially Responsible Party
Status," respectively.
(4) In re: Mobile Energy Services Company, LLC; In re: Mobile Energy Services
Holdings, Inc.
(U.S. Bankruptcy Court for the Southern District of Alabama)
MESH 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 with the U.S. Bankruptcy Court. In 2001, MESH filed
an amended plan of reorganization, which the U.S. Bankruptcy Court
confirmed in September 2003. The plan became effective in late 2003 and
Southern Company's equity interest in MESH - which had been written off
entirely prior to 2001 - was extinguished. Southern Company will continue
to have contingent liabilities to the pulp and paper complex owners
associated with a guarantee of certain potential environmental
obligations and with a potential obligation to fund a maintenance reserve
account that expires in 2019 and 2021, respectively. The combined maximum
contingent liabilities were $19 million at December 31, 2003. MESH and
Mirant have each separately agreed to indemnify Southern Company for any
amounts required to be paid under such obligations. The final outcome of
these matters cannot now be determined.
(5) California Electricity Markets Investigation
Southern Company received a subpoena in November 2002 to provide
information to a federal grand jury in the Northern District of
California. The subpoena covered a number of broad areas, including
specific information regarding electricity production and sales
activities in California. 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
has fully cooperated in the investigation.
(6) In re: Mirant Corporation, et. al
(U.S. Bankruptcy Court for the Northern District of Texas)
On July 14, 2003, Mirant filed for voluntary reorganization under Chapter
11 with the U.S. Bankruptcy Court. Southern Company has certain
contingent liabilities associated with guarantees of contractual
commitments made by Mirant's subsidiaries discussed in Note 7 to
Southern Company's financial statements in Item 8 herein under
"Guarantees" and with various lawsuits related to Mirant
I-29
Item 3. LEGAL PROCEEDINGS
(Continued)
discussed elsewhere in this Item 3. Also, Southern Company
has joint and several liability with Mirant regarding the joint
consolidated federal income tax return as discussed in Note 5 to the
financial statements of Southern Company in Item 8 herein. Under the
terms of the separation agreement, Mirant agreed to indemnify Southern
Company for costs associated with these guarantees, lawsuits, and
additional Internal Revenue Service (IRS) assessments. The impact of
Mirant's bankruptcy filing on Mirant's indemnity obligations, if any,
cannot now be determined. If Southern Company is ultimately required to
make any payments related to these potentially material obligations,
Mirant's indemnification obligation to Southern Company would represent
an unsecured pre-bankruptcy claim, subject to compromise pursuant to
Mirant's final reorganization plan.
The Bankruptcy Code automatically stays all litigation as to Mirant. A
motion filed with the bankruptcy court requesting an extension of this
automatic stay to all other non-debtor defendants, including Southern
Company and the named current and/or former Southern Company officers was
granted in November 2003. Although the Mirant securities litigation is
stayed until further order from the bankruptcy court, Mirant is
authorized to agree with parties in pending actions to allow discovery or
other matters to proceed without violating the stay. Mirant and
plaintiffs' counsel in the Mirant securities litigation have agreed that
document discovery may proceed. On October 23, 2003, the bankruptcy court
entered an order authorizing Southern Company's insurance companies to
pay related defense costs.
On February 20, 2004, the Official Committee of Unsecured Creditors of
Mirant informed Southern Company of its intent to examine Southern
Company in accordance with federal bankruptcy rules to determine whether
there is a legitimate basis to bring claims against Southern Company in
connection with Mirant's initial public offering, Southern Company's
spin off of Mirant and the related separation agreements.
The final outcome of these matters cannot now be determined.
(7) In re: Mirant Corporation Securities Litigation
(United States District Court for the Northern District of Georgia)
In November 2002, Southern Company, certain former and current
senior officers of Southern Company, and 12 underwriters of Mirant's
initial public offering were added as defendants in a putative class
action lawsuit that several Mirant shareholders originally filed against
Mirant and certain Mirant officers in May 2002. The original lawsuit 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 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. The lawsuit purports to include persons who acquired
Mirant securities between September 26, 2000, and September 5, 2002.
On July 14, 2003, the court dismissed all claims based on Mirant's
alleged improper energy trading and marketing activities involving the
California energy market. The remaining claims are based on alleged false
statements and omissions in Mirant's prospectus for its initial public
offering and accounting-related issues previously disclosed by Mirant.
I-30
Item 3. LEGAL PROCEEDINGS
(Continued)
Such claims do not allege any improper trading and marketing
activity, accounting errors, or material misstatements or omissions on
the part of Southern Company, but rather seek to impose liability on
Southern Company based on allegations that Southern Company was a
"control person" as to Mirant prior to the spin off date. Southern
Company filed an answer to the consolidated amended class action
complaint on September 3, 2003. Plaintiffs have also filed a motion for
class certification.
Under certain circumstances, Southern Company will be obligated under its
Bylaws to indemnify the four current and/or former Southern Company
officers who served as directors of Mirant at the time of its initial
public offering through the date of the spin off and are also named as
defendants in this lawsuit. Except for limited document discovery,
litigation has been stayed until further order from the bankruptcy court.
The final outcome of these matters cannot now be determined.
(8) In re: Mirant Corporation ERISA Litigation
(United States District Court for the Northern District of Georgia)
In April 2003, a retired employee of Mirant filed a complaint in the
U.S. District Court for the Northern District of Georgia alleging
violations of ERISA and naming as defendants Mirant, Southern Company,
several current and former directors and officers of Mirant and/or
Southern Company, and "Unknown Fiduciary Defendants 1-100." In June 2003,
a substantially similar complaint was filed. Neither complaint contained
any specific allegations of wrongdoing with respect to Southern Company.
On September 2, 2003, the court consolidated all pending and future ERISA
actions arising out of the same facts, and the plaintiffs filed a
consolidated amended ERISA complaint on September 23, 2003. The
plaintiffs sought to represent a class of persons who were participants
in or beneficiaries of certain Mirant employee benefit plans between
September 27, 2000, and July 22, 2003. The consolidated amended complaint
named as defendants Mirant, certain Mirant benefit committees, Southern
Company, and several of Mirant's current and former officers, directors,
and employees. The consolidated amended complaint alleged that the
defendants breached their fiduciary duties and violated ERISA by failing
to investigate whether Mirant stock was a prudent investment for the
plans, by continuing and promoting Mirant stock as an investment
alternative for participants in the plans, and by failing to disclose
information about Mirant's financial condition and about its improper
activities in the California energy markets.
On February 19, 2004, the plaintiffs dismissed Southern Company from this
action without prejudice. The plaintiffs are not barred from naming
Southern Company in some future lawsuit, but management believes the
possibility of having to pay damages in any such lawsuit is remote.
(9) 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 the U.S. District Court in Georgia against Georgia Power for
alleged violations of the Clean Air Act at four of the generating units
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.
I-31
Item 3. LEGAL PROCEEDINGS
(Continued)
On June 19, 2003, the court granted Georgia Power's motion to dismiss
the allegations regarding hazardous air pollutants and denied Georgia
Power's motion to dismiss the allegations regarding emission offsets.
On August 29, 2003, Georgia Power filed a motion for partial summary
judgment regarding emission offsets. On January 20, 2004, Georgia Power
filed a motion for summary judgment on the remaining three counts, and
the plaintiffs have filed motions for partial summary judgment. The
case is currently scheduled for trial during the summer of 2004. 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.
(10) Right of Way Litigation
Southern Company and certain of its subsidiaries, including Georgia
Power, Gulf Power, Mississippi Power, and Southern Telecom
(collectively, defendants), have been named as defendants in numerous
lawsuits brought by landowners since 2001 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. With respect to one such lawsuit brought by landowners
regarding the installation and use of fiber optic cable over Gulf Power
rights of way located on the landowners' property, on November 7, 2003,
the Second Circuit Court in Gadsden County, Florida, ruled in favor of
the plaintiffs on their motion for partial summary judgment concerning
liability. The question of damages, if any, will be decided at a future
trial. In the event of an adverse verdict on damages, Gulf Power could
appeal the verdicts on both liability and damages. Management of
Southern Company and its subsidiaries believe that the defendant
companies in the pending right of way litigation have complied with
applicable laws and 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.
In addition, in late 2001, certain subsidiaries of Southern Company,
including Alabama Power, Georgia Power, Gulf Power, Mississippi Power,
Savannah Electric, and Southern Telecom (collectively, defendants),
were named as defendants in a lawsuit brought by a telecommunications
company that uses certain of the defendants' rights of way. This
lawsuit alleges, among other things, that the defendants are
contractually obligated to indemnify, defend, and hold harmless the
telecommunications company from any liability that may be assessed
against the telecommunications company in pending and future right of
way litigation. The defendants believe that the plaintiff's claims are
without merit. An adverse outcome in this matter, combined with an
adverse outcome against the telecommunications company in one or more
of the right of way lawsuits, could result in substantial judgments;
however, the final outcome of these matters cannot now be determined.
(11) 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. This matter is on appeal to Florida's First
District Court of Appeal. If this verdict is upheld, there is
insurance coverage available to offset a substantial portion of this
amount. 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.
I-32
Item 3. LEGAL PROCEEDINGS
(Continued)
Southern Company and its subsidiaries are subject to certain claims and legal
actions arising in the ordinary course of business. In addition, the business
activities of Southern Company and its subsidiaries 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 against
Southern Company and its subsidiaries cannot be predicted at this time;
however, management does not anticipate that the liabilities, if any, arising
from such current 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-33
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, 2003.
H. Allen Franklin (1)
Chairman, President, Chief Executive Officer and Director
Age 59
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 55
Elected in 2001. Previously served as President and Chief Executive Officer of
Mississippi Power from March 1995 to May 2001.
Thomas A. Fanning
Executive Vice President, Chief Financial Officer and Treasurer
Age 46
Elected in 2003. Previously served as President, Chief Executive Officer and
Director of Gulf Power from 2002 to April 2003; Executive Vice President,
Treasurer and Chief Financial Officer of Georgia Power from 1999 to 2002.
Leonard J. Haynes
Executive Vice President and Chief Marketing Officer
Age 53
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 51
Elected in 2001. Previously served as President and Chief Executive Officer of
Savannah Electric from 1997 until 2001.
Charles D. McCrary
Executive Vice President
Age 52
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.
David M. Ratcliffe (2)
Executive Vice President
Age 55
Elected in 1999. He also has served as Chief Executive Officer of Georgia Power
since June 1999 and as President of Georgia Power from June 1999 to December
2003. Previously served as Executive Vice President, Treasurer and Chief
Financial Officer of Georgia Power from March 1998 to June 1999.
W. Paul Bowers
President of Southern Company Generation & Energy Marketing, Executive Vice
President of SCS and President and Chief Executive Officer of Southern Power
since May 2001
Age 47
Elected in 2001. Previously served as Senior Vice President and Chief Marketing
Officer of Southern Company from March 2000 to May 2001; President and Chief
Executive Officer of Western Power Distribution and Southwestern Electricity
plc, a subsidiary of Mirant located in Bristol, England, from December 1998 to
2000.
W. G. Hairston, III
President and Chief Executive Officer of Southern Nuclear since 1993.
Age 59
(1) Mr. Franklin will retire in July 2004.
(2) Mr. Ratcliffe will continue to serve as Chief Executive Officer of Georgia
Power until April 2004, at which time he will become President of Southern
Company. He will become Chairman and Chief Executive Officer of Southern Company
effective in July 2004.
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, 2003)
I-34
for one year until the first board meeting after the next annual meeting or
until their successors are elected and have qualified.
I-35
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, 2003.
Charles D. McCrary
President, Chief Executive Officer and Director
Age 52
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.
William B. Hutchins, III
Executive Vice President, Chief Financial Officer
and Treasurer
Age 60
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 55
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.
Steven R. Spencer
Executive Vice President
Age 48
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 54
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 25, 2003) for one year until the next
annual meeting or until their successors are elected and have qualified.
I-36
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, 2003.
David M. Ratcliffe (1)
Chief Executive Officer and Director
Age 55
Elected as an Executive Officer in 1998 and as Director in 1999. Served as Chief
Executive Officer since June 1999 and as President from June 1999 through
December 2003. Previously served as Executive Vice President, Treasurer and
Chief Financial Officer of Georgia Power from March 1998 to June 1999.
Michael D. Garrett (2)
President and Director
Age 54
Elected in 2003. President and Director of Georgia Power effective January 1,
2004. Previously served as President, Chief Executive Officer and Director of
Mississippi Power from 2001 to 2003; Executive Vice President - Customer Service
of Alabama Power from January 2000 to May 2001; and Executive Vice President of
External Affairs of Alabama Power from March 1998 to January 2000.
William C. Archer, III
Executive Vice President
Age 55
Elected in 1995. Served as Executive Vice President of External Affairs since
1995.
C. B. Harreld
Executive Vice President, Chief Financial Officer and Treasurer
Age 59
Elected in 2003. Served as Executive Vice President, Chief Financial Officer and
Treasurer since 2003. Previously served as Senior Vice President of Finance, SCS
from 2002 to 2003; Chief Financial Officer and Comptroller of Southern Company
Generation and Energy Marketing from 2001 to 2002; Chief Financial Officer of
Mirant - Europe from 2000 to 2001; and Vice President and Controller, Southern
Energy, Inc. from 1999 to 2000.
Judy M. Anderson
Senior Vice President
Age 55
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 49
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 56
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.
Richard L. Holmes
Senior Vice President
Age 52
Elected in 2003. Served as Senior Vice President of Corporate Services since
2003. Previously served as Vice President of Corporate Services from 2002 to
2003; Vice President of Region Operations from 2000 to 2002; Assistant to the
President and Chief Executive Officer from 1999 to 2000; and Metro West Region
Manager from 1992 to 1999.
Leslie R. Sibert
Vice President
Age 41
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 45
Elected in 2001. Served as Senior Vice President of Fossil and Hydro since 2001.
Previously served as Vice President and Chief Executive People Officer of
Southern Company from 1998 to 2001.
I-37
(1) Mr. Ratcliffe will continue to serve as Chief Executive Officer of Georgia
Power until April 2004, at which time he will become President of Southern
Company. He will become Chairman and Chief Executive Officer of Southern Company
in July 2004.
(2) Mr. Garrett was elected President and Director of Georgia Power effective
January 1, 2004. In addition, he will become Chief Executive Officer of Georgia
Power effective April 2004.
The officers of Georgia Power were elected for a term running from the last
annual meeting of the directors (May 21, 2003) for one year until the next
annual meeting or until their successors are elected and have qualified, except
for Mr. Harreld whose election was effective June 30, 2003 and Mr. Garrett whose
election was effective January 1, 2004.
I-38
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, 2003.
Susan N. Story
President, Chief Executive Officer and Director
Age 43
Elected in 2003. Previously served as Executive Vice President of Engineering
and Construction Services at Southern Company Generation and Energy Marketing
from 2001 to 2003; Vice President of Procurement and Materials at SCS from 2000
to 2001; and Vice President of Corporate Services and Corporate Real Estate at
Alabama Power from 1997 to 2000.
Francis M. Fisher, Jr.
Vice President
Age 55
Elected in 1989. Served as Vice President of Customer Operations since 1996.
P. Bernard Jacob
Vice President
Age 49
Elected in 2003. Served as Vice President of External Affairs and Corporate
Services since 2003. Previously served as Director of IR Security and Program
Management at SCS from 2002 to 2003 and Manager of Telecommunications Strategy
at SCS from 1998 to 2002.
Ronnie R. Labrato
Vice President, Chief Financial Officer and Comptroller
Age 50
Elected in 2000. Previously served as Comptroller and Chief Financial Officer
from 2000 to 2001 and Controller from 1992 to 2000.
Gene L. Ussery, Jr.
Vice President
Age 54
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 (July 24, 2003) for one year until the next
annual meeting or until their successors are elected and have qualified.
I-39
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, 2003.
Michael D. Garrett (1)
President, Chief Executive Officer and Director
Age 54
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.
Anthony J. Topazi (2)
President, Chief Executive Officer and Director
Age 53
Elected in 2003. Served as Senior Vice President of Southern Power from November
2002 to December 2003 and Vice President of SCS from December 1999 to December
2003. 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.
Bobby J. Kerley
Vice President
Age 50
Elected in 2003. Served as Vice President of Customer Services and Retail
Marketing since December 2003. Previously served at Alabama Power as Division
Vice President - Southeast Division Office from April 2001 to December 2003;
Division Manager - Operations, Birmingham Division Office from January 2001 to
April 2001; Transmission Lines Manager, Corporate Headquarters from March 1997
to January 2001.
Don E. Mason
Vice President
Age 62
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 51
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 54
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.
(1) Mr. Garrett was elected President and Director of Georgia Power effective
January 1, 2004. In addition, he will become Chief Executive Officer of Georgia
Power effective April 2004.
(2) Mr. Topazi was elected President, Chief Executive Officer and Director of
Mississippi Power effective January 1, 2004.
The officers of Mississippi Power were elected for a term running from the
last annual meeting of the directors (April 23, 2003) for one year until the
next annual meeting or until their successors are elected and have qualified,
except for Mr. Kerley and Mr. Topazi whose elections were effective
November 14, 2003 and January 1, 2004, respectively.
I-40
PART II
Item 5. MARKET FOR REGISTRANTS' COMMON EQUITY, RELATED STOCKHOLDER MATTERS
AND ISSUER PURCHASES OF EQUITY SECURITIES
(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
-------------- --------------
2003
First Quarter $30.81 $27.71
Second Quarter 31.81 27.94
Third Quarter 30.53 27.76
Fourth Quarter 30.40 28.65
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
-------------------------------------------------------
There is no market for the other registrants' common stock, all of
which is owned by Southern Company. On February 25, 2004, the closing
price of Southern Company's common stock was $29.79.
(b) Number of Southern Company's common stockholders of record
at December 31, 2003: 134,068
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 retail operating
companies to their stockholder(s) for the past two years were as
follows:
---------------------------------------------------------
Registrant Quarter 2003 2002
---------------------------------------------------------
(in thousands)
Southern Company
First $ 245,745 $ 234,272
Second 247,324 236,154
Third 255,042 242,850
Fourth 256,334 244,309
Alabama Power First 107,550 107,750
Second 107,550 107,750
Third 107,550 107,750
Fourth 107,550 107,750
Georgia Power First 141,450 135,725
Second 141,450 135,725
Third 141,450 135,725
Fourth 141,450 135,725
Gulf Power First 17,550 16,375
Second 17,550 16,375
Third 17,550 16,375
Fourth 17,550 16,375
Mississippi First 16,500 15,875
Power Second 16,500 15,875
Third 16,500 15,875
Fourth 16,500 15,875
Savannah
Electric First 5,750 5,675
Second 5,750 5,675
Third 5,750 5,675
Fourth 5,750 5,675
---------------------------------------------------------
Southern Power did not pay a dividend in 2002, but paid a $77 million
dividend to Southern Company in the third quarter of 2003.
The dividend paid per share by Southern Company was 33.5(cents) first two
quarters of 2002 and 34.25(cents) for the two remaining quarters in 2002. The
dividend paid on Southern Company's common stock for the first and second
quarters of 2003 was 34.25(cents) per share and for the third and fourth
quarters of 2003 was 35(cents) 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 Note 8 of Southern Company and Note 6 of Gulf Power, Mississippi Power and
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, 2003 were as follows:
----------------------------------------------------------
Retained Restricted
Earnings Amount
------------------ -------------
(in millions)
Alabama Power $ 1,292 $ -
Georgia Power 2,010 -
Gulf Power 161 127
Mississippi Power 203 118
Savannah Electric 110 68
Southern Power 218 -
Consolidated 5,343 $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-62 and II-63.
Alabama Power. Reference is made to information under the heading "Selected
Financial and Operating Data," contained herein at pages II-106 and II-107.
Georgia Power. Reference is made to information under the heading "Selected
Financial and Operating Data," contained herein at pages II-155 and II-156.
Gulf Power. Reference is made to information under the heading "Selected
Financial and Operating Data," contained herein at pages II-196 and II-197.
Mississippi Power. Reference is made to information under the heading
"Selected Financial and Operating Data," contained herein at pages II-241 and
II-242.
Savannah Electric. Reference is made to information under the heading
"Selected Financial and Operating Data," contained herein at pages II-282 and
II-283.
Southern Power. Reference is made to information under the heading "Selected
Financial and Operating Data," contained herein at page II-313.
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-10 through II-28.
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-67 through II-82.
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-111 through II-127.
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-160 through II-174.
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-201 through II-217.
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-246 through II-260.
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-287 through II-298.
II-2
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Reference is made to information in each of the registrants' "Management's
Discussion and Analysis - Financial Condition And Liquidity - Market Price Risk"
in Item 7 herein and to Notes 1 and 6 to each of the registrants' financial
statements in Item 8 herein under the heading "Financial Instruments."
II-3
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO 2003 FINANCIAL STATEMENTS
Page
The Southern Company and Subsidiary Companies:
Independent Auditors' Report............................................................................................ II-9
Report of Independent Public Accountants................................................................................ II-9
Consolidated Statements of Income for the Years Ended December 31, 2003, 2002 and 2001.................................. II-29
Consolidated Statements of Cash Flows for the Years Ended December 31, 2003, 2002 and 2001.............................. II-30
Consolidated Balance Sheets at December 31, 2003 and 2002............................................................... II-31
Consolidated Statements of Capitalization at December 31, 2003 and 2002................................................. II-33
Consolidated Statements of Common Stockholders' Equity for the Years Ended
December 31, 2003, 2002 and 2001................................................................................ II-35
Consolidated Statements of Comprehensive Income for the Years Ended
December 31, 2003, 2002 and 2001................................................................................ II-35
Notes to Financial Statements........................................................................................... II-36
Alabama Power:
Independent Auditors' Report............................................................................................ II-66
Report of Independent Public Accountants................................................................................ II-66
Statements of Income for the Years Ended December 31, 2003, 2002 and 2001............................................... II-83
Statements of Cash Flows for the Years Ended December 31, 2003, 2002 and 2001........................................... II-84
Balance Sheets at December 31, 2003 and 2002 ........................................................................... II-85
Statements of Capitalization at December 31, 2003 and 2002 ............................................................. II-87
Statements of Common Stockholder's Equity for the Years Ended
December 31, 2003, 2002 and 2001............................................................................... II-89
Statements of Comprehensive Income for the Years Ended
December 31, 2003, 2002 and 2001................................................................................ II-89
Notes to Financial Statements........................................................................................... II-90
Georgia Power:
Independent Auditors' Report............................................................................................ II-110
Report of Independent Public Accountants................................................................................ II-110
Statements of Income for the Years Ended December 31, 2003, 2002 and 2001............................................... II-128
Statements of Cash Flows for the Years Ended December 31, 2003, 2002 and 2001........................................... II-129
Balance Sheets at December 31, 2003 and 2002............................................................................ II-130
Statements of Capitalization at December 31, 2003 and 2002 ............................................................. II-132
Statements of Common Stockholder's Equity for the Years Ended
December 31, 2003, 2002 and 2001............................................................................... II-133
Statements of Comprehensive Income for the Years Ended
December 31, 2003, 2002 and 2001................................................................................ II-133
Notes to Financial Statements........................................................................................... II-134
Gulf Power:
Independent Auditors' Report............................................................................................ II-159
Report of Independent Public Accountants................................................................................ II-159
Statements of Income for the Years Ended December 31, 2003, 2002 and 2001............................................... II-175
Statements of Cash Flows for the Years Ended December 31, 2003, 2002 and 2001........................................... II-176
Balance Sheets at December 31, 2003 and 2002 ........................................................................... II-177
Statements of Capitalization at December 31, 2003 and 2002 ............................................................. II-179
Statements of Common Stockholder's Equity for the Years Ended
December 31, 2003, 2002 and 2001................................................................................. II-180
II-4
Page
Statements of Comprehensive Income for the Years Ended
December 31, 2003, 2002 and 2002................................................................................ II-180
Notes to Financial Statements........................................................................................... II-181
Mississippi Power:
Independent Auditors' Report............................................................................................ II-200
Report of Independent Public Accountants................................................................................ II-200
Statements of Income for the Years Ended December 31, 2003, 2002 and 2001............................................... II-218
Statements of Cash Flows for the Years Ended December 31, 2003, 2002 and 2001........................................... II-219
Balance Sheets at December 31, 2003 and 2002 ........................................................................... II-220
Statements of Capitalization at December 31, 2003 and 2002 ............................................................. II-222
Statements of Common Stockholder's Equity for the Years Ended
December 31, 2003, 2002 and 2001............................................................................... II-223
Statements of Comprehensive Income for the Years Ended
December 31, 2003, 2002 and 2001................................................................................ II-223
Notes to Financial Statements........................................................................................... II-224
Savannah Electric:
Independent Auditors' Report............................................................................................ II-245
Report of Independent Public Accountants................................................................................ II-245
Statements of Income for the Years Ended December 31, 2003, 2002 and 2001............................................... II-261
Statements of Cash Flows for the Years Ended December 31, 2003, 2002 and 2001........................................... II-262
Balance Sheets at December 31, 2003 and 2002 ........................................................................... II-263
Statements of Capitalization at December 31, 2003 and 2002 ............................................................. II-265
Statements of Common Stockholder's Equity for the Years Ended
December 31, 2003, 2002 and 2001................................................................................ II-266
Statements of Comprehensive Income for the Years Ended
December 31, 2003, 2002 and 2001................................................................................ II-266
Notes to Financial Statements........................................................................................... II-267
Southern Power:
Independent Auditors' Report............................................................................................ II-286
Statements of Income for the Years Ended December 31, 2003 and 2002 and
for the period from January 8, 2001 (inception) through December 31, 2001....................................... II-299
Statements of Cash Flows for the Years Ended December 31, 2003 and 2002 and
for the period from January 8, 2001 (inception) through December 31, 2001....................................... II-300
Balance Sheets at December 31, 2003 and 2002 ........................................................................... II-301
Statements of Common Stockholder's Equity for the Years Ended December 31, 2003 and 2002 and
for the period from January 8, 2001 (inception) through December 31, 2001 ...................................... II-303
Statements of Comprehensive Income for the Years Ended December 31, 2003 and 2002 and
for the period from January 8, 2001 (inception) through December 31, 2001....................................... II-303
Notes to Financial Statements........................................................................................... II-304
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
Item 9A. CONTROLS AND PROCEDURES
(a) Evaluation of disclosure controls and procedures.
As of the end of the period covered by this annual report, Southern
Company, the retail 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-15(e) and 15d-15(e) 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 changes in Southern Company's, the retail
operating companies' or Southern Power's internal controls over financial
reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the
Securities Exchange Act of 1934) during the fourth quarter of 2003 that have
materially affected or are reasonably likely to materially affect, Southern
Company's, the retail operating companies' or Southern Power's internal
controls over financial reporting.
II-6
PAGE>
THE SOUTHERN COMPANY
AND SUBSIDIARY COMPANIES
FINANCIAL SECTION
II-7
MANAGEMENT'S REPORT
Southern Company and Subsidiary Companies 2003 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 internal accounting controls are evaluated on an ongoing basis
by the company's internal audit staff. The company's independent public
accountants also consider certain elements of the internal control system in
order to determine their auditing procedures for the purpose of expressing an
opinion on the financial statements.
The audit committee of the board of directors, composed of four 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/Thomas A. Fanning
Thomas A. Fanning
Executive Vice President, Chief Financial Officer,
and Treasurer
March 1, 2004
II-8
INDEPENDENT AUDITORS' REPORT
To the Board of Directors and Stockholders of
Southern Company
We have audited the accompanying consolidated balance sheets and consolidated
statements of capitalization of Southern Company and Subsidiary Companies as of
December 31, 2003 and 2002, and the related consolidated statements of income,
comprehensive income, common stockholders' equity, and cash flows for the years
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 audits. The consolidated financial statements
of Southern Company and Subsidiary Companies for the year ended December 31,
2001, 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 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, the consolidated financial statements (pages II-29 to II-61)
present fairly, in all material respects, the financial position of Southern
Company and Subsidiary Companies at December 31, 2003 and 2002, and the results
of their operations and their cash flows for the years then ended in conformity
with accounting principles generally accepted in the United States of America.
As discussed in Note 1 to the consolidated financial statements, in 2003
Southern Company changed its method of accounting for asset retirement
obligations.
/s/Deloitte & Touche LLP
Atlanta, Georgia
March 1, 2004
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(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 to 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-9
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Southern Company and Subsidiary Companies 2003 Annual Report
OVERVIEW OF CONSOLIDATED EARNINGS
- ---------------------------------
AND BUSINESS ACTIVITIES
- -----------------------
Earnings
Southern Company's financial performance in 2003 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 $1.5 billion increased 11.8 percent over
income reported in 2002. Net income from continuing operations was $1.3 billion
in 2002 and $1.1 billion in 2001. This was a 17.6 percent and 12.7 percent
increase in 2002 and 2001, respectively. Basic earnings per share from
continuing operations in 2003 were $2.03 per share, $1.86 in 2002, and $1.62 in
2001. Dilution -- which factors in additional shares related to stock options --
decreased earnings per share in 2003, 2002, and 2001 by 1 cent each year.
On April 2, 2001, Southern Company completed the spin off of its remaining
80.1 percent ownership of Mirant Corporation (Mirant) in a tax-free transaction.
As a result of the spin off, Southern Company's 2001 financial statements and
related information reflect Mirant as discontinued operations.
Dividends
Southern Company has paid dividends on its common stock since 1948. Dividends
paid per share on common stock were $1.385 in 2003, $1.355 in 2002, and $1.34 in
2001. In January 2004, Southern Company declared a quarterly dividend of 35
cents per share. This is the 225th consecutive quarter that Southern Company has
paid a dividend equal to or higher than the previous quarter. The company's goal
for the dividend payout ratio is 70 percent.
Southern Company Business Activities
Discussion of the results of operations is focused on Southern Company's primary
business of electricity sales in the Southeast by the retail 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 rate authority. Southern Company's other
business activities include investments in synthetic fuels and leveraged lease
projects, telecommunications, energy-related services, natural gas marketing,
and the parent holding company.
Several factors affect the opportunities, challenges, and risk of Southern
Company's primary business of selling electricity. These factors include the
retail operating companies' ability to maintain a stable regulatory environment,
to achieve energy sales growth while containing costs, and to recover costs
related to growing demand and increasingly stricter environmental standards.
Another major factor is the profitability of the competitive market-based
wholesale generating business and federal regulatory policy, which may impact
Southern Company's level of participation in this market. 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 energy contracts with neighboring utilities, energy
conservation practiced by customers, the price of electricity, the price
elasticity of demand, and the rate of economic growth in the service area.
RESULTS OF OPERATIONS
- ---------------------
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 electricity business is as follows:
Increase (Decrease)
Amount From Prior Year
----------------------------------
2003 2003 2002 2001
- ---------------------------------------------------------------
(in millions)
Operating revenues $10,747 $541 $ 300 $ 46
- ---------------------------------------------------------------
Fuel 2,998 212 209 13
Purchased power 473 24 (269) 41
Other operation
and maintenance 2,858 107 262 19
Depreciation
and amortization 972 (16) (155) 9
Taxes other than
income taxes 584 29 22 1
- ---------------------------------------------------------------
Total operating
expenses 7,885 356 69 83
- ---------------------------------------------------------------
Operating income 2,862 185 231 (37)
Other income, net 2 20 (32) 51
Interest expenses
and other, net 595 9 (24) (25)
Income taxes 845 68 76 (1)
- ---------------------------------------------------------------
Net income $ 1,424 $128 $ 147 $ 40
===============================================================
II-10
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2003 Annual Report
Revenues
Details of electric operating revenues are as follows:
2003 2002 2001
- -----------------------------------------------------------------
(in millions)
Retail -- prior year $ 8,728 $ 8,440 $8,600
Change in --
Base rates 75 33 23
Sales growth 104 98 61
Weather (135) 158 (177)
Fuel cost recovery
and other 103 (1) (67)
- -----------------------------------------------------------------
Retail -- current year 8,875 8,728 8,440
- -----------------------------------------------------------------
Sales for resale --
Within service area 403 393 338
Outside service area 955 775 836
- -----------------------------------------------------------------
Total sales for resale 1,358 1,168 1,174
- -----------------------------------------------------------------
Other electric
operating revenues 514 310 292
- -----------------------------------------------------------------
Electric operating
revenues $10,747 $10,206 $9,906
=================================================================
Percent change 5.3% 3.0% 0.5%
- -----------------------------------------------------------------
Retail revenues increased $147 million in 2003 and $288 million in 2002 and
declined $160 million in 2001. The significant factors driving these changes are
shown in the table above.
Electric rates -- for the retail operating companies -- include provisions to
adjust billings for fluctuations in fuel costs, the energy component of
purchased energy 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 for 2003 increased $10
million, which reflected increased customer growth offset by milder weather,
compared with sales in 2002. Revenues from sales for resale within the service
area in 2002 increased $55 million as a result of above normal weather. 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.
Revenues from energy sales for resale outside the service area increased $180
million as a result of new contracts, higher gas prices, and milder weather. The
new contracts reflected some 2,400 megawatts of new generating capacity being
placed into service in 2003. As a result of mild weather, more coal-fired
generation was available for sale to utilities outside the service area. In
general, sales for resale outside the service area can be significantly
influenced by weather, which affects both customer demand and generating
availability for these type sales. Neighboring utilities that depend heavily on
gas-fired generation purchase larger amounts of power as natural gas prices
increase. These factors contribute to the large fluctuations in sales from year
to year.
In 2002, revenues from energy sales for resale outside the service area were
down 7.3 percent after having increased 39 percent in 2001. 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 $355
million since 2000 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. Under the unit power sales contracts, capacity revenues
reflect the recovery of fixed costs and a return on investment, 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:
2003 2002 2001
----------------------------------------------------------------
(in millions)
Unit power --
Capacity $182 $175 $170
Energy 211 198 201
Other long term --
Capacity 111 100 112
Energy 451 306 353
- ----------------------------------------------------------------
Total $955 $779 $836
================================================================
Capacity revenues for unit power contracts in 2003, 2002, and 2001 each
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.
In May 2003, Mississippi Power and Southern Power entered into agreements
with Dynegy, Inc. (Dynegy) that resolved and terminated in 2003 all outstanding
II-11
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2003 Annual Report
matters related to capacity sales contracts with subsidiaries of Dynegy. The
termination payments from Dynegy resulted in an increase in other electric
revenues of $135 million for the year 2003.
Energy Sales
Changes in revenues are influenced heavily by the volume of energy sold each
year. Kilowatt-hour sales for 2003 and the percent change by year were as
follows:
Amount Percent Change
(billions of ------- --------------------------
kilowatt-hours) 2003 2003 2002 2001
- --------------------------------------------------------------
Residential 47.8 (1.9)% 9.5% (3.6)%
Commercial 48.4 0.3 2.8 1.5
Industrial 54.4 1.0 1.8 (6.8)
Other 1.0 (0.2) 2.3 0.7
- --------------------------------------------------------------
Total retail 151.6 (0.2) 4.5 (3.2)
Sales for resale --
Within service area 9.4 (11.2) 12.9 (2.0)
Outside service area 31.1 41.7 2.7 24.4
- --------------------------------------------------------------
Total 192.1 4.2 4.7 (0.5)
==============================================================
Residential energy sales in 2003 reflected a decrease in customer demand as
a result of very mild weather partially offset by an increase of 1.6 percent in
new customers. Commercial sales continued to show steady growth while industrial
sales increased somewhat over the depressed results of recent years. In 2002,
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 a 1.6 percent increase in customers served. 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. Energy sales to retail customers are
projected to increase at an average annual rate of 1.6 percent during the period
2004 through 2014.
Sales to customers outside the service area under contracts and opportunity
sales increased by 8.0 billion, 1.0 billion, and 3.9 billion kilowatt-hours in
2003, 2002, and 2001, respectively. In 2003, these sales reflected the expansion
of the competitive wholesale contract business discussed earlier, as well as
increased availability of coal-fired generation resulting from weather-related
lower retail demand coupled with higher natural gas prices, which increase the
wholesale market price related to opportunity sales. Unit power energy sales
increased 4.0 percent in 2003, decreased 3.3 percent in 2002, and increased 2.7
percent in 2001. Fluctuations in oil and natural gas prices, which are the
primary fuel sources for unit power sales customers, influence changes in sales.
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 2003 were $7.9 billion, an increase of $356
million over 2002 expenses. Electricity production costs exceeded last year's
cost by $210 million as a result of increased electricity sales and a 6.8
percent increase in the average unit cost of fuel. Non-production electricity
operation and maintenance costs also increased by $159 million in 2003. This
increase in expenses was primarily driven by additional administrative and
general expenses of $45 million, customer service expenses of $15 million, and a
$60 million regulatory expense related to Plant Daniel. For more information
regarding this regulatory expense, see Note 3 to the financial statements under
"Mississippi Power Regulatory Filing." Taxes other than income taxes increased
$29 million in 2003 as a result of new facilities with a higher tax basis for
property taxes. Depreciation and amortization declined by $16 million in 2003,
primarily as a result of Georgia Power's 2001 rate order to recognize certain
purchased power costs evenly over a three-year period. This amortization reduced
depreciation expense by $49 million in 2003. This expense was partially offset
by a higher depreciable plant basis. For more information regarding the 2001
rate action, see Note 3 to the financial statements under "Georgia Power Retail
Rate Orders."
In 2002, electric operating expenses were $7.5 billion, an increase of $69
million over 2001 expenses. Electricity production costs exceeded 2001 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. 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.
Electric operating expenses in 2001 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.
II-12
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2003 Annual Report
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 demand, the unit cost of fuel consumed, and the availability of
generating units. The amount and sources of generation, the average cost of fuel
per net kilowatt-hour generated, and the average cost of purchased power were as
follows:
2003 2002 2001
- ---------------------------------------------------------------
Total generation
(billions of kilowatt-hours) 189 183 174
Sources of generation
(percent) --
Coal 71 69 72
Nuclear 16 16 16
Gas 9 12 9
Hydro 4 3 3
Average cost of fuel per net
kilowatt-hour generated
(cents) 1.72 1.61 1.56
Average cost of purchased
power per net kilowatt-hour
(cents) 3.82 4.17 6.10
- ---------------------------------------------------------------
Fuel and purchased power costs to produce electricity were $3.5 billion in
2003, an increase of $295 million or 7.4 percent above the prior year costs.
This increase was attributed to higher unit fuel cost and increased customer
demand. The additional demand was met by generating 6 billion and purchasing 1.6
billion more kilowatt-hours than in 2002.
In 2002, fuel and purchased power costs to produce electricity were $3.23
billion, a decrease of $79 million or 2.4 percent below the prior year costs. An
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. Fuel and purchased power costs in
2001 were $3.3 billion, an increase of $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 interest charges and other financing costs in 2003 increased by $19
million as a result of Southern Power issuing $575 million of senior notes in
both 2003 and 2002 to finance new generating facilities. This increase offset
the reduction in interest costs related to the retail operating companies
refinancing higher-cost debt in 2003. Total interest charges and other financing
costs declined by $24 million in 2002 and $25 million in 2001 as a result of
much lower interest rates on short-term debt and continued refinancing of
higher-cost long-term securities.
Other Business Activities
Southern Company's other business activities include the parent company -- which
does not allocate operating expenses to business units -- investments in
synthetic fuels and leveraged lease projects, telecommunications, energy
services, and natural gas marketing. These businesses are classified in general
categories and may comprise one or more of the following subsidiaries. Southern
Company Holdings invests in synthetic fuels and leveraged lease projects that
receive tax benefits, which contribute significantly to the economic results of
these investments; Southern LINC provides digital wireless communications
services to the retail operating companies and also markets these services to
the public within the Southeast; Southern Telecom provides fiber optics services
in the Southeast; 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.
A condensed income statement for Southern Company's other business activities
is shown below:
Increase (Decrease)
Amount From Prior Year
------- -----------------------
2003 2003 2002 2001
- ---------------------------------------------------------------
(in millions)
Operating revenues $ 504 $161 $ 94 $ 43
- ---------------------------------------------------------------
Operation and
maintenance 414 101 41 29
Depreciation and
amortization 55 (4) 30 (7)
Taxes other than
income taxes 2 - - (2)
- ---------------------------------------------------------------
Total operating
expenses 471 97 71 20
- ---------------------------------------------------------------
Operating income 33 64 23 23
Equity in losses of
unconsolidated
subsidiaries (185) (30) (102) (31)
Leveraged lease
income 66 8 (1) (2)
Other income, net 7 8 (11) 5
Interest expenses 104 6 (37) (62)
Income taxes (233) 16 (105) (29)
- ---------------------------------------------------------------
Net income $ 50 $ 28 $ 51 $ 86
===============================================================
Southern Company's non-regulated business investments continued to provide
financial returns consistent with the company's earnings goals. Non-regulated
revenues increased $161 million in 2003. Southern Company GAS began operations
II-13
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2003 Annual Report
in August 2002 and recorded revenues of $168 million in 2003 and $68 million in
2002. Southern LINC's revenues increased $8 million, $32 million, and $12
million in 2003, 2002, and 2001, respectively, as a result of increased wireless
subscribers. Revenues from a subsidiary formed in April 2001 that provides
services related to synthetic fuel products were $93 million in 2003, increasing
by $37 million and $26 million in 2003 and 2002, respectively, as a result of
increased production at the facilities. The majority of these revenues relate to
transportation services that are billed at cost and, therefore, have no effect
on net income.
The increases in 2003 and 2002 operating and maintenance expenses were
primarily driven by Southern Company GAS' increases in operating expenses of
$120 million and $60 million, respectively. These increases reflect only a
partial year of operation in 2002 for Southern Company GAS. Natural gas
purchases represent their primary operating expense. Also, the average cost of
natural gas per decatherm increased 24 percent in 2003. These increases were
partially offset by intersegment eliminations related to synthetic fuels being
sold to the retail operating companies. See Note 1 to the financial statements
under "Synthetic Fuel Tax Credits" for additional information. In 2002, expenses
increased $19 million for Southern LINC as a result of their additional
subscribers, and expenses for synthetic fuel product services increased by $30
million as a result of increased production. In 2001, operation and maintenance
expenses increased $37 million as a result of a subsidiary formed in April 2001
to produce synthetic fuel. This increase was partially offset by a reduction in
expenses related to a private security subsidiary that was sold in late 2000.
The changes in depreciation expense in 2002 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
Southern LINC. The 2001 decreases relate to investment write offs in 2000.
The increases in equity in losses of unconsolidated subsidiaries in 2002 and
2001 reflect the results of additional investments in synthetic 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 $120 million in 2003, $108 million in
2002, and $71 million in 2001.
The increase in other income in 2003 reflected a $15 million gain for a
Southern Telecom contract settlement during the year. This gain was offset by an
increase of $7 million in charitable contributions above the amount in 2002 made
by the parent holding company.
Interest expenses for 2003 increased $18 million for the redemption of $430
million of preferred securities. This increase was partially offset by less
short-term debt outstanding at the parent company. Interest expense charges in
2002 and 2001 reflect lower interest rates and less amounts of debt outstanding
for the parent company.
Effects of Inflation
The retail 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 retail
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. These factors affect the
opportunities, challenges, and risk of Southern Company's primary business of
selling electricity. These factors include the retail operating companies'
ability to maintain a stable regulatory environment, to achieve energy sales
growth while containing costs, and to recover costs related to growing demand
and increasingly stricter environmental standards. Another major factor is the
profitability of the competitive market-based wholesale generating business and
federal regulatory policy, which may impact Southern Company's level of
participation in this market. 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
energy contracts with neighboring utilities, energy conservation practiced by
II-14
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2003 Annual Report
customers, the price of electricity, the price elasticity of demand, and the
rate of economic growth in the service area.
Industry Restructuring
The retail 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.
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 allowed
independent power producers to access a utility's transmission network and sell
electricity to other utilities.
Although the Energy Act does not provide for retail customer access, it was a
major catalyst for 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 well
as the August 2003 power outage in the Northeast. As a result of these issues,
many states, including those in Southern Company's retail service area, have
either discontinued or delayed consideration of initiatives involving retail
deregulation.
Since 2001, merchant energy companies and traditional electric utilities with
significant energy marketing and trading activities have come 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. Southern Company has not
experienced any material adverse 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, both of which are optimized by
limited energy trading activities.
Southern Company continues to maintain and expand its wholesale energy
business in the Southeast. In 2001, Southern Company formed Southern Power to
construct, own, and manage wholesale generating assets in the Southeast.
Southern Power is the primary growth engine for Southern Company's competitive
wholesale energy business. By the end of 2005, Southern Power plans to have
approximately 6,000 megawatts of available generating capacity in commercial
operation. At December 31, 2003, approximately 4,800 megawatts were in
commercial operation.
Continuing to be a low-cost producer could provide opportunities to increase
the size and profitability of the electricity sales business in markets that
evolve with changing regulation and competition. Conversely, future regulatory
changes could adversely affect the company's growth, and 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.
Environmental Matters
New Source Review Actions
In November 1999, the Environmental Protection Agency (EPA) brought a civil
action against certain Southern Company subsidiaries, including Alabama Power
and Georgia Power, and alleged that these subsidiaries had violated the New
Source Review (NSR) provisions of the Clean Air Act at five coal-fired
II-15
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2003 Annual Report
generating facilities. Through subsequent amendments and other legal procedures,
the EPA added Savannah Electric as a defendant to the original action. The EPA
filed a separate action against Alabama Power after it was dismissed from the
original action. As of the date of this report, the EPA alleges that NSR
violations occurred at eight coal-fired generating facilities operated by
Alabama Power, Georgia Power, and Savannah Electric. The civil actions request
penalties and injunctive relief, including an order requiring the installation
of the best available control technology at the affected units. The actions
against Alabama Power, Georgia Power, and Savannah Electric have been stayed
since the spring of 2001 during the appeal of a very similar NSR action against
the Tennessee Valley Authority before the U.S. Court of Appeals for the Eleventh
Circuit. The Eleventh Circuit appeal was decided on September 16, 2003, and on
February 13, 2004, the EPA petitioned the U.S. Supreme Court to review the
Eleventh Circuit's decision. The EPA also filed a motion to lift the stay in the
action against Alabama Power. At this time, no party to the Georgia Power and
Savannah Electric action, which was administratively closed two years ago, has
asked the court to reopen that case. See Note 3 to the financial statements
under "New Source Review Actions" for additional information.
In December 2002 and October 2003, the EPA issued final revisions to its NSR
regulations under the Clean Air Act. The December 2002 revisions included
changes to the regulatory exclusions and the methods of calculating emissions
increases. The October 2003 regulations clarified the scope of the existing
Routine Maintenance, Repair, and Replacement exclusion. A coalition of states
and environmental organizations filed petitions for review of these revisions
with the U.S. Court of Appeals for the District of Columbia Circuit. On December
24, 2003, the court of appeals granted a stay of the October 2003 revisions
pending its review of the rules and ordered that its review be conducted on an
expedited basis. In January 2004, the Bush Administration announced that it
would continue to enforce the existing rules until the courts resolve legal
challenges to the EPA's revised NSR regulations. In any event, the final
regulations must be adopted by the states in the company's service area in order
to apply to facilities in the Southern Company system. The effect of these final
regulations and the related legal challenges cannot be determined at this time.
Southern Company believes that its retail 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.
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 the U.S. District
Court in Georgia against Georgia Power for alleged violations of the Clean Air
Act at four of the units at Plant Wansley. 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. The case is currently
scheduled for trial during the summer of 2004. See Note 3 to the financial
statements under "Plant Wansley Environmental Litigation" for additional
information.
While the company 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
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
- -- both capital and operating -- a major portion of which is expected to be
recovered through existing ratemaking provisions. Environmental costs that are
known and estimable at this time are included in capital expenditures discussed
under "Capital Requirements and Contractual Obligations." 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. Title IV compliance
was effective in 2000 and associated construction expenditures totaled
approximately $400 million. Some of these expenditures 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
II-16
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2003 Annual Report
nonattainment problems in Atlanta, Georgia and Birmingham, Alabama. The states
of Alabama and Georgia adopted regulations that required additional nitrogen
oxide emission reductions from May through September of each year at plants in
and/or near those nonattainment areas. Seven generating plants in the Atlanta
area and two plants in the Birmingham area are currently subject to those
requirements, the most recent of which went into effect in 2003. Construction
expenditures for compliance with the nitrogen oxide emission reduction
requirements are estimated to be approximately $950 million, of which $17
million remains to be spent.
On September 26, 2003, the EPA published a final rule, effective January 1,
2004, reclassifying the Atlanta area from a "serious" to a "severe"
nonattainment area for the one-hour ozone air quality standard under Title I of
the Clean Air Act. The attainment deadline is to be as expeditious as
practicable but not later than November 15, 2005. If the Atlanta area fails to
attain the one-hour ozone standard by the deadline, all major sources of
nitrogen oxides and volatile organic compounds located in the nonattainment
area, including Georgia Power's plants McDonough and Yates, could be subject to
payment of annual emissions fees for nitrogen oxides emitted above 80 percent of
the baseline period. The baseline period is expected to be the calendar year
2005. Based on average emissions at these units over the past three years, such
fees could reach $23 million annually. The final outcome of this matter will
depend on the baseline period selected and the development, approval, and
implementation of applicable regulations, including new regulations for the
eight-hour ozone air quality standard.
In 2002, Gulf Power entered into an agreement with the state of Florida to
install additional controls on certain units and to retire three older units at
a plant near Pensacola to help ensure attainment of the ozone standard in the
area. The conditions of the agreement will be fully implemented by 2005 at a
cost of approximately $133 million, of which $100 million remains to be spent.
Gulf Power's costs have been approved under its environmental cost recovery
clause.
To help ozone nonattainment areas attain 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. Additional construction
expenditures for compliance with these rules are currently estimated at
approximately $360 million, of which $330 million remains to be spent. As a
result of litigation challenging the rule, the courts required the EPA to
complete a separate rulemaking before the requirements can be applied in
Georgia. The final EPA rules have not been issued in Georgia.
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 eight-hour
ozone standard unlawful and remanded it to the EPA for further rulemaking.
During 2003, the EPA proposed implementation rules designed to address the
court's concerns. The EPA plans to designate areas as attainment or
nonattainment with the new eight-hour ozone standard in April 2004 and with the
new fine particulate matter standard by the end of 2004. These designations will
be based on air quality data for 2001 through 2003. Several areas within
Southern Company's service area are likely to be designated nonattainment under
these standards. State implementation plans (SIPs), including new emission
control regulations necessary to bring those areas into attainment, could be
required as early as 2007. These SIPs could require reductions in sulfur dioxide
emissions and 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 and cannot be determined at this time.
In January 2004, the EPA issued a proposed Interstate Air Quality Rule to
address interstate transport of ozone and fine particles. This proposed rule
would require additional year-round sulfur dioxide and nitrogen oxide emission
reductions from power plants in the eastern United States in two phases - in
2010 and 2015. The EPA currently plans to finalize this rule by 2005. If
finalized, the rule could modify or supplant other SIP requirements for
attainment of the fine particulate matter standard and the eight-hour ozone
standard. The impact of this rule on the company will depend upon the specific
requirements of the final rule and cannot be determined at this time.
Further reductions in sulfur dioxide and nitrogen oxides 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 SIPs in 2007. The SIPs must contain emission
II-17
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2003 Annual Report
reduction strategies for implementing BART and achieving progress toward the
Clean Air Act's 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.
The EPA has entered into an agreement that requires proposed revised rules in
April 2004 and final rules in 2005. Because new BART rules have not been
developed and state visibility assessments for progress 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. In 2004 and 2005, a number of the
company's plants will likely become subject to CAM requirements for at least one
pollutant, in most cases particulate matter. The company is in the process of
developing CAM plans. Because the plans are still under development, the company
cannot determine the costs associated with implementation of the CAM
regulations. Actual ongoing monitoring costs are expensed as incurred and are
not material for any year presented.
In January 2004, the EPA issued proposed rules regulating mercury emissions
from electric utility boilers. The proposal solicits comments on two possible
approaches for the new regulations - a Maximum Achievable Control Technology
approach and a cap-and-trade approach. Either approach would require significant
reductions in mercury emissions from company facilities. The regulations are
scheduled to be finalized by the end of 2004, and compliance could be required
as early as 2007. Because the regulations have not been finalized, the impact on
the company cannot be determined at this time.
Several major bills to amend the Clean Air Act to impose more stringent
emissions limitations on power plants have been proposed by Congress. Three of
these, the Bush Administration's Clear Skies Act, the Clean Power Act of 2003,
and the Clean Air Planning Act of 2003, propose to further limit power plant
emissions of sulfur dioxide, nitrogen oxides, and mercury. The latter two bills
also propose to limit emissions of carbon dioxide. The cost impacts of such
legislation would depend upon the specific requirements enacted and cannot be
determined at this time.
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, known
as Climate VISION, 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. The electric
utility sector has pledged to reduce its greenhouse gas intensity 3 percent to 5
percent over the next decade and is in the process of developing a memorandum of
understanding with the Department of Energy (DOE) to cover this voluntary
program.
Southern Company must comply with other environmental laws and regulations
that cover the handling and disposal of 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. Amounts for
cleanup and ongoing monitoring costs were not material for any year presented.
The subsidiaries may be liable for some or all required cleanup costs for
additional sites that may require environmental remediation. See Note 3 to the
financial statements under "Georgia Power Potentially Responsible Status" for
additional information.
Under the Clean Water Act, the EPA has been developing new rules aimed at
reducing impingement and entrainment of fish and fish larvae at power plants'
cooling water intake structures. On February 16, 2004, the EPA finalized these
rules. These rules will require biological studies and, perhaps, retrofits to
some intake structures at existing power plants. The impact of these new rules
will depend on the results of studies and analyses performed as part of the
rules' implementation.
The company is also planning to install cooling towers at some of its
facilities to cool water prior to discharge under the Clean Water Act. Cooling
towers for two Georgia Power plants near Atlanta are scheduled for completion in
2004 and 2008 at a total estimated cost of $160 million, of which $90 million
remains to be spent. Also, Georgia Power is conducting a study of the aquatic
environment at another facility to determine if additional controls are
necessary.
II-18
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2003 Annual Report
In addition, 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 that discharge 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.
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 or
regulations related to global climate change, electromagnetic fields, or other
environmental and health concerns could also significantly affect Southern
Company. The impact of any new legislation, changes to existing legislation, or
environmental regulations could affect many areas of Southern Company's
operations. The full impact of any such changes cannot, however, be determined
at this time.
FERC Matters
Transmission
In December 1999, the Federal Energy Regulatory Commission (FERC) issued its
final rule (Order 2000) on Regional Transmission Organizations (RTOs). Order
2000 encouraged utilities owning transmission systems to form RTOs on a
voluntary basis. Southern Company worked with a number of utilities in the
Southeast to develop a for-profit RTO known as SeTrans. In 2002, the sponsors of
SeTrans established a Stakeholder Advisory Committee to provide input into the
development of the RTO from other sectors of the electric industry, as well as
consumers. During the development of SeTrans, state regulatory authorities
expressed concern over certain aspects of the FERC's policies regarding RTOs. In
December 2003, the SeTrans sponsors announced that they would suspend work on
SeTrans because the regulated utility participants, including Southern Company,
had determined that it was highly unlikely to obtain support of both federal and
state regulatory authorities. Any impact of the FERC's rule on Southern Company
and its subsidiaries will depend on the regulatory reaction to the suspension of
SeTrans and future developments, which 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 day ahead and spot energy markets;
and (7) revise the FERC policy on the pricing of transmission expansions.
Comments on the proposal were submitted by many interested parties, including
Southern Company, and the FERC has indicated that it has revised certain aspects
of the proposal in response to public comments. Proposed energy legislation
would prohibit the FERC from issuing the final rule before October 31, 2006, and
from making any final rule effective before December 31, 2006. That legislation
has been approved by the House of Representatives but remains pending before the
Senate. Passage of the legislation now appears in doubt. It is uncertain whether
in the absence of legislation the FERC will move forward with any part or all of
the proposed rule. Any impact of this proposal on Southern Company and its
subsidiaries will depend on the form in which the final rule may be ultimately
adopted. However, Southern Company's financial statements could be adversely
affected by changes in the transmission regulatory structure in its regional
power market.
Market-Based Rate Authority
Southern Power currently has general authorization from the FERC to sell power
to nonaffiliates at market-based prices. In addition, each of the retail
operating companies has obtained FERC approval to sell power to nonaffiliates at
market-based prices under specific contracts. Southern Power and the retail
operating companies also have FERC authority to make short-term opportunity
sales at market rates. Specific FERC approval must be obtained with respect to a
market-based contract with an affiliate. In November 2001, the FERC modified the
test it uses to consider utilities' applications to charge market-based rates
and adopted a new test called the Supply Margin Assessment (SMA). The FERC
II-19
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2003 Annual Report
applied the SMA to several utilities, including Southern Company, and found
Southern Company and others to be "pivotal suppliers" in their service areas and
ordered the implementation of several mitigation measures. Southern Company and
others sought rehearing of the FERC order, and the FERC delayed the
implementation of certain mitigation measures. Southern Company and others
submitted comments to the FERC in 2002 regarding these issues. In December 2003,
the FERC issued a staff paper discussing alternatives and held a technical
conference in January 2004. Southern Company anticipates that the FERC will
address the requests for rehearing in the near future. Regardless of the outcome
of the SMA proposal, the FERC retains the ability to modify or withdraw the
authorization for any seller to sell at market-based rates, 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. The final outcome of this matter will depend on
the form in which the SMA test and mitigation measures' rules may be ultimately
adopted and cannot be determined at this time.
Purchased Power Agreements (PPAs) by Georgia Power and Savannah Electric for
Southern Power's Plant McIntosh capacity were certified by the Georgia Public
Service Commission in December 2002 after a competitive bidding process. In
April 2003, Southern Power applied for FERC approval of these PPAs. Interveners
opposed the FERC's acceptance of the PPAs, alleging that the PPAs do not meet
the applicable standards for market-based rates between affiliates. In July
2003, the FERC accepted the PPAs to become effective as scheduled on June 1,
2005, subject to refund, and ordered that hearings be held. For additional
information, see Note 3 to the financial statements under "FERC Matters."
Income Tax Matters
Synthetic Fuel Tax Credits
As discussed in Note 3 to the financial statements under "Synthetic Fuel Tax
Credits," Southern Company has investments in two entities that produce
synthetic fuel and receive tax credits under Section 29 of the tax code. Both
entities have received private letter rulings from the Internal Revenue Service
(IRS) concluding that significant chemical change occurred based on the
procedures and results submitted. From the inception of Southern Company's
investment in these entities through December 31, 2003, Southern Company has
recognized through income approximately $274 million (net of approximately $37
million reserved) in tax credits related to its share of the synthetic fuel
production at these entities. However, if the IRS were to challenge these
credits, there could be a significant tax liability due for tax credits
previously taken, which could have a significant impact on earnings and cash
flows.
Leveraged Lease Transactions
As discussed in Note 1 to the financial statements under "Leveraged Leases,"
Southern Company participates in four international leveraged lease
transactions. Southern Company receives federal income tax deductions for rent,
depreciation and amortization, as well as interest on related debt. The IRS has
proposed to disallow the tax losses for one of the lease transactions, as
discussed in Note 3 to the financial statements under "Leveraged Lease
Transactions," resulting in additional taxes and interest of approximately $30
million. Southern Company accounted for this payment as a deposit and filed a
refund claim that the IRS has proposed to disallow. If Southern Company is
unsuccessful in defending its position, additional taxes and interest would be
assessed that could have a material impact on earnings and cash flows. Although
the IRS has not proposed any disallowances related to the three other lease
transactions, subsequent audits may do so. The final outcome of these matters
cannot now be determined.
Other Matters
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 $99 million, $117 million, and $124 million
in 2003, 2002, and 2001, respectively. Future pension income is dependent on
several factors including trust earnings and changes to the plan. The decline in
pension income is expected to continue and become an expense as early as 2006.
Postretirement benefit costs for Southern Company were $101 million, $99
million, and $96 million in 2003, 2002, and 2001, respectively, 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 retail operating companies, pension income or expense and postretirement
benefit costs are a component of the regulated rates and generally do not have a
long-term effect on net income. For more information regarding pension and
postretirement benefits, see Note 2 to the financial statements.
II-20
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2003 Annual Report
On December 8, 2003, President Bush signed into law the Medicare Prescription
Drug, Improvement, and Modernization Act of 2003 (Medicare Act). The Medicare
Act introduces a prescription drug benefit for Medicare-eligible retirees
starting in 2006, as well as a federal subsidy to plan sponsors like Southern
Company that provide prescription drug benefits. In accordance with FASB Staff
Position No. 106-1, Southern Company has elected to defer recognizing the
effects of the Medicare Act for its postretirement plans under FASB Statement
No. 106, Employers' Accounting for Postretirement Benefits Other than Pension
until authoritative guidance on accounting for the federal subsidy is issued or
until a significant event occurs that would require remeasurement of the plans'
assets and obligations. Southern Company anticipates that the benefits it pays
after 2006 will be lower as a result of the Medicare Act; however, the retiree
medical obligations and costs reported in Note 2 to the financial statements do
not reflect these changes. The final accounting guidance could require changes
to previously reported information.
Georgia Power is required to file a general retail rate case in July 2004.
The outcome will have a significant impact on future earnings. See Note 3 to the
financial statements under "Georgia Power Retail Rate Orders" for additional
information.
On May 21, 2003, Mississippi Power and Southern Power entered into agreements
with Dynegy that resolved and terminated in 2003 all outstanding matters related
to capacity sales contracts with subsidiaries of Dynegy. The termination
payments from Dynegy resulted in a one-time gain to Southern Company of
approximately $88 million after tax -- $38 million for Mississippi Power and $50
million for Southern Power. As a result of the Dynegy capacity contract
terminations, Southern Power is completing limited construction activities on
Plant Franklin Unit 3 to preserve the long-term viability of the project but has
deferred final completion until the 2008-2011 period. The length of the deferral
period will depend on forecasted capacity needs and other wholesale market
opportunities. Southern Power is continuing to explore alternatives for its
existing capacity. On December 5, 2003, Mississippi Power filed a request with
the Mississippi Public Service Commission (MPSC) to include 266 megawatts of
Plant Daniel units 3 and 4 generating capacity in jurisdictional cost of
service. See Note 3 to the financial statements under "Uncontracted Generating
Capacity" and "Mississippi Power Regulatory Filing" for additional information.
On July 14, 2003, Mirant filed for voluntary reorganization under Chapter 11
with the U.S. Bankruptcy Court. Southern Company has certain contingent
liabilities associated with guarantees of contractual commitments made by
Mirant's subsidiaries discussed in Note 7 to the financial statements under
"Guarantees" and with various lawsuits related to Mirant discussed in Note 3 to
the financial statements under "Mirant Related Matters." Also, Southern Company
has joint and several liability with Mirant regarding the joint consolidated
federal income tax return as discussed in Note 5 to the financial statements. If
Southern Company is ultimately required to make any payments related to these
potential obligations, Mirant's indemnification obligation to Southern Company
would represent an unsecured pre-bankruptcy claim, subject to compromise
pursuant to Mirant's final reorganization plan.
Nuclear security legislation was recently introduced and considered in
Congress both as a free-standing bill in the Senate and as a part of
comprehensive energy legislation in a House-Senate Conference Report. Neither of
the proposals has been enacted. The Nuclear Regulatory Commission (NRC) also
ordered additional security measures for licensees in 2003. Southern Company is
in the process of implementation and must be in full compliance with these
orders by October 29, 2004. The requirements of the latest orders will have an
impact on Southern Company's nuclear power plants and result in increased
operation and maintenance expenses as well as additional capital expenditures.
The precise impact of the new requirements will depend upon the details of the
implementation of the new requirements, which have not been finalized.
Southern Company is involved in various matters being litigated, regulatory
matters, and significant tax related issues that could affect future earnings.
See Note 3 to the financial statements for information regarding material
issues.
ACCOUNTING POLICIES
- -------------------
Application of Critical Accounting Policies and
Estimates
Southern Company prepares its consolidated financial statements in accordance
with accounting principles generally accepted in the United States. Significant
accounting policies are described in Note 1 to the financial statements. In the
application of these policies, certain estimates are made that may have a
material impact on Southern Company's results of operations and related
disclosures. Different assumptions and measurements could produce estimates that
are significantly different from those recorded in the financial statements.
Senior management has discussed the development and selection of the critical
II-21
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2003 Annual Report
accounting policies and estimates described below with the Audit Committee of
Southern Company's Board of Directors.
Electric Utility Regulation
Southern Company's retail operating companies, which comprise approximately 85
percent of Southern Company's total earnings, are subject to retail regulation
by their respective state public service commissions and wholesale regulation by
the FERC. These regulatory agencies set the rates the retail operating companies
are permitted to charge customers based on allowable costs. As a result, the
retail operating companies apply FASB Statement No. 71, Accounting for the
Effects of Certain Types of Regulation. Through the ratemaking process, the
regulators may require the inclusion of costs or revenues in periods different
than when they would be recognized by a non-regulated company. This treatment
may result in the deferral of expenses and the recording of related regulatory
assets based on anticipated future recovery through rates or the deferral of
gains or creation of liabilities and the recording of related regulatory
liabilities. The application of Statement No. 71 has a further effect on the
company's financial statements as a result of the estimates of allowable costs
used in the ratemaking process. These estimates may differ from those actually
incurred by the retail operating companies; therefore, the accounting estimates
inherent in specific costs such as depreciation, nuclear decommissioning, and
pension and post-retirement benefits have less of a direct impact on the
company's results of operations than they would on a non-regulated company.
As reflected in Note 1 to the financial statements, significant regulatory
assets and liabilities have been recorded. Management reviews the ultimate
recoverability of these regulatory assets and liabilities based on applicable
regulatory guidelines. However, adverse legislation and judicial or regulatory
actions could materially impact the amounts of such regulatory assets and
liabilities and could adversely impact the company's financial statements.
Contingent Obligations
Southern Company and its subsidiaries are subject to a number of federal and
state laws and regulations, as well as other factors and conditions that
potentially subject them to environmental, litigation, income tax, and other
risks. See "Future Earnings Potential" and Note 3 to the financial statements
for more information regarding certain of these contingencies. Southern Company
and its subsidiaries periodically evaluate their exposure to such risks and
record reserves for those matters where a loss is considered probable and
reasonably estimable in accordance with generally accepted accounting
principles. The adequacy of reserves can be significantly affected by external
events or conditions that can be unpredictable; thus, the ultimate outcome of
such matters could materially affect Southern Company's financial statements or
those of its subsidiaries. These events or conditions include the following:
o Changes in existing state or federal regulation by governmental authorities
having jurisdiction over air quality, water quality, control of toxic
substances, hazardous and solid wastes, and other environmental matters.
o Changes in existing income tax regulations or changes in IRS interpretations
of existing regulations.
o Identification of additional sites that require environmental remediation or
the filing of other complaints in which Southern Company or its subsidiaries
may be asserted to be a potentially responsible party.
o Identification and evaluation of other potential lawsuits or complaints in
which Southern Company or its subsidiaries may be named as a defendant.
o Resolution or progression of existing matters through the legislative
process, the court systems, the IRS, or the EPA.
Plant Daniel Capacity
As discussed in Note 3 to the financial statements, Mississippi Power requested
and received an interim accounting order from the MPSC on December 16, 2003. The
order directed Mississippi Power to expense and record in 2003 a regulatory
liability of $60 million pending the conclusion of the MPSC's evaluation of
Mississippi Power's request to include an additional 266 megawatts of Plant
Daniel units 3 and 4 generating capacity in jurisdictional cost of service. The
MPSC is not expected to complete its evaluation and issue a final order until
the second quarter of 2004. Management believes that the interim accounting
order represents a probable liability and that recognition of the expense in
2003 is appropriate. However, if the MPSC ultimately refuses Mississippi Power's
request, the regulatory liability will be required to be reversed.
New Accounting Standards
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 established new accounting and reporting standards for legal
obligations associated with the ultimate cost of retiring long-lived assets. The
II-22
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2003 Annual Report
present value of the ultimate costs for an asset's future retirement is recorded
in the period in which the liability is incurred. The costs are capitalized as
part of the related long-lived asset and depreciated over the asset's useful
life. Additionally, non-regulated companies are no longer permitted 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 "Asset Retirement Obligations and Other Costs of Removal."
FASB Statement No. 149, Amendment of Statement 133 on Derivative Instruments
and Hedging Activities, which further amends and clarifies the accounting and
reporting for derivative instruments, became effective generally for financial
instruments entered into or modified after June 30, 2003. Current
interpretations of Statement No. 149 indicate that certain electricity forward
transactions subject to unplanned netting -- including those typically referred
to as "book outs" -- may only qualify as cash flow hedges if an entity can
demonstrate that physical delivery or receipt of power occurred. Southern
Company's forward electricity contracts continue to be exempt from fair value
accounting requirements or to qualify as cash flow hedges, with the related
gains and losses deferred in other comprehensive income. The implementation of
Statement No. 149 did not have a material effect on Southern Company's financial
statements.
In July 2003, the Emerging Issues Task Force (EITF) of FASB issued EITF No.
03-11, which became effective on October 1, 2003. The standard addresses the
reporting of realized gains and losses on derivative instruments and is being
interpreted to require book outs to be recorded on a net basis in operating
revenues. Adoption of this standard did not have a material impact on Southern
Company's financial statements.
FASB Interpretation No. 46, Consolidation of Variable Interest Entities,
which was originally issued in January 2003, requires the primary beneficiary of
a variable interest entity to consolidate the related assets and liabilities.
Southern Company's previous interest in a variable interest entity related to
Mississippi Power's lease arrangement for certain facilities at Plant Daniel was
restructured prior to the original effective date of July 1, 2003, and is no
longer subject to Interpretation No. 46. See Note 7 to the financial statements
under "Operating Leases" for additional information. In December 2003, the FASB
revised Interpretation No. 46 and deferred the effective date until March 31,
2004, for interests held in variable interest entities other than special
purpose entities.
Current analysis indicates that the trusts established by Southern Company
and the retail operating companies to issue preferred securities are variable
interest entities under Interpretation No. 46, and that Southern Company and the
retail operating companies are not the primary beneficiaries of these trusts. If
this conclusion is finalized, effective March 31, 2004, the trust assets and
liabilities -- including the preferred securities issued by the trusts -- will
be deconsolidated. The investments in the trusts and the loans from the trusts
to Southern Company and the retail operating companies will be reflected as
equity method investments and as long-term notes payable to affiliates,
respectively, on the Consolidated Balance Sheets. Based on December 31, 2003
values, this treatment would result in an increase of approximately $59 million
to both total assets and total liabilities. See Note 6 to the financial
statements under "Mandatorily Redeemable Preferred Securities" for additional
information.
Southern Company has also identified certain other significant variable
interest investments. These include two entities that produce synthetic fuel and
are further described in Note 3 to the financial statements under "Synthetic
Fuel Tax Credits." Southern Company is not the primary beneficiary of these
entities. Southern Company also holds an 85 percent limited partnership
investment in an energy/telecom venture capital fund that is currently accounted
for under the equity method. At December 31, 2003, this investment totaled $17
million; the company has committed to a maximum investment of $75 million.
Southern Company is continuing to review its transactions in light of the
revised Interpretation No. 46; however, adoption is not currently expected to
have a material impact on Southern Company's financial statements.
In May 2003, the FASB issued Statement No. 150, Accounting for Certain
Financial Instruments with Characteristics of Both Liabilities and Equity, which
requires classification of certain financial instruments within its scope,
including shares that are mandatorily redeemable, as liabilities. Statement No.
150 was effective for financial instruments entered into or modified after May
31, 2003, and otherwise on July 1, 2003. In accordance with Statement No. 150,
mandatorily redeemable preferred securities are reflected in the Consolidated
Balance Sheets as liabilities. The adoption of Statement No. 150 had no impact
on the Consolidated Statements of Income and Cash Flows.
II-23
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2003 Annual Report
FINANCIAL CONDITION AND LIQUIDITY
- ---------------------------------
Overview
Southern Company's financial condition continues to be strong. At December 31,
2003, each of the retail operating companies was within its allowed range of
return on equity. They operated at high levels of reliability while achieving
industry-leading customer satisfaction levels and continuing to have retail
prices below the national average. Also, earnings from the competitive
generation business and other business activities made a significant
contribution to the company's earnings goal of 5 percent average long-term
growth.
At the close of 2003, the market value of Southern Company's common stock was
$30.25 per share, compared with book value of $13.13 per share. The
market-to-book value ratio was 230 percent at the end of 2003, compared with 233
percent at year-end 2002.
Gross property additions to utility plant were $2.0 billion in 2003. The
majority of funds needed for gross property additions since 2000 has been
provided from operating activities. The Consolidated Statements of Cash Flows
provide additional details.
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 2004
- -- 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 2004. Equity capital can be provided from any combination of the
company's stock plans, private placements, or public offerings.
The retail 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 operating cash flows. 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
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.
Southern Company and each operating company obtain financing separately
without credit support from any affiliate. Currently, Southern Company provides
limited credit support to Southern Power. See Note 6 to the financial statements
under "Bank Credit Arrangements" for additional information. The Southern
Company system does not maintain a centralized cash or money pool. Therefore,
funds of each company are not commingled with funds of any other company. In
accordance with the Public Utility Holding Company Act, most loans between
affiliated companies must be approved in advance by the Securities and Exchange
Commission (SEC).
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.
To meet short-term cash needs and contingencies, Southern Company has various
internal and external sources of liquidity. At the beginning of 2004, Southern
Company and its subsidiaries had approximately $311 million of cash and cash
equivalents and $3.5 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, including
commercial paper programs, to meet liquidity needs. Cash flows from operating
activities were $3.1 billion in 2003, $2.8 billion in 2002, and $2.4 billion in
2001.
At the beginning of 2004, bank credit arrangements are as follows:
Expires
------------------------------
2005
Total Unused 2004 & Beyond
- ----------------------------------------------------------------
(in millions)
$3,496 $3,476 $2,806 $670
- ----------------------------------------------------------------
Approximately $2.25 billion of the credit facilities expiring in 2004 allow
for the execution of term loans for an additional two-year period and $265
million allow for the execution for one-year term loans. See Note 6 to the
financial statements under "Bank Credit Arrangements" for additional
information.
II-24
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2003 Annual Report
Financing Activities
During 2003, Southern Company and its subsidiaries issued $3.5 billion of
long-term debt and $125 million of preferred securities. In addition, Southern
Company issued 18 million new shares of common stock through the company's stock
plans and realized proceeds of $470 million. The issuances were used to refund
$3.0 billion of long-term debt and $480 million of mandatorily redeemable
preferred securities and to provide $575 million of permanent financing for
Southern Power's new generating facilities. The remainder was used to reduce
short-term debt, provide capital contributions to subsidiaries, and fund
Southern Company's ongoing construction program.
Subsequent to December 31, 2003, the retail operating companies have issued
$850 million of securities to redeem $400 million of long-term debt and
mandatorily redeemable preferred securities and for other corporate purposes.
Off-Balance Sheet Financing Arrangements
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. In 2003, the generating
facility was acquired by Juniper Capital L.P. (Juniper), a limited partnership
whose investors are unaffiliated with Mississippi Power. Simultaneously, Juniper
entered into a restructured lease agreement with Mississippi Power. Juniper has
also entered into leases with other parties unrelated to Mississippi Power. The
assets leased by Mississippi Power comprise less than 50 percent of Juniper's
assets. Mississippi Power is not required to consolidate the leased assets and
related liabilities, and the lease with Juniper is considered an operating lease
under FASB Statement No. 13. The lease also provides for a residual value
guarantee -- approximately 73 percent of the acquisition cost -- by Mississippi
Power that is due upon termination of the lease in the event that the company
does not renew the lease or purchase the assets and that the fair market value
is less than the unamortized cost of the assets. See Note 7 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
purchases and sales, fixed-price physical gas purchases, and agreements covering
interest rate swaps. At December 31, 2003, the maximum potential collateral
requirements under the electricity purchase and sale contracts were
approximately $415 million. Generally, collateral may be provided for by a
Southern Company guaranty, a letter of credit, or cash. At December 31, 2003,
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
and certain energy-related 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.
To mitigate exposure to interest rates, the company has entered into interest
rate swaps that have been designated as hedges. The weighted average interest
rate on $1.0 billion variable long-term debt that has not been hedged at
December 31, 2003 was 1.5 percent. If Southern Company sustained a 100 basis
point change in interest rates for all unhedged variable rate long-term debt,
the change would affect annualized interest expense by approximately $10 million
at December 31, 2003. 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 6 to the financial statements under "Financial
Instruments."
Due to cost-based rate regulations, the retail 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 retail operating companies and Southern Power enter into
II-25
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2003 Annual Report
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. The retail operating companies have implemented fuel-hedging
programs at the instruction of their respective public service commissions.
Southern Company GAS also has gas-hedging programs to substantially mitigate its
exposure to price volatility for its gas purchases.
The fair value of changes in energy-related derivative contracts and year-end
valuations were as follows at December 31:
Changes in Fair Value
- ----------------------------------------------------------------
2003 2002
- ----------------------------------------------------------------
(in millions)
Contracts beginning of year $ 47.3 $ 1.3
Contracts realized or settled (73.2) (32.2)
New contracts at inception - -
Changes in valuation techniques - -
Current period changes 41.7 78.2
- ----------------------------------------------------------------
Contracts end of year $ 15.8 $ 47.3
================================================================
Source of 2003 Year-End Valuation Prices
- ---------------------------------------------------------------
Maturity
Total ---------------------
Fair Value 2004 2005-2006
- ---------------------------------------------------------------
(in millions)
Actively quoted $15.8 $16.9 $(1.1)
External sources - - -
Models and other
methods - - -
- ---------------------------------------------------------------
Contracts end of year $15.8 $16.9 $(1.1)
===============================================================
Unrealized gains and losses from mark to market adjustments on derivative
contracts related to the retail operating companies' 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 retail
operating companies' fuel cost recovery clauses. In addition, unrealized gains
and losses on energy-related derivatives used by Southern Power and Southern
Company GAS to hedge anticipated purchases and sales are deferred in other
comprehensive income. Gains and losses on derivative contracts that are not
designated as hedges are recognized in the income statement as incurred. At
December 31, 2003, the fair value of derivative energy contracts was reflected
in the financial statements as follows:
Amounts
- ----------------------------------------------------------------
(in millions)
Regulatory liabilities, net $14.9
Other comprehensive income 1.5
Net income (0.6)
- ----------------------------------------------------------------
Total fair value $15.8
================================================================
Unrealized pre-tax gains (losses) of $(2) million, $(5) million, and $9
million were recognized in income in 2003, 2002, and 2001, respectively.
Southern Company is exposed to market price risk in the event of nonperformance
by counterparties 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 6 to the financial
statements under "Financial Instruments."
Capital Requirements and Contractual Obligations
The construction program of Southern Company is currently estimated to be $2.2
billion for 2004, $2.2 billion for 2005, and $2.6 billion for 2006.
Environmental expenditures included in these amounts are $349 million, $403
million, and $646 million for 2004, 2005, and 2006, respectively. 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 1,200 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. In addition,
II-26
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2003 Annual Report
capital improvements, including those needed to meet the environmental standards
previously discussed for the retail operating companies' generation,
transmission, and distribution facilities are ongoing.
As a result of requirements by the NRC, 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 "Nuclear
Decommissioning." Also, as discussed in Note 1 to the financial statements under
"Revenues and Fuel Costs," in 1993 the DOE implemented a special assessment over
a 15-year period on utilities with nuclear plants to be used for the
decontamination and decommissioning of its nuclear fuel enrichment facilities.
In addition, 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 retail operating companies'
respective regulatory commissions.
Other funding requirements related to obligations associated with scheduled
maturities of long-term debt and preferred securities, as well as the related
interest and distributions, preferred stock dividends, leases, and other
purchase commitments are as follows. See notes 1, 6, and 7 to the financial
statements for additional information.
2005- 2007- After
2004 2006 2008 2008 Total
- -------------------------------------------------------------------------------------------------------------------------------
(in millions)
Long-term debt and preferred securities(a) --
Principal $ 741 $ 1,842 $1,448 $ 8,795 $12,826
Interest and distributions 614 1,116 968 8,468 11,166
Preferred stock dividends(b) 22 44 44 - 110
Operating leases 128 208 143 262 741
Purchase commitments(c) --
Capital(d) 2,121 4,799 - - 6,920
Coal and nuclear fuel 2,409 3,198 1,675 182 7,464
Natural gas(e) 814 1,029 619 2,763 5,225
Purchased power 139 355 367 918 1,779
Long-term service agreements 54 98 169 988 1,309
Trusts --
Nuclear decommissioning 29 58 58 317 462
Postretirement benefits(f) 15 75 - - 90
DOE 8 16 - - 24
- ------------------------------------------------------------------------------------------------------------------------------
Total $7,094 $12,838 $5,491 $22,693 $48,116
==============================================================================================================================
(a) All amounts are reflected based on final maturity dates. Southern Company and the subsidiaries will continue to retire
higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. Variable rate
interest obligations are estimated based on rates as of January 1, 2004, as reflected in the Consolidated Statements of
Capitalization.
(b) Preferred stock does not mature; therefore, amounts are provided for the next five years only.
(c) Southern Company generally does not enter into non-cancelable commitments for other operation and maintenance expenditures.
Total other operation and maintenance expenses for the last three years were $3.2 billion, $3.1 billion, and $2.8 billion,
respectively.
(d) Southern Company forecasts capital expenditures over a three-year period.Amounts represent current estimates of total
expenditures excluding those amounts related to contractual purchase commitments for uranium and nuclear fuel conversion,
enrichment, and fabrication services. At December 31, 2003, significant purchase commitments were outstanding in connection
with the construction program.
(e) Natural gas purchase commitments are based on various indices at the time of delivery. Amounts reflected have been estimated
based on the New York Mercantile future prices at December 31, 2003.
(f) Southern Company forecasts postretirement trust contributions over a three-year period. No contributions related to Southern
Company's pension trust are currently expected during this period. See Note 2 to the financial statements for additional
information related to the pension plans.
II-27
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2003 Annual Report
Cautionary Statement Regarding Forward-Looking Information
Southern Company's 2003 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 and other expenditures, and Southern
Company's projections for energy sales and its goals for future generating
capacity, dividend payout 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:
o 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, tax, 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;
o current and future litigation, regulatory investigations, proceedings, or
inquiries, including the pending EPA civil actions against certain Southern
Company subsidiaries and current IRS audits;
o the effects, extent, and timing of the entry of additional competition in the
markets in which Southern Company's subsidiaries operate;
o the impact of fluctuations in commodity prices, interest rates, and customer
demand;
o available sources and costs of fuels;
o ability to control costs;
o investment performance of Southern Company's employee benefit plans;
o advances in technology;
o state and federal rate regulations and pending and future rate cases and
negotiations;
o effects of and changes in political, legal, and economic conditions and
developments in the United States, including the current soft economy;
o the performance of projects undertaken by the non-traditional business and
the success of efforts to invest in and develop new opportunities;
o internal restructuring or other restructuring options that may be pursued;
o 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;
o the ability of counterparties of Southern Company and its subsidiaries to
make payments as and when due;
o the ability to obtain new short- and long-term contracts with neighboring
utilities;
o the direct or indirect effects on Southern Company's business resulting from
the terrorist incidents on September 11, 2001, or any similar incidents or
responses to such incidents;
o financial market conditions and the results of financing efforts, including
Southern Company's and its subsidiaries' credit ratings;
o the ability of Southern Company and its subsidiaries to obtain additional
generating capacity at competitive prices;
o weather and other natural phenomena;
o the direct or indirect effects on Southern Company's business resulting from
the August 2003 power outage in the Northeast, or any similar incidents;
o the effect of accounting pronouncements issued periodically by
standard-setting bodies; and
o other factors discussed elsewhere herein and in other reports (including the
Form 10-K) filed from time to time with the SEC.
II-28
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2003, 2002, and 2001
Southern Company and Subsidiary Companies 2003 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------------
2003 2002 2001
- ----------------------------------------------------------------------------------------------------------------------------------
(in millions)
Operating Revenues:
Retail sales $ 8,875 $ 8,728 $ 8,440
Sales for resale 1,358 1,168 1,174
Other electric revenues 514 310 292
Other revenues 504 343 249
- ----------------------------------------------------------------------------------------------------------------------------------
Total operating revenues 11,251 10,549 10,155
- ----------------------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Fuel 3,031 2,767 2,577
Purchased power 473 449 718
Other operations 2,302 2,118 1,899
Maintenance 937 965 862
Depreciation and amortization 1,027 1,047 1,173
Taxes other than income taxes 586 557 535
- ----------------------------------------------------------------------------------------------------------------------------------
Total operating expenses 8,356 7,903 7,764
- ----------------------------------------------------------------------------------------------------------------------------------
Operating Income 2,895 2,646 2,391
Other Income and (Expense):
Allowance for equity funds used during construction 25 22 22
Interest income 36 22 27
Equity in losses of unconsolidated subsidiaries (184) (154) (52)
Leveraged lease income 66 58 59
Interest expense, net of amounts capitalized (527) (492) (557)
Distributions on mandatorily redeemable preferred securities (151) (175) (169)
Preferred dividends of subsidiaries (21) (17) (18)
Other income (expense), net (53) (64) (26)
- ----------------------------------------------------------------------------------------------------------------------------------
Total other income and (expense) (809) (800) (714)
- ----------------------------------------------------------------------------------------------------------------------------------
Earnings From Continuing Operations Before Income Taxes 2,086 1,846 1,677
Income taxes 612 528 558
- ----------------------------------------------------------------------------------------------------------------------------------
Earnings From Continuing Operations Before
Cumulative Effect of Accounting Change 1,474 1,318 1,119
Cumulative effect of accounting change -
less income taxes of less than $1 - - 1
- ----------------------------------------------------------------------------------------------------------------------------------
Earnings From Continuing Operations 1,474 1,318 1,120
Earnings from discontinued operations,
net of income taxes of $93 - - 142
- ----------------------------------------------------------------------------------------------------------------------------------
Consolidated Net Income $ 1,474 $ 1,318 $ 1,262
==================================================================================================================================
Common Stock Data:
Earnings per share from continuing operations -
Basic $2.03 $1.86 $1.62
Diluted 2.02 1.85 1.61
Earnings per share including discontinued operations -
Basic $2.03 $1.86 $1.83
Diluted 2.02 1.85 1.82
- ----------------------------------------------------------------------------------------------------------------------------------
Average number of shares of common stock outstanding - (in millions)
Basic 727 708 689
Diluted 732 714 694
- ----------------------------------------------------------------------------------------------------------------------------------
Cash dividends paid per share of common stock $1.385 $1.355 $1.34
- ----------------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
II-29
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2003, 2002, and 2001
Southern Company and Subsidiary Companies 2003 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------------
2003 2002 2001
- ----------------------------------------------------------------------------------------------------------------------------------
(in millions)
Operating Activities:
Consolidated net income $ 1,474 $ 1,318 $ 1,262
Adjustments to reconcile consolidated net income
to net cash provided from operating activities --
Less earnings from discontinued operations - - 142
Depreciation and amortization 1,163 1,136 1,358
Deferred income taxes and investment tax credits 451 166 (22)
Plant Daniel capacity 60 - -
Deferred capacity revenues (15) (8) -
Equity in losses of unconsolidated subsidiaries 94 91 52
Leveraged lease income (66) (58) (59)
Pension, postretirement, and other employee benefits (19) (65) (101)
Tax benefit of stock options 30 23 -
Settlement of interest rate hedges (116) (16) -
Other, net 11 38 (98)
Changes in certain current assets and liabilities --
Receivables, net 7 (121) 327
Fossil fuel stock (17) 105 (199)
Materials and supplies (12) 8 (43)
Other current assets 27 (58) (12)
Accounts payable (68) 108 (51)
Accrued taxes 19 (49) 91
Other current liabilities 43 235 21
- ----------------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities of continuing operations 3,066 2,853 2,384
- ----------------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (2,002) (2,717) (2,617)
Investment in unconsolidated subsidiaries (72) (90) (50)
Cost of removal net of salvage (80) (109) (99)
Other (40) (52) 30
- ----------------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities of continuing operations (2,194) (2,968) (2,736)
- ----------------------------------------------------------------------------------------------------------------------------------
Financing Activities:
Increase (decrease) in notes payable, net (366) (968) 223
Proceeds --
Long-term debt 3,494 2,914 1,999
Mandatorily redeemable preferred securities - 1,315 30
Preferred stock 125 - -
Common stock 470 428 395
Redemptions --
Long-term debt (3,009) (1,370) (1,185)
Mandatorily redeemable preferred securities (480) (1,171) -
Preferred stock - (70) -
Payment of common stock dividends (1,004) (958) (922)
Other (64) (86) (33)
- ----------------------------------------------------------------------------------------------------------------------------------
Net cash provided from (used for)
financing activities of continuing operations (834) 34 507
- ----------------------------------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents 38 (81) 155
Cash and Cash Equivalents at Beginning of Year 273 354 199
- ----------------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 311 $ 273 $ 354
==================================================================================================================================
The accompanying notes are an integral part of these financial statements.
II-30
CONSOLIDATED BALANCE SHEETS
At December 31, 2003 and 2002
Southern Company and Subsidiary Companies 2003 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------------
Assets 2003 2002
- ----------------------------------------------------------------------------------------------------------------------------------
(in millions)
Current Assets:
Cash and cash equivalents $ 311 $ 273
Receivables --
Customer accounts receivable 696 712
Unbilled revenues 275 277
Under recovered regulatory clause revenues 188 174
Other accounts and notes receivable 339 370
Accumulated provision for uncollectible accounts (30) (26)
Fossil fuel stock, at average cost 316 299
Vacation pay 97 98
Materials and supplies, at average cost 571 560
Prepaid expenses 124 126
Other 30 66
- ----------------------------------------------------------------------------------------------------------------------------------
Total current assets 2,917 2,929
- ----------------------------------------------------------------------------------------------------------------------------------
Property, Plant, and Equipment:
In service 40,340 37,486
Less accumulated depreciation 14,304 13,505
- ----------------------------------------------------------------------------------------------------------------------------------
26,036 23,981
Nuclear fuel, at amortized cost 223 223
Construction work in progress 1,275 2,362
- ----------------------------------------------------------------------------------------------------------------------------------
Total property, plant, and equipment 27,534 26,566
- ----------------------------------------------------------------------------------------------------------------------------------
Other Property and Investments:
Nuclear decommissioning trusts, at fair value 808 639
Leveraged leases 838 791
Other 238 243
- ----------------------------------------------------------------------------------------------------------------------------------
Total other property and investments 1,884 1,673
- ----------------------------------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets:
Deferred charges related to income taxes 874 898
Prepaid pension costs 911 786
Unamortized debt issuance expense 152 145
Unamortized loss on reacquired debt 326 313
Other 447 411
- ----------------------------------------------------------------------------------------------------------------------------------
Total deferred charges and other assets 2,710 2,553
- ----------------------------------------------------------------------------------------------------------------------------------
Total Assets $35,045 $33,721
==================================================================================================================================
The accompanying notes are an integral part of these financial statements.
II-31
CONSOLIDATED BALANCE SHEETS (continued)
At December 31, 2003 and 2002
Southern Company and Subsidiary Companies 2003 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------------
Liabilities and Stockholders' Equity 2003 2002
- ----------------------------------------------------------------------------------------------------------------------------------
(in millions)
Current Liabilities:
Securities due within one year $ 741 $ 1,679
Notes payable 568 972
Accounts payable 700 797
Customer deposits 189 169
Accrued taxes --
Income taxes 154 81
Other 249 219
Accrued interest 187 158
Accrued vacation pay 129 130
Accrued compensation 437 440
Other 263 342
- ----------------------------------------------------------------------------------------------------------------------------------
Total current liabilities 3,617 4,987
- ----------------------------------------------------------------------------------------------------------------------------------
Long-term debt (See accompanying statements) 10,164 8,714
- ----------------------------------------------------------------------------------------------------------------------------------
Mandatorily redeemable preferred securities (See accompanying statements) 1,900 2,380
- ----------------------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 4,586 4,203
Deferred credits related to income taxes 409 450
Accumulated deferred investment tax credits 579 607
Employee benefit obligations 765 661
Asset retirement obligations 845 -
Other cost of removal obligations 1,269 1,944
Miscellaneous regulatory liabilities 576 464
Other 264 303
- ----------------------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 9,293 8,632
- ----------------------------------------------------------------------------------------------------------------------------------
Total liabilities 24,974 24,713
Cumulative preferred stock of subsidiaries (See accompanying statements) 423 298
Common stockholders' equity (See accompanying statements) 9,648 8,710
- ----------------------------------------------------------------------------------------------------------------------------------
Total Liabilities and Stockholders' Equity $35,045 $33,721
==================================================================================================================================
Commitments and Contingent Matters (See notes)
- ----------------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
II-32
CONSOLIDATED STATEMENTS OF CAPITALIZATION
At December 31, 2003 and 2002
Southern Company and Subsidiary Companies 2003 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------------
2003 2002 2003 2002
- ----------------------------------------------------------------------------------------------------------------------------------
(in millions) (percent of total)
Long-Term Debt of Subsidiaries:
First mortgage bonds --
Maturity Interest Rates
-------- ---------------
2006 6.50% to 6.90% $ 45 $ 45
2023 through 2026 6.88% to 7.45% 60 93
- ----------------------------------------------------------------------------------------------------------------------------------
Total first mortgage bonds 105 138
- ----------------------------------------------------------------------------------------------------------------------------------
Long-term senior notes and debt --
Maturity Interest Rates
-------- --------------
2003 4.69% to 7.85% - 847
2004 4.88% to 7.25% 580 579
2005 5.49% to 7.25% 379 383
2006 1.60% to 6.20% 679 154
2007 4.88% to 7.13% 905 905
2008 3.13% to 6.55% 458 208
2009 through 2048 4.35% to 8.12% 4,284 3,227
Adjustable rates:
2003 1.52% to 1.53% - 517
2004 1.27% to 2.44% 89 512
2005 1.25% to 2.44% 492 211
2006 1.37% 195 -
2007 2.57% to 4.13% 72 50
- ----------------------------------------------------------------------------------------------------------------------------------
Total long-term senior notes and debt 8,133 7,593
- ----------------------------------------------------------------------------------------------------------------------------------
Other long-term debt --
Pollution control revenue bonds --
Maturity Interest Rates
-------- ---------------
Collateralized:
2006 5.25% 12 12
2007 5.80% - 1
2023 through 2026 5.50% to 5.80% 24 86
Variable rates (at 1/1/04)
2015 through 2017 1.27% to 1.33% 90 90
Non-collateralized:
2012 through 2034 1.20% to 5.45% 850 789
Variable rates (at 1/1/04)
2011 through 2038 1.05% to 1.45% 1,565 1,564
- ----------------------------------------------------------------------------------------------------------------------------------
Total other long-term debt 2,541 2,542
- ----------------------------------------------------------------------------------------------------------------------------------
Capitalized lease obligations 107 106
- ----------------------------------------------------------------------------------------------------------------------------------
Unamortized debt (discount), net (21) (26)
- ----------------------------------------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
requirement -- $485 million) 10,865 10,353
Less amount due within one year 701 1,639
- ----------------------------------------------------------------------------------------------------------------------------------
Long-term debt excluding amount due within one year 10,164 8,714 45.9% 43.4%
- ----------------------------------------------------------------------------------------------------------------------------------
II-33
CONSOLIDATED STATEMENTS OF CAPITALIZATION (continued)
At December 31, 2003 and 2002
Southern Company and Subsidiary Companies 2003 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------------
2003 2002 2003 2002
- ----------------------------------------------------------------------------------------------------------------------------------
(in millions) (percent of total)
Mandatorily Redeemable Preferred Securities:
Maturity Interest Rates
- -------- ---------------
$25 liquidation value --
2028 through 2042 6.85% to 7.63% 944 1,380
$1,000 liquidation value --
2027 through 2042 4.75% to 8.19% 996 1,040
- ----------------------------------------------------------------------------------------------------------------------------------
Total mandatorily redeemable preferred securities
(annual distribution requirement -- $182 million) 1,940 2,420
Less amount due within one year 40 40
- ----------------------------------------------------------------------------------------------------------------------------------
Total mandatorily redeemable preferred securities
excluding amounts due within one year 1,900 2,380 8.6 11.8
- ----------------------------------------------------------------------------------------------------------------------------------
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
$100,000 stated value --
4.95% 125 -
- ----------------------------------------------------------------------------------------------------------------------------------
Total cumulative preferred stock of subsidiaries
(annual dividend requirement -- $22 million) 423 298 1.9 1.5
- ----------------------------------------------------------------------------------------------------------------------------------
Common Stockholders' Equity:
Common stock, par value $5 per share --
Authorized -- 1 billion shares
Issued -- 2003: 735 million shares
-- 2002: 717 million shares
Treasury -- 2003: 0.2 million shares
-- 2002: 0.1 million shares
Par value 3,675 3,583
Paid-in capital 747 338
Treasury, at cost (4) (3)
Retained earnings 5,343 4,874
Accumulated other comprehensive income (loss) (113) (82)
- ----------------------------------------------------------------------------------------------------------------------------------
Total common stockholders' equity 9,648 8,710 43.6 43.3
- ----------------------------------------------------------------------------------------------------------------------------------
Total Capitalization $22,135 $20,102 100.0% 100.0%
==================================================================================================================================
The accompanying notes are an integral part of these financial statements.
II-34
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY
For the Years Ended December 31, 2003, 2002, and 2001
Southern Company and Subsidiary Companies 2003 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, 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
Net income - - - 1,474 - - 1,474
Other comprehensive income (loss) - - - - (31) - (31)
Stock issued 92 408 - - - - 500
Cash dividends - - - (1,004) - - (1,004)
Other - 1 (1) (1) - - (1)
- ----------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2003 $3,675 $ 747 $ (4) $ 5,343 $(113) $ - $ 9,648
==================================================================================================================================
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2003, 2002, and 2001
Southern Company and Subsidiary Companies 2003 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------------
2003 2002 2001
- ----------------------------------------------------------------------------------------------------------------------------------
(in millions)
Consolidated Net Income $1,474 $1,318 $ 1,262
- ----------------------------------------------------------------------------------------------------------------------------------
Other comprehensive income (loss) -- continuing operations:
Change in additional minimum pension liability,
net of tax of $(11) and $(18), respectively (17) (31) -
Changes in fair value of qualifying hedges,
net of tax of $(2), $(45), and $4, respectively (17) (60) 7
Less: Reclassification adjustment for amounts included in net income,
net of tax of $1 and $1, respectively 3 2 -
- ----------------------------------------------------------------------------------------------------------------------------------
Total other comprehensive income (loss) -- continuing operations (31) (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) - - (22)
- ----------------------------------------------------------------------------------------------------------------------------------
Total other comprehensive income (loss) -- discontinued operations - - (315)
- ----------------------------------------------------------------------------------------------------------------------------------
Consolidated Comprehensive Income $1,443 $1,229 $ 954
==================================================================================================================================
The accompanying notes are an integral part of these financial statements.
II-35
NOTES TO FINANCIAL STATEMENTS
Southern Company and Subsidiary Companies 2002 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Southern Company is the parent company of five retail operating companies,
Southern Power Company (Southern Power), Southern Company Services (SCS),
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 retail 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 retail
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 -- the system service company
- -- provides, at cost, specialized services to Southern Company and subsidiary
companies. Southern LINC provides digital wireless communications services to
the retail 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 is a competitive retail natural gas marketer
serving customers in Georgia. Southern Holdings is an intermediate holding
subsidiary for Southern Company's investments in synthetic fuels and leveraged
leases and an energy services business. Southern Nuclear operates and 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 regarding Mirant, see Note 3 under "Mirant Related Matters."
The financial statements reflect Southern Company's investments in the
subsidiaries on a consolidated basis. The equity method is used for subsidiaries
in which the company has significant influence but does not control. 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 retail
operating companies and Southern Power are subject to regulation by the FERC,
and the retail 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.
Related Party Transactions
Alabama Power and Georgia Power purchase synthetic fuel from Alabama Fuel
Products, LLC (AFP), an entity in which Southern Holdings holds a 30 percent
ownership interest. Total fuel purchases for 2003 and 2002 were $301 million and
$211 million, respectively. The financial statements reflect the elimination
of 30 percent of these amounts. Another subsidiary of Southern Holdings provides
services to AFP. In connection with these services, revenues of approximately
$74 million and $44 million in 2003 and 2002, respectively, have been billed to
an entity that is a subsidiary of AFP's majority owner.
Revenues and Fuel Costs
Capacity revenues are generally recognized on a levelized basis over the
appropriate contract periods. Energy and 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
retail 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
II-36
NOTES (continued)
Southern Company and Subsidiary Companies 2003 Annual Report
fuel. Total charges for nuclear fuel included in fuel expense amounted to $138
million in 2003, $134 million in 2002, and $133 million in 2001. 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 2015. At Plant
Hatch, an on-site dry storage facility became operational in 2000 and can be
expanded to accommodate spent fuel through the life of the plant. Construction
of an on-site dry storage facility at Plant Farley is in progress and scheduled
for operation in 2005. Construction of an on-site dry storage facility 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 interest -- estimate their respective remaining liability at
December 31, 2003, under this law to be approximately $13 million and $10
million.
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.
Regulatory Assets and Liabilities
The retail 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:
2003 2002 Note
- ----------------------------------------------------------------
(in millions)
Deferred income tax charges $ 874 $ 898 (a)
Loss on reacquired debt 326 313 (b)
DOE assessments 26 33 (c)
Vacation pay 97 98 (d)
Building lease 54 54 (f)
Generating plant outage costs 35 38 (f)
Other assets 75 73 (f)
Asset retirement obligations (138) - (a)
Other cost of removal obligations (1,269) (1,944) (a)
Deferred income tax credits (409) (450) (a)
Accelerated cost recovery (115) (229) (e)
Plant Daniel capacity (60) - (g)
Storm damage reserves (53) (38) (f)
Fuel-hedging liabilities (13) (38) (c)
Environmental remediation reserves (41) (42) (f)
Deferred purchased power (92) (63) (f)
Other liabilities (13) (12) (f)
- ----------------------------------------------------------
Total $ (716) $(1,309)
==========================================================
Note: The recovery and amortization periods for these regulatory assets and
(liabilities) are as follows:
(a) Asset retirement and removal liabilities are recorded, deferred income
tax assets are recovered, and deferred tax liabilities are amortized over
the related property lives, which may range up to 50 years. Asset
retirement and removal liabilities will be settled and trued up following
completion of the related activities.
(b) Recovered over either the remaining life of the original issue or, if
refinanced, over the life of the new issue, which may range up to 50
years.
(c) Assessments for the decontamination and decommissioning of the DOE's
nuclear fuel enrichment facilities are recorded annually from 1993
through 2008. Fuel-hedging assets and liabilities are recorded over the
life of the underlying hedged purchase contracts, which generally do not
exceed two years. Upon final settlement, actual costs incurred are
recovered through the fuel cost recovery clauses.
(d) Recorded as earned by employees and recovered as paid, generally within
one year.
(e) Amortized over three-year period ending in 2004.
(f) Recorded and recovered or amortized as approved by the appropriate state
public service commissions.
(g) See Note 3 under "Mississippi Power Regulatory Filing."
In the event that a portion of an operating company's operations is no longer
subject to the provisions of FASB Statement No. 71, the company would be
required to write off related 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,
II-37
NOTES (continued)
Southern Company and Subsidiary Companies 2003 Annual Report
including plant, and write down the assets, if impaired, to their fair value.
All regulatory assets and liabilities are to be reflected in rates.
Depreciation and Amortization
Depreciation of the original cost of plant in service is provided primarily by
using composite straight-line rates, which approximated 3.1 percent in 2003, 3.2
percent in 2002, and 3.4 percent in 2001. 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.
Under previous rate orders, Georgia Power recorded accelerated depreciation
and amortization amounting to $91 million in 2001. 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. Also, effective January 2002, Georgia Power was ordered by the
Georgia Public Service Commission (GPSC) to recognize new certified purchased
power costs in rates evenly over the three years covered by the current retail
rate order. As a result of this regulatory adjustment, Georgia Power recorded in
depreciation and amortization expense $14 million and $63 million in 2003 and
2002, respectively. Georgia Power will record a credit to amortization expense
of $77 million in 2004. See Note 3 under "Georgia Power Retail Rate Orders" for
additional information.
Asset Retirement Obligations
And Other Costs of Removal
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 accordance with SEC requirements,
such amounts are reflected on the Consolidated Balance Sheet as regulatory
liabilities. Effective January 1, 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 costs 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 costs 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 the continued accrual of
future retirement costs for long-lived assets that the company does not have a
legal obligation to retire. However, the retail operating companies have
received guidance regarding accounting for the financial statement impacts of
Statement No.143 from their respective state public service commissions and will
continue to recognize the accumulated removalcosts for other obligations as a
regulatory liability. Therefore, the retail operating companies had no
cumulative effect to net income resulting from the adoption of Statement No.
143.
The liability recognized to retire long-lived assets primarily relates to
Southern Company's nuclear facilities, which include Alabama Power's Plant
Farley and Georgia Power's ownership interests in plants Hatch and Vogtle. The
fair value of assets legally restricted for settling retirement obligations
related to nuclear facilities as of December 31, 2003 was $808 million. In
addition, the retail operating companies have retirement obligations related to
various landfill sites, ash ponds, and underground storage tanks. The retail
operating companies have also identified retirement obligations related to
certain transmission and distribution facilities. However, liabilities for the
removal of these transmission and distribution assets have not been recorded
because no reasonable estimate can be made regarding the timing of the
obligations. The retail operating companies will continue to recognize in the
income statement allowed 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 are recognized as either a
regulatory asset or liability and are reflected in the Consolidated Balance
Sheets. See "Nuclear Decommissioning" for further information on amounts
included in rates.
Details of the asset retirement obligations included in the Consolidated
Balance Sheets are as follows:
2003
- ----------------------------------------------------------------
(in millions)
Balance beginning of year $ -
Liabilities incurred 780
Liabilities settled -
Accretion 55
Cash flow revisions 10
- ----------------------------------------------------------------
Balance end of year $845
================================================================
If Statement No. 143 had been adopted on January 1, 2002, the pro-forma
asset retirement obligations would have been $729 million.
II-38
NOTES (continued)
Southern Company and Subsidiary Companies 2003 Annual Report
Nuclear Decommissioning
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. The funds set
aside for decommissioning are managed and invested in accordance with applicable
requirements of various regulatory bodies, including the NRC, the FERC, and
state public utility commissions, as well as the Internal Revenue Service (IRS).
Funds are invested in a tax efficient manner in a diversified mix of equity and
fixed income securities. Equity securities typically range from 50 to 75 percent
of the funds and fixed income securities from 25 to 50 percent. 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. The estimated costs of decommissioning based on the most
current study as of December 31, 2003, 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 2003 2003 2003
Decommissioning periods:
Beginning year 2017 2034 2027
Completion year 2046 2065 2048
- ----------------------------------------------------------------
(in millions)
Site study costs:
Radiated structures $892 $497 $452
Non-radiated structures 63 49 58
- ----------------------------------------------------------------
Total $955 $546 $510
================================================================
Significant assumptions:
Inflation rate 4.5% 3.1% 3.1%
Trust earning rate 7.0 6.6 6.6
- ----------------------------------------------------------------
The decommissioning cost estimates are based on prompt dismantlement and
removal of the plant from service. The actual decommissioning costs may vary
from the above estimates because of changes in the assumed date of
decommissioning, changes in NRC requirements, or changes in the assumptions used
in making these estimates.
Annual provisions for nuclear decommissioning are based on an annuity method
as approved by the respective state public service commissions. The amount
expensed in 2003 and fund balances were as follows:
Plant Plant Plant
Farley Hatch Vogtle
- ---------------------------------------------------------------
(in millions)
Amount expensed in 2003 $18 $7 $2
Accumulated provisions:
External trust funds,
at fair value $385 $269 $154
Internal reserves 31 7 4
- ---------------------------------------------------------------
Total $416 $276 $158
===============================================================
Alabama Power's decommissioning costs for ratemaking are based on the site
study. Effective January 1, 2002, the GPSC decreased Georgia Power's annual
decommissioning costs for ratemaking 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. Assumptions used to determine these costs for ratemaking
were an inflation rate of 4.5 percent and 4.7 percent for Alabama Power and
Georgia Power, respectively, and a trust earning rate of 7.0 percent and 6.5
percent for Alabama Power and Georgia Power, 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 permits the operation of units 1 and 2
until 2034 and 2038, respectively. The site study decommissioning costs reflect
the license extension; however, the updated costs will not be reflected in rates
until the GPSC issues a new rate order, which is not expected until December
2004. Alabama Power filed an application with the NRC in September 2003 to
extend the operating license for Plant Farley for an additional 20 years.
II-39
NOTES (continued)
Southern Company and Subsidiary Companies 2003 Annual Report
Allowance for Funds Used During Construction
(AFUDC) and Interest Capitalized
In accordance with regulatory treatment, the retail 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 retail operating companies' regulated rates
is capitalized in accordance with standard interest capitalization requirements.
Cash payments for interest totaled $603 million, $544 million, and $624
million in 2003, 2002, and 2001, respectively, net of amounts capitalized of $49
million, $59 million, and $57 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 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.
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 either the amount of regulatory disallowance or by
estimating the fair value of the assets and recording a 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.
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 rent or depreciation and amortization, as well as
interest on long-term debt related to these investments.
Southern Company's net investment in leveraged leases consists of the
following at December 31:
2003 2002
- ----------------------------------------------------------------
(in millions)
Net rentals receivable $1,512 $1,531
Unearned income (674) (740)
- ----------------------------------------------------------------
Investment in leveraged leases 838 791
Deferred taxes arising
from leveraged leases (351) (260)
- ----------------------------------------------------------------
Net investment in leveraged leases $ 487 $ 531
================================================================
A summary of the components of income from leveraged leases is as follows:
2003 2002 2001
- ---------------------------------------------------------------
(in millions)
Pretax leveraged lease income $66 $58 $59
Income tax expense 23 21 21
- ---------------------------------------------------------------
Net leveraged lease income $43 $37 $38
===============================================================
II-40
NOTES (continued)
Southern Company and Subsidiary Companies 2003 Annual Report
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.
Financial Instruments
Southern 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 Southern Company's bulk energy purchases and sales
contracts that meet the definition of a derivative are exempt from fair value
accounting requirements and are accounted for under the accrual method. Other
derivative 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.
Other derivative contracts 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.
The other Southern Company financial instruments for which the carrying
amount does not equal fair value at December 31 were as follows:
Carrying Fair
Amount Value
- ---------------------------------------------------------------
(in millions)
Long-term debt:
At December 31, 2003 $10,759 $10,971
At December 31, 2002 10,226 10,510
Preferred securities:
At December 31, 2003 1,940 2,059
At December 31, 2002 2,428 2,498
- ---------------------------------------------------------------
The fair values were based on either closing market price or closing price of
comparable instruments.
Comprehensive Income
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. Comprehensive
income consists 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. Comprehensive
income from discontinued operations also includes foreign currency translation
adjustments, net of income taxes.
2. RETIREMENT BENEFITS
Southern Company has a defined benefit, trusteed, pension plan covering
substantially all employees. The plan is funded in accordance with Employee
Retirement Income Security Act (ERISA) requirements. No contributions to the
plan are expected for the year ending December 31, 2004. Southern Company also
provides certain non-qualified benefit plans for a selected group of management
and highly compensated employees. Benefits under these non-qualified plans are
funded on a cash basis. In addition, Southern Company provides certain medical
care and life insurance benefits for retired employees. The retail operating
companies fund related trusts to the extent required by their respective
regulatory commissions. For the year ended December 31, 2004, postretirement
benefit contributions are expected to total approximately $15 million.
II-41
NOTES (continued)
Southern Company and Subsidiary Companies 2003 Annual Report
The measurement date for plan assets and obligations is September 30 for each
year. In 2002, Southern Company adopted several plan changes that had the effect
of increasing benefits to both current and future retirees.
Pension Plans
The accumulated benefit obligation for the pension plans was $4.2 billion in
2003 and $3.6 billion in 2002. Changes during the year in the projected benefit
obligations, accumulated benefit obligations, and fair value of plan assets were
as follows:
Projected
Benefit Obligations
--------------------
2003 2002
- ---------------------------------------------------------------
(in millions)
Balance at beginning of year $4,094 $3,760
Service cost 115 109
Interest cost 261 277
Benefits paid (197) (184)
Plan amendments 11 88
Actuarial (gain) loss 289 44
- ---------------------------------------------------------------
Balance at end of year $4,573 $4,094
===============================================================
Plan Assets
------------------
2003 2002
- ---------------------------------------------------------------
(in millions)
Balance at beginning of year $4,600 $5,109
Actual return on plan assets 735 (343)
Benefits paid (176) (166)
- ---------------------------------------------------------------
Balance at end of year $5,159 $4,600
===============================================================
Pension plan assets are managed and invested in accordance with all
applicable requirements, including ERISA and the IRS revenue code. The company's
investment policy covers a diversified mix of assets, including equity and fixed
income securities, real estate, and private equity, as described in the table
below. Derivative instruments are used primarily as hedging tools but may also
be used to gain efficient exposure to the various asset classes. The company
primarily minimizes the risk of large losses through diversification but also
monitors and manages other aspects of risk.
Plan Assets
-------------------------------
Target 2003 2002
- ----------------------------------------------------------------
Domestic equity 37% 37% 35%
International equity 20 20 18
Global fixed income 26 24 25
Real estate 10 11 12
Private equity 7 8 10
- ----------------------------------------------------------------
Total 100% 100% 100%
================================================================
The accrued pension costs recognized in the Consolidated Balance Sheets were
as follows:
2003 2002
- ---------------------------------------------------------------
(in millions)
Funded status $586 $ 506
Unrecognized transition amount (26) (39)
Unrecognized prior service cost 314 334
Unrecognized net (gain) loss (70) (115)
- ---------------------------------------------------------------
Prepaid pension asset, net 804 686
Portion included in
benefit obligations 107 100
- ---------------------------------------------------------------
Total prepaid assets recognized in
the Consolidated Balance Sheets $911 $ 786
===============================================================
In 2003 and 2002, amounts recognized in the Consolidated Balance Sheets for
accumulated other comprehensive income and intangible assets to record the
minimum pension liability related to the non-qualified plans were $77 million
and $49 million and $42 million and $35 million, respectively.
Components of the pension plans' net periodic cost were as follows:
2003 2002 2001
- -------------------------------------------------------------
(in millions)
Service cost $ 115 $ 109 $ 104
Interest cost 261 277 260
Expected return on
plan assets (450) (449) (423)
Recognized net gain (42) (65) (73)
Net amortization 17 11 8
- --------------------------------------------------------------
Net pension cost (income) $ (99) $(117) $(124)
==============================================================
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
---------------------
2003 2002
- ---------------------------------------------------------------
(in millions)
Balance at beginning of year $1,461 $1,239
Service cost 25 21
Interest cost 93 91
Benefits paid (66) (62)
Actuarial (gain) loss 142 172
- ---------------------------------------------------------------
Balance at end of year $1,655 $1,461
===============================================================
II-42
NOTES (continued)
Southern Company and Subsidiary Companies 2003 Annual Report
Plan Assets
---------------
2003 2002
- ---------------------------------------------------------------
(in millions)
Balance at beginning of year $417 $425
Actual return on plan assets 70 (34)
Employer contributions 101 88
Benefits paid (66) (62)
- ---------------------------------------------------------------
Balance at end of year $522 $417
===============================================================
Postretirement benefits plan assets are managed and invested in accordance
with all applicable requirements, including ERISA and the IRS revenue code. The
company's investment policy covers a diversified mix of assets, including equity
and fixed income securities, real estate, and private equity, as described in
the table below. Derivative instruments are used primarily as hedging tools but
may also be used to gain efficient exposure to the various asset classes. The
company primarily minimizes the risk of large losses through diversification but
also monitors and manages other aspects of risk.
Plan Assets
--------------------------------
Target 2003 2002
- ----------------------------------------------------------------
Domestic equity 43% 44% 38%
International equity 17 18 16
Global fixed income 33 31 37
Real estate 4 4 5
Private equity 3 3 4
- ----------------------------------------------------------------
Total 100% 100% 100%
================================================================
The accrued postretirement costs recognized in the Consolidated Balance
Sheets were as follows:
2003 2002
- ----------------------------------------------------------------
(in millions)
Funded status $(1,133) $(1,043)
Unrecognized transition obligation 144 159
Unrecognized prior service cost 211 225
Unrecognized net loss (gain) 357 239
Fourth quarter contributions 19 51
- ----------------------------------------------------------------
Accrued liability recognized in the
Consolidated Balance Sheets $ (402) $ (369)
================================================================
Components of the postretirement plans' net periodic cost were as follows:
2003 2002 2001
- --------------------------------------------------------------
(in millions)
Service cost $ 25 $ 21 $ 22
Interest cost 93 91 88
Expected return on
plan assets (47) (42) (40)
Net amortization 30 29 26
- --------------------------------------------------------------
Net postretirement cost $101 $ 99 $ 96
==============================================================
The weighted average rates assumed in the actuarial calculations used to
determine both the benefit obligations and the net periodic costs for the
pension and postretirement benefit plans were as follows:
2003 2002 2001
- ---------------------------------------------------------------
Discount 6.00% 6.50% 7.50%
Annual salary increase 3.75 4.00 5.00
Long-term return
on plan assets 8.50 8.50 8.50
- ---------------------------------------------------------------
The company determined the long-term rate of return based on historical asset
class returns and current market conditions, taking into account the
diversification benefits of investing in multiple asset classes.
An additional assumption used in measuring the accumulated postretirement
benefit obligation was a weighted average medical care cost trend rate of 8.25
percent for 2003, 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,
2003, as follows:
1 Percent 1 Percent
Increase Decrease
- ----------------------------------------------------------------
(in millions)
Benefit obligation $140 $124
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 2003, 2002, and 2001 were $55
million, $53 million, and $51 million, respectively.
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. In addition, Southern 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
II-43
NOTES (continued)
Southern Company and Subsidiary Companies 2003 Annual Report
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 against Southern Company and its subsidiaries cannot be
predicted at this time; however, management does not anticipate that the
liabilities, if any, arising from such current proceedings would have a material
adverse effect on Southern Company's financial statements.
Mirant Related Matters
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. On October 2, 2000, Mirant completed
its initial public offering of 66.7 million 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.
Potential Mirant Restatement
In November 2002, Mirant first announced that it had identified accounting
errors in previously issued financial statements. Mirant has restated and
reduced its net income for 2001 by $159 million. Mirant has stated that the
specific quarters in 2001 to which the overstatement apply have not been
determined. If any adjustments are necessary prior to April 2, 2001, before
Southern Company's spin off of Mirant, then Southern Company's earnings from
discontinued operations for such periods would be affected. The impact of any
such adjustments cannot be determined until Mirant's 2001 revised quarterly
financial statements are filed and would not affect Southern Company's 2002 or
any future financial statements.
Mirant Bankruptcy
On July 14, 2003, Mirant filed for voluntary reorganization under Chapter 11
with the U.S. Bankruptcy Court. Southern Company has certain contingent
liabilities associated with guarantees of contractual commitments made by
Mirant's subsidiaries discussed in Note 7 under "Guarantees" and with various
lawsuits related to Mirant discussed later in this note. Also, Southern Company
has joint and several liability with Mirant regarding the joint consolidated
federal income tax return as discussed in Note 5. Under the terms of the
separation agreement, Mirant agreed to indemnify Southern Company for costs
associated with these guarantees, lawsuits, and additional IRS assessments. The
impact of Mirant's bankruptcy filing on Mirant's indemnity obligations, if any,
cannot now be determined. If Southern Company is ultimately required to make any
payments related to these potentially material obligations, Mirant's
indemnification obligation to Southern Company would represent an unsecured
pre-bankruptcy claim, subject to compromise pursuant to Mirant's final
reorganization plan.
The Bankruptcy Code automatically stays all litigation as to Mirant. A motion
filed with the bankruptcy court requesting an extension of this automatic stay
to all other non-debtor defendants, including Southern Company and the named
current and/or former Southern Company officers, was granted in November 2003.
Although the Mirant securities litigation is stayed until further order from the
bankruptcy court, Mirant is authorized to agree with parties in pending actions
to allow discovery or other matters to proceed without violating the stay.
Mirant and plaintiffs' counsel in the Mirant securities litigation have agreed
that document discovery may proceed. On October 23, 2003, the bankruptcy court
entered an order authorizing Southern Company's insurance companies to pay
related defense costs.
On February 20, 2004, the Official Committee of Unsecured Creditors of Mirant
informed Southern Company of its intent to examine Southern Company in
accordance with federal bankruptcy rules to determine whether there is a
legitimate basis to bring claims against Southern Company in connection with
Mirant's initial public offering, Southern Company's spinoff of Mirant, and the
related separation agreements.
The final outcome of these matters cannot now be determined.
California Electricity Markets Investigation
Southern Company received a subpoena in November 2002 to provide information to
a federal grand jury in the Northern District of California. The subpoena
covered a number of broad areas, including specific information regarding
electricity production and sales activities in California. 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 has fully cooperated in the investigation.
Mirant Securities Litigation
In November 2002, Southern Company, certain former and current senior officers
of Southern Company, and 12 underwriters of Mirant's initial public offering
II-44
NOTES (continued)
Southern Company and Subsidiary Companies 2003 Annual Report
were added as defendants in a putative class action lawsuit that several Mirant
shareholders originally filed against Mirant and certain Mirant officers in May
2002. The original lawsuit 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
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. The lawsuit purports to include persons
who acquired Mirant securities between September 26, 2000, and September 5,
2002.
On July 14, 2003, the court dismissed all claims based on Mirant's alleged
improper energy trading and marketing activities involving the California energy
market. The remaining claims are based on alleged false statements and omissions
in Mirant's prospectus for its initial public offering and accounting-related
issues previously disclosed by Mirant. Such claims do not allege any improper
trading and marketing activity, accounting errors, or material misstatements or
omissions on the part of Southern Company, but rather seek to impose liability
on Southern Company based on allegations that Southern Company was a "control
person" as to Mirant prior to the spin off date. Southern Company filed an
answer to the consolidated amended class action complaint on September 3, 2003.
Plaintiffs have also filed a motion for class certification.
Under certain circumstances, Southern Company will be obligated under its
Bylaws to indemnify the four current and/or former Southern Company officers who
served as directors of Mirant at the time of its initial public offering through
the date of the spin off and are also named as defendants in this lawsuit.
Except for limited document discovery, litigation has been stayed until further
order from the bankruptcy court. The final outcome of these matters cannot now
be determined.
Mirant ERISA Litigation
In April 2003, a retired employee of Mirant filed a complaint in the U.S.
District Court for the Northern District of Georgia alleging violations of ERISA
and naming as defendants Mirant, Southern Company, several current and former
directors and officers of Mirant and/or Southern Company, and "Unknown Fiduciary
Defendants 1-100." In June 2003, a substantially similar complaint was filed.
Neither complaint contained any specific allegations of wrongdoing with respect
to Southern Company. On September 2, 2003, the court consolidated all pending
and future ERISA actions arising out of the same facts, and the plaintiffs filed
a consolidated amended ERISA complaint on September 23, 2003. The plaintiffs
sought to represent a class of persons who were participants in or beneficiaries
of certain Mirant employee benefit plans between September 27, 2000, and July
22, 2003. The consolidated amended complaint named as defendants Mirant, certain
Mirant benefit committees, Southern Company, and several of Mirant's current and
former officers, directors, and employees. The consolidated amended complaint
alleged that the defendants breached their fiduciary duties and violated ERISA
by failing to investigate whether Mirant stock was a prudent investment for the
plans, by continuing and promoting Mirant stock as an investment alternative for
participants in the plans, and by failing to disclose information about Mirant's
financial condition and about its improper activities in the California energy
markets.
On February 19, 2004, plaintiffs dismissed Southern Company from this action
without prejudice. The plaintiffs are not barred from naming Southern Company in
some future lawsuit, but management believes the possibility of having to pay
damages in any such lawsuit is remote.
Mobile Energy Services' Petition for Bankruptcy
Mobile Energy Services Holdings (MESH) 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 with the U.S. Bankruptcy Court. In 2001, MESH
filed an amended plan of reorganization, which the U.S. Bankruptcy Court
confirmed in September 2003. The plan became effective in late 2003 and Southern
Company's equity interest in MESH - which had been written off entirely prior to
2001 - was extinguished. Southern Company will continue to have contingent
liabilities to the pulp and paper complex owners associated with a guarantee of
certain potential environmental obligations and with a potential obligation to
fund a maintenance reserve account that expires in 2019 and 2021, respectively.
The combined maximum contingent liabilities were $19 million at December 31,
II-45
NOTES (continued)
Southern Company and Subsidiary Companies 2003 Annual Report
2003. MESH and Mirant have each separately agreed to indemnify Southern Company
for any amounts required to be paid under such obligations. The final outcome of
these matters cannot now be determined.
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,
2003, for the assessment and anticipated cleanup of sites on the Georgia
Hazardous Sites Inventory. In addition, in 1995 the Environmental Protection
Agency (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, 2003, 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 Actions
In November 1999, the EPA brought a civil action in the U.S. District Court for
the Northern District of Georgia against Alabama Power, Georgia Power, and SCS.
The complaint alleged violations of the New Source Review (NSR) provisions of
the Clean Air Act with respect to five coal-fired generating facilities in
Alabama and Georgia and violations of related state laws. The civil action
requested 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 retail operating companies notices of violation
relating to 10 generating facilities, which include the five facilities
mentioned previously. In early 2000, the EPA filed a motion to amend its
complaint to add the violations alleged in its notices of violation and to add
Gulf Power, Mississippi Power, and Savannah Electric as defendants.
In August 2000, the U.S. District Court in Georgia granted Alabama Power's
motion to dismiss for lack of jurisdiction in Georgia and granted SCS' motion to
dismiss on the grounds that it neither owned nor operated the generating units
involved in the proceedings. In March 2001, 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 in Georgia 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. In
addition, the EPA refiled its claims against Alabama Power in the U.S. District
Court for the Northern District of Alabama. These complaints allege violations
with respect to eight coal-fired generating facilities in Alabama and Georgia,
and they request the same kinds of relief as was requested in the original
complaint, i.e. penalties and injunctive relief, including installation of the
best available control technology. The EPA has not refiled against Gulf Power,
Mississippi Power, or SCS.
The actions against Alabama Power, Georgia Power, and Savannah Electric were
stayed in the spring of 2001 during the appeal of a very similar NSR enforcement
action against the Tennessee Valley Authority (TVA) before the U.S. Court of
Appeals for the Eleventh Circuit. The TVA appeal involves many of the same legal
issues raised by the actions against Alabama Power, Georgia Power, and Savannah
Electric. Because the final resolution of the TVA appeal could have a
significant impact on Alabama Power and Georgia Power, both companies have been
involved in that appeal. On June 24, 2003, the court of appeals issued its
ruling in the TVA case. It found unconstitutional the statutory scheme set forth
in the Clean Air Act that allowed the EPA to impose penalties for failing to
comply with an administrative compliance order, like the one issued to TVA,
without the EPA having to prove the underlying violation. Thus, the court of
appeals held that the compliance order was of no legal consequence, and TVA was
free to ignore it. The court did not, however, rule directly on the substantive
legal issues about the proper interpretation and application of certain NSR
provisions that had been raised in the TVA appeal. On September 16, 2003, the
court of appeals denied the EPA's request for a rehearing of the decision. On
February 13, 2004, the EPA petitioned the U.S. Supreme Court to review the
decision of the court of appeals. The EPA also filed a motion to lift the stay
in the action against Alabama Power. At this time, no party to the Georgia Power
and Savannah Electric action, which was administratively closed two years ago,
has asked the court to reopen that case.
II-46
NOTES (continued)
Southern Company and Subsidiary Companies 2003 Annual Report
Since the inception of the NSR proceedings against Georgia Power, Alabama
Power, and Savannah Electric, the EPA has also been proceeding with similar NSR
enforcement actions against other utilities, involving many of the same legal
issues. In each case, the EPA alleged that the utilities failed to comply with
the NSR permitting requirements when performing maintenance and construction
activities at coal-burning plants, which activities the utilities considered to
be routine or otherwise not subject to NSR. In 2003, district courts addressing
these cases issued opinions that reached conflicting conclusions.
In October 2003, the EPA issued final revisions to its NSR regulations under
the Clean Air Act clarifying the scope of the existing Routine Maintenance,
Repair, and Replacement exclusion. On December 24, 2003, the U.S. Court of
Appeals for the District of Columbia Circuit stayed the effectiveness of these
revisions pending resolution of related litigation. In January 2004, the Bush
Administration announced that it would continue to enforce the existing rules.
Southern Company believes that its retail 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.
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 the U.S. District
Court in Georgia against Georgia Power for alleged violations of the Clean Air
Act at four of the generating units 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 June 19, 2003, the court granted Georgia Power's motion to dismiss the
allegations regarding hazardous air pollutants and denied Georgia Power's motion
to dismiss the allegations regarding emission offsets. On August 29, 2003,
Georgia Power filed a motion for partial summary judgment regarding emission
offsets. On January 20, 2004, Georgia Power filed a motion for summary judgment
on the remaining three counts, and the plaintiffs have filed motions for partial
summary judgment. The case is currently scheduled for trial during the summer of
2004. 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.
Race Discrimination Litigation
In July 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 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 indirect 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. On March 31, 2003,
the U.S. District Court for the Northern District of Georgia granted summary
judgment in favor of the defendants on all claims raised by all seven
plaintiffs. On April 23, 2003, plaintiffs filed an appeal to the U.S. Court of
Appeals for the Eleventh Circuit challenging these adverse summary judgment
rulings, as well as the District Court's October 2001 ruling denying class
II-47
NOTES (continued)
Southern Company and Subsidiary Companies 2003 Annual Report
certification. Oral argument occurred on January 27, 2004, and the parties await
the court's decision. The final outcome of this matter cannot now be determined.
Right of Way Litigation
Southern Company and certain of its subsidiaries, including Georgia Power, Gulf
Power, Mississippi Power, and Southern Telecom (collectively, defendants), have
been named as defendants in numerous lawsuits brought by landowners since 2001
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. With respect to one such lawsuit
brought by landowners regarding the installation and use of fiber optic cable
over Gulf Power rights of way located on the landowners' property, on November
7, 2003, the Second Circuit Court in Gadsden County, Florida, ruled in favor of
the plaintiffs on their motion for partial summary judgment concerning
liability. The question of damages, if any, will be decided at a future trial.
In the event of an adverse verdict on damages, Gulf Power could appeal the
verdicts on both liability and damages. Management of Southern Company and its
subsidiaries believe that the defendant companies in the pending right of way
litigation have complied with applicable laws and 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.
In addition, in late 2001, certain subsidiaries of Southern Company,
including Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah
Electric, and Southern Telecom (collectively, defendants), were named as
defendants in a lawsuit brought by a telecommunications company that uses
certain of the defendants' rights of way. This lawsuit alleges, among other
things, that the defendants are contractually obligated to indemnify, defend,
and hold harmless the telecommunications company from any liability that may be
assessed against the telecommunications company in pending and future right of
way litigation. The defendants believe that the plaintiff's claims are without
merit. An adverse outcome in this matter, combined with an adverse outcome
against the telecommunications company in one or more of the right of way
lawsuits, could result in substantial judgments; however, the final outcome of
these matters cannot now be determined.
Income Tax Issues
Synthetic Fuel Tax Credits
Southern Company has investments in two entities that produce synthetic fuel and
receive tax credits under Section 29 of the IRS revenue code. In April 2001,
Southern Company acquired a 30 percent membership interest in AFP. In 1998,
Southern Company acquired a 24.975 percent limited partnership interest in
Carbontronics Synfuels Investors, L.P. (Carbontronics). At December 31, 2003,
Southern Company's total investment in these entities was approximately $30
million.
On June 30, 2003, the IRS issued an announcement that suspended the issuance
of new private letter rulings and indicated that it might also revoke existing
private letter rulings for synthetic fuels Section 29 tax credits pending a
review of the scientific validity of test procedures and results that have been
presented as evidence that a significant chemical change occurred in such
synthetic fuel. On October 29, 2003, the IRS announced that it has completed its
review and determined that the test procedures and results used by taxpayers are
scientifically valid if the procedures are applied in a consistent and unbiased
manner. The IRS stated that the processes they approved do not produce the level
of chemical change required by Section 29, but they will, nevertheless, resume
issuing private letter rulings. The IRS will require taxpayers applying for
future rulings to implement and maintain certain sampling and quality control
procedures, as well as additional documentation and record retention procedures.
The IRS also plans to extend these procedures to taxpayers already holding
rulings on the issue of significant chemical change.
On October 30, 2003, the Senate Governmental Affairs Permanent Subcommittee
on Investigations announced that it has begun a separate investigation of the
synthetic fuel industry and its producers for potential abuses of these tax
credits.
In January 2004, the IRS completed an audit of AFP for tax years 1999 and
2000. The IRS raised no issues related to the Section 29 tax credits for these
years and issued a "no-change" audit report to AFP's tax matters partner. The
IRS is currently auditing Carbontronics for tax years 2000 and 2001. From the
inception of Southern Company's investment in these entities through December
31, 2003, Southern Company has recognized through income approximately $274
II-48
NOTES (continued)
Southern Company and Subsidiary Companies 2003 Annual Report
million (net of approximately $37 million reserved) in tax credits related to
its share of the synthetic fuel production at these entities.
Both entities have private letter rulings from the IRS that concluded
significant chemical change occurred based on the procedures and results
submitted. In addition, both entities regularly use independentlaboratories and
experts to test for chemical change. These tests replicated significant chemical
changes consistent with the procedures submitted with the private letter
rulings. Southern Company has relied on these private letter rulings and
believes that the test results presented in connection with such private letter
rulings are valid and that the entities have operated in compliance with their
respective private letter rulings and Section 29 of the revenue code. The
ultimate outcome of these matters cannot now be determined.
Leveraged Lease Transactions
Southern Company undergoes audits by the IRS for each of its tax years. The IRS
has completed its audits of Southern Company's consolidated federal income tax
returns for all years through 1999. As part of the audit for the 1996-1999 tax
years, the IRS reviewed Southern Company's four international leveraged lease
transactions. Based on its review, the IRS proposed to disallow the tax losses
associated with one of these transactions, resulting in an additional tax
payment of approximately $30 million, including interest. To finalize the audit
and eliminate any additional interest charges, Southern Company made this
payment to the IRS in May 2003 and filed a refund claim for this amount. On
January 5, 2004, the IRS proposed to disallow the refund claim. Southern Company
has accounted for the payment as a deposit. Southern Company continues to
believe that the transaction remains a valid lease for U.S. tax purposes and,
accordingly, intends to file a petition for refund in federal court. If Southern
Company is not successful in its defense of the tax treatment for this
transaction, it could also affect the timing of the related revenue recognition
for book purposes. A cumulative effect adjustment could be required to reduce
net income based on the revised cash flows as a result of the changes in the
allowed tax deductions.
The IRS did not disallow any tax losses or make any other adjustments for the
1996-1999 period with respect to any of Southern Company's other lease
transactions. However, there can be no assurance that subsequent IRS audits
would not raise similar disallowance issues. See Note 1 under "Leveraged Leases"
for additional information on deferred taxes arising from these transactions.
The ultimate 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 and for the
recovery of retail costs associated with certificated purchased power
agreements. Both increases and decreases have been placed into effect since the
adoption of these rates. 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.
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.
Also, to recover certificated purchased power costs, an increase of 2.6 percent
in retail rates, or $79 million annually, was effective July 2003. An additional
increase of $25 million annually is scheduled to be effective in June 2004 for
new certificated purchased power costs.
Georgia Power Retail Rate Orders
In December 2001, the GPSC approved a three-year retail rate order for Georgia
Power ending December 31, 2004. Retail rates were decreased by $118 million
effective January 1, 2002. Under the terms of the order, earnings are 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. Georgia
Power's earnings in both 2002 and 2003 were within the common equity range.
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
II-49
NOTES (continued)
Southern Company and Subsidiary Companies 2003 Annual Report
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 was credited to a
regulatory liability account as mandated by the GPSC.
Under the 2001 rate order, Georgia Power discontinued recording accelerated
depreciation and amortization and began amortizing the accumulated balance
equally over three years as a credit to expense beginning in 2002. Also, the
rate order required Georgia Power to recognize capacity and operating and
maintenance costs related to certified purchase power contracts evenly into
rates over a three-year period ending December 31, 2004.
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.
Uncontracted Generating Capacity
On May 21, 2003, Mississippi Power and Southern Power entered into agreements
with Dynegy, Inc. (Dynegy) to resolve all outstanding matters related to
capacity sales contracts with subsidiaries of Dynegy. Under the terms of the
agreements, Dynegy made a cash payment of $75 million to Mississippi Power and
$80 million to Southern Power. The contracts between Southern Power and Dynegy
were terminated in May 2003, and the Mississippi Power contract was terminated
effective October 31, 2003.
The termination payments from Dynegy resulted in a one-time gain to Southern
Company of approximately $88 million after tax ($38 million for Mississippi
Power and $50 million for Southern Power).
As a result of these contract terminations, Southern Power is completing
limited construction activities on Plant Franklin Unit 3 to preserve the
long-term viability of the project but has deferred final completion until the
2008-2011 period. The length of the deferral period will depend on forecasted
capacity needs and other wholesale market opportunities. As of December 31,
2003, Southern Power's investment in Unit 3 of Plant Franklin was $156 million.
Southern Power is continuing to explore alternatives for its existing capacity.
The final outcome of these matters cannot now be determined.
Mississippi Power Regulatory Filing
On December 5, 2003, Mississippi Power filed a request with the Mississippi
Public Service Commission (MPSC) to modify certain portions of its Performance
Evaluation Plan (PEP) and to include 266 megawatts of Plant Daniel units 3 and 4
generating capacity not currently included in jurisdictional cost of service.
As part of Mississippi Power's proposal to include the additional Plant
Daniel capacity in retail rates, the MPSC issued an interim accounting order in
December 2003 directing Mississippi Power to expense and record in 2003 a
regulatory liability in the amount of approximately $60 million while the MPSC
fully considers the entire request. However, if the MPSC ultimately denies
Mississippi Power's request, the regulatory liability will be required to be
reversed.
In the second quarter of 2004, Mississippi Power expects the MPSC to render a
final order on the inclusion of the additional Plant Daniel capacity in rates,
the amortization period for the regulatory liability, and the requested changes
to PEP.
FERC Matters
Southern Power currently has general authorization from the FERC to sell power
to nonaffiliates at market-based prices. In addition, each of the retail
operating companies has obtained FERC approval to sell power to nonaffiliates at
market-based prices under specific contracts. Southern Power and the retail
operating companies also have FERC authority to make short-term opportunity
sales at market rates. Specific FERC approval must be obtained with respect to a
market-based contract with an affiliate. In November 2001, the FERC modified the
test it uses to consider utilities' applications to charge market-based rates
and adopted a new test called the Supply Margin Assessment (SMA). The FERC
applied the SMA to several utilities, including Southern Company, and found
Southern Company and others to be "pivotal suppliers" in their service areas and
ordered the implementation of several mitigation measures. Southern Company and
others sought rehearing of the FERC order, and the FERC delayed the
implementation of certain mitigation measures. Southern Company and others
submitted comments to the FERC in 2002 regarding these issues. In December 2003,
the FERC issued a staff paper discussing alternatives and held a technical
conference in January 2004. Southern Company anticipates that the FERC will
address the requests for rehearing in the near future. The final outcome of this
matter will depend on the form in which the SMA test and mitigation measures
rules may be ultimately adopted and cannot be determined at this time.
II-50
NOTES (continued)
Southern Company and Subsidiary Companies 2003 Annual Report
Purchased Power Agreements (PPAs) by Georgia Power and Savannah Electric for
Southern Power's Plant McIntosh capacity were certified by the GPSC in December
2002 after a competitive bidding process. In April 2003, Southern Power applied
for FERC approval of these PPAs. Interveners opposed the FERC's acceptance of
the PPAs, alleging that the PPAs do not meet the applicable standards for
market-based rates between affiliates. In July 2003, the FERC accepted the PPAs
to become effective as scheduled on June 1, 2005, subject to refund, and ordered
that hearings be held to determine: (a) whether, in the design and
implementation of the GPSC competitive bidding process, Georgia Power and
Savannah Electric unduly preferred Southern Power; (b) whether the analysis of
the competitive bids unduly favored Southern Power, particularly with respect to
evaluation of non-price factors; (c) whether Georgia Power and Savannah Electric
selected their affiliate, Southern Power, based upon a reasonable combination of
price and non-price factors; (d) whether Southern Power received an undue
preference or competitive advantage in the competitive bidding process as a
result of access to its affiliate's transmission system; (e) whether and to what
extent the PPAs impact wholesale competition; and (f) whether the PPAs are just
and reasonable and not unduly discriminatory. Hearings are scheduled to begin in
March 2004. Management believes that the PPAs should be approved by the FERC;
however, the ultimate outcome of this matter cannot now be determined.
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, and Jacksonville Electric Authority. In addition, Georgia
Power has joint ownership agreements with OPC for the Rocky Mountain facilities
and with Florida Power Corporation 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.
At December 31, 2003, 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% $3,307 $1,706
Plant Hatch
(nuclear) 50.1 908 469
Plant Miller
(coal)
Units 1 and 2 91.8 767 355
Plant Scherer
(coal)
Units 1 and 2 8.4 115 52
Plant Wansley
(coal) 53.5 390 160
Rocky Mountain
(pumped storage) 25.4 169 85
Intercession City
(combustion turbine) 33.3 12 1
Plant Stanton
(combined cycle)
Unit A 65.0 155 1
- ----------------------------------------------------------------
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. Income Taxes
Southern Company files a consolidated federal income tax return. In 2002,
Southern Company began filing a combined state of Georgia 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 IRS
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. The IRS is currently auditing the
consolidated tax returns for 2001 and 2000. For additional tax-related
information, see Note 3 under "Mirant Bankruptcy" and "Income Tax Issues."
II-51
NOTES (continued)
Southern Company and Subsidiary Companies 2003 Annual Report
At December 31, 2003, the tax-related regulatory assets and liabilities were
$874 million and $409 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.
Details of income tax provisions are as follows:
2003 2002 2001
- ---------------------------------------------------------------
(in millions)
Total provision for income taxes:
Federal --
Current $130 $284 $477
Deferred 404 167 (10)
- ---------------------------------------------------------------
534 451 467
- ---------------------------------------------------------------
State --
Current 42 64 103
Deferred 36 13 (12)
- ---------------------------------------------------------------
78 77 91
- ---------------------------------------------------------------
Total $612 $528 $558
===============================================================
Net cash payments for income taxes related to continuing operations in 2003,
2002, and 2001 were $188 million, $374 million, and $558 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:
2003 2002
- ---------------------------------------------------------------
(in millions)
Deferred tax liabilities:
Accelerated depreciation $3,737 $3,364
Property basis differences 970 1,011
Other 985 840
- ---------------------------------------------------------------
Total 5,692 5,215
- ---------------------------------------------------------------
Deferred tax assets:
Federal effect of state deferred taxes 119 111
Other property basis differences 171 185
Deferred costs 128 188
Pension and other benefits 160 146
Other 483 428
- ---------------------------------------------------------------
Total 1,061 1,058
- ---------------------------------------------------------------
Total deferred tax liabilities, net 4,631 4,157
Portion included in prepaid expenses
(accrued income taxes), net (55) 33
Deferred state tax assets 10 13
- ---------------------------------------------------------------
Accumulated deferred income taxes
in the Consolidated Balance Sheets $4,586 $4,203
===============================================================
At December 31, 2003, Southern Company also had available state of Georgia
net operating loss carryforward deductions totaling $1.0 billion, which could
result in net state income tax benefits of $60 million, if utilized. Less than
$27 million of such deductions will expire by 2008; the remainder will expire
between 2009 and 2021. During 2003, Southern Company realized $19 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 $29 million
in 2003, $27 million in 2002, and $30 million in 2001. At December 31, 2003, 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:
2003 2002 2001
- -------------------------------------------------------------
Federal statutory rate 35.0% 35.0% 35.0%
State income tax,
net of federal deduction 2.4 2.7 3.7
Synthetic fuel tax credits (5.7) (5.8) (4.2)
Employee stock plans
dividend deduction (1.5) (2.9) -
Non-deductible book
depreciation 1.1 1.3 1.7
Difference in prior years'
deferred and current tax rate (0.7) (1.0) (1.1)
Other (1.5) (0.9) (2.2)
- -------------------------------------------------------------
Effective income tax rate 29.1% 28.4% 32.9%
=============================================================
6. FINANCING
Mandatorily Redeemable Preferred Securities
Southern Company and the retail operating companies have each formed certain
wholly owned trust subsidiaries for the purpose of issuing preferred securities.
The proceeds of the related equity investments and preferred security sales were
loaned back to Southern Company and the retail operating companies through the
issuance of junior subordinated notes totaling $2.0 billion, which constitute
II-52
NOTES (continued)
Southern Company and Subsidiary Companies 2003 Annual Report
substantially all assets of these trusts. Southern Company and the retail
operating companies each considers that the mechanisms and obligations relating
to the preferred securities issued for its benefit, taken together, constitute a
full and unconditional guarantee by it of the respective trusts' payment
obligations with respect to these securities. At December 31, 2003, preferred
securities of $1.9 billion were outstanding and recognized as liabilities in the
Consolidated Balance Sheets. Southern Company guarantees the notes related to
$555 million of these securities issued on its behalf.
Securities 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:
2003 2002
- ---------------------------------------------------------------
(in millions)
First mortgage bond maturities
and redemptions $ - $ 33
Pollution control bonds - 1
Capitalized leases 11 11
Senior notes 655 1,552
Mandatorily redeemable preferred securities 40 40
Other long-term debt 35 42
- ---------------------------------------------------------------
Total $741 $1,679
===============================================================
Debt redemptions and/or serial maturities through 2008 applicable to total
long-term debt are as follows: $741 million in 2004; $891 million in 2005; $951
million in 2006; $975 million in 2007; and $473 million in 2008.
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 retail
operating companies, constitute a direct first lien on substantially all of the
retail operating companies' respective fixed property and franchises. Georgia
Power discharged its mortgage in 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 2004, unused credit arrangements with banks totaled $3.5
billion, of which $2.8 billion expires during 2004 and $670 million expires
during 2005 and beyond. The following table outlines the credit arrangements by
company:
Amount of Credit
------------------------------------
Expires
--------------
2005 &
Company Total Unused 2004 beyond
- ------- --------------------------------------
(in millions)
Alabama Power $ 865 $ 865 $ 865 $ -
Georgia Power 725 725 725 -
Gulf Power 56 56 56 -
Mississippi Power 100 100 100 -
Savannah Electric 80 60 40 20
Southern Company 1,000 1,000 1,000 -
Southern Power 650 650 - 650
Other 20 20 20 -
- ----------------------------------------------------------------
Total $3,496 $3,476 $2,806 $670
================================================================
Approximately $2.25 billion of the credit facilities expiring in 2004 allow
the execution of term loans for an additional two-year period, and $265 million
allow execution of one-year term loans. 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 retail 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 $3.5 billion of unused credit
arrangements is $2.8 billion of syndicated credit arrangements that require the
payment of agent fees.
Most of Southern Company's, Southern Power's, and the retail operating
companies' credit arrangements with banks have covenants that limit debt levels
to 65 percent of total capitalization, as defined in the agreements. Exceeding
these debt levels would result in a default under the credit arrangements At
December 31, 2003, Southern Company, Southern Power, and the retail operating
companies were in compliance with their respective debt limit covenants. 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
retail 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
II-53
NOTES (continued)
Southern Company and Subsidiary Companies 2003 Annual Report
if triggered would require prepayment of debt related to projects financed under
the credit arrangement that are not complete. Southern Company has committed to
fund at least 35 percent on Southern Power's construction project financing and
to pay for construction overruns to the extent that Southern Power's cash flow
is insufficient. Southern Company and its subsidiaries are currently in
compliance with all such covenants. Borrowings under certain retail operating
companies' unused credit arrangements totaling $50 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 $3.5 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, 2003, was $659 million.
Southern Company, the retail operating companies, and Southern Power borrow
through commercial paper programs that have the liquidity support of committed
bank credit arrangements. In addition, Southern Company and the retail operating
companies from time to time borrow through extendible commercial note programs.
As of December 31, 2003, no extendible commercial notes were outstanding. The
amount of commercial paper outstanding at December 31, 2003, and December 31,
2002, was $568 million and $858 million, respectively. During 2003, the peak
amount outstanding for commercial paper was $1.66 billion, and the average
amount outstanding was $900 million. The average annual interest rate on
commercial paper was 1.3 percent in 2003. Commercial paper is included in notes
payable on the Consolidated Balance Sheets.
Financial Instruments
The retail operating companies, Southern Power, and Southern Company GAS enter
into energy-related derivatives to hedge exposures to electricity, gas, and
other fuel price changes. However, due to cost-based rate regulations, the
retail operating companies have limited exposure to market volatility in
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. Each of the retail operating companies has
implemented fuel-hedging programs at the instruction of their respective public
service commissions. Together with Southern Power, the retail operating
companies may enter into hedges of forward electricity sales. Southern Company
GAS has gas-hedging programs to substantially mitigate its exposure to price
volatility for its gas purchases.
At December 31, 2003, the fair value of derivative energy contracts was
reflected in the financial statements as follows:
Amounts
- ---------------------------------------------------------------
(in millions)
Regulatory liabilities, net $14.9
Other comprehensive income 1.5
Net income (0.6)
- ---------------------------------------------------------------
Total fair value $15.8
===============================================================
The fair value gains or losses for cash flow hedges that are recoverable
through the regulatory fuel clauses are recorded as regulatory assets and
liabilities and are recognized in earnings at the same time the hedged items
affect earnings. For Southern Power and Southern Company GAS, the fair value
gains or losses for cash flow hedges are recorded in other comprehensive income
and are reclassified into earnings at the same time the hedged items affect
earnings. For the year 2003, approximately $22 million of pre-tax gains were
reclassified from other comprehensive income to fuel expense. For the year 2004,
approximately $5 million of pre-tax gains are expected to be reclassified from
other comprehensive income to fuel expense.
Southern Company and certain subsidiaries also enter into derivatives to
hedge exposure to interest rate changes. Derivatives related to fixed rate
securities are accounted for as fair value hedges. Derivatives related to
variable rate securities or forecasted transactions are accounted for as cash
flow hedges. The derivatives are generally structured to match the critical
terms of the hedged debt instruments; therefore, no material ineffectiveness has
been recorded in earnings.
II-54
NOTES (continued)
Southern Company and Subsidiary Companies 2003 Annual Report
At December 31, 2003, Southern Company had $3.0 billion notional amount of
interest rate swaps outstanding with net fair value gains of $33 million as
follows:
Fair Value Hedges
Variable Fair
Rate Notional Value
Company Maturity Paid Amount Gain
- ------------------------------------------ ------------------
(in millions)
Southern
Company 2007 6-month $400 $30.9
LIBOR - 0.10%
2009 6-month $40 $0.8
LIBOR + 2.92%
- ---------------------------------------------------------------
Cash Flow Hedges
Weighted Average Fair
Fixed Value
Rate Notional Gain/
Company Maturity Paid Amount (Loss)
- ------------------------------------------ ------------------
(in millions)
Southern
Company 2004 3.20% $200 $(2.0)
Alabama
Power 2004 1.63* 486 (0.2)
2006 1.89 195 1.5
2007 1.99* 486 4.4
Georgia
Power 2004 1.39* 873 (0.8)
2005 1.56 50 -
2005 1.96 250 (1.1)
Savannah
Electric 2004 2.06 20 (0.1)
- ------------------------------------------------------------------
*Hedged using the Bond Market Association Municipal Swap Index.
For fair value hedges where the hedged item is an asset, liability, or firm
commitment, the changes in the fair value of the hedging derivatives are
recorded in earnings and are offset by the changes in the fair value of the
hedged item.
The fair value gain or loss for cash flow hedges is recorded in other
comprehensive income and is reclassified into earnings at the same time the
hedged items affect earnings. In 2003 and 2002, the company recognized losses of
$116 million and $14 million, respectively, upon termination of certain interest
derivatives at the same time it issued debt. These losses have been deferred in
other comprehensive income and will be amortized to interest expense over the
life of the related debt. For 2003, approximately $26 million of pre-tax losses
were reclassified from other comprehensive income to interest expense. For 2004,
pre-tax losses of approximately $22 million are expected to be reclassified from
other comprehensive income to interest expense.
7. COMMITMENTS
Construction Program
Southern Company is engaged in continuous construction programs, currently
estimated to total $2.2 billion in 2004, $2.2 billion in 2005, and $2.6 billion
in 2006. These amounts include $41 million, $31 million, and $27 million in
2004, 2005, and 2006, respectively, for construction expenditures related to
contractual purhase commitments for uranium and nuclear fuel conversion,
enrichment, and fabrication services included in this note under "Fuel and
Purchased Power Commitments." 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; changes in FERC rules and
transmission regulations; increasing costs of labor, equipment, and materials;
and cost of capital. At December 31, 2003, significant purchase commitments were
outstanding in connection with the construction program. Southern Company has
approximately 1,200 megawatts of additional generating capacity scheduled to be
placed in service by 2005. In addition, capital improvements to generation,
transmission, and distribution facilities -- including those to meet
environmental standards -- will continue.
Long-Term Service Agreements
The retail 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
II-55
NOTES (continued)
Southern Company and Subsidiary Companies 2003 Annual Report
respective units. Total payments to GE under these agreements for facilities
owned are currently estimated at $1.3 billion over the remaining 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 purchase commitments contain given volumes with prices based on
various indices at the time of delivery. Amounts included in the chart below
represent estimates based on New York Mercantile future prices at December 31,
2003. Also, Southern Company has entered into various long-term commitments for
the purchase of electricity. Total estimated minimum long-term obligations at
December 31, 2003 were as follows:
Coal and
Natural Nuclear Purchased
Year Gas Fuel Power
- ------------------------------------------------------------
(in millions)
2004 $ 814 $2,409 $ 139
2005 538 1,723 174
2006 491 1,475 181
2007 350 1,131 183
2008 269 544 184
2009 and thereafter 2,763 182 918
- ------------------------------------------------------------
Total commitments $5,225 $7,464 $1,779
============================================================
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. In 2003, the generating
facility was acquired by Juniper Capital L.P. (Juniper), whose partners are
unaffiliated with Mississippi Power. Simultaneously, Juniper entered into a
restructured lease agreement with Mississippi Power. Juniper has also entered
into leases with other parties unrelated to Mississippi Power. The assets leased
by Mississippi Power comprise less than 50 percent of Juniper's assets. In
accordance with FASB Interpretation No. 46, Mississippi Power is not required to
consolidate the leased assets and related liabilities, and the lease with
Juniper is considered an operating lease under FASB Statement No. 13. The
initial lease term ends in 2011, and the lease includes a purchase and renewal
option based on the cost of the facility at the inception of the lease, which
was $369 million. Mississippi Power is required to amortize approximately four
percent of the initial acquisition cost over the initial lease term. Eighteen
months prior to the end of the initial lease, Mississippi Power may elect to
renew for 10 years. If the lease is renewed, the agreement calls for Mississippi
Power to amortize an additional 17 percent of the initial completion cost over
the renewal period. Upon termination of the lease, at Mississippi Power's
option, it may either exercise its purchase option or the facility can be sold
to a third party.
The lease provides for a residual value guarantee -- approximately 73
percent of the acquisition cost -- by Mississippi Power that is due upon
termination of the lease in the event that Mississippi Power does not renew the
lease or purchase the assets and that the fair market value is less than the
unamortized cost of the asset. Mississippi Power has recognized in the balance
sheet a liability of approximately $15 million for the fair market value of this
residual value guarantee. In 2003, approximately $11 million in lease
termination costs were included in operation expenses and $26 million in lease
expense. The amount of future minimum operating lease payments will be
approximately $29 million annually during the initial term.
Southern Company has other operating lease agreements with various terms and
expiration dates. Total operating lease expenses were $156 million, $171
million, and $64 million for 2003, 2002, and 2001, respectively. At December 31,
2003, estimated minimum rental commitments for noncancelable operating leases
were as follows:
Rail
Year Cars Other Total
- ---- ----------------------------
(in millions)
2004 $ 36 $ 92 $128
2005 33 80 113
2006 28 67 95
2007 19 57 76
2008 19 48 67
2009 and thereafter 106 156 262
- ---------------------------------------------------------------
Total minimum payments $241 $500 $741
===============================================================
II-56
NOTES (continued)
Southern Company and Subsidiary Companies 2003 Annual Report
For the retail 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, 2003, the total notional amount of
guarantees outstanding was less than $30 million, all of which will expire by
2009. Under the terms of the separation agreement, Mirant may not enter into any
new commitments under these guarantees after the spin off date and must use
reasonable efforts to release Southern Company from all such support
arrangements and indemnify Southern Company for any obligations incurred.
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. However, in December
2003, Mirant notified Southern Company that the Bankruptcy Code provides relief
from paying this fee.
Southern Company has executed a keep-well agreement with a subsidiary of
Southern Holdings 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," Alabama Power,
Georgia Power, and Mississippi Power have entered into certain residual value
guarantees. Also, Southern Company has certain contingent liabilities as
discussed in Note 3 under "Mobile Energy Services' Petition for Bankruptcy."
8. COMMON STOCK
Stock Issued
Southern Company raised $470 million or 18 million shares in 2003 and $378
million or 16 million shares in 2002 from the issuance of new common shares
under the company's various stock plans. Southern Company issued 2 million and
17 million treasury shares of common stock in 2002 and 2001, respectively,
through various company stock plans. Proceeds from the issuance of treasury
stock were $56 million in 2002 and $395 million in 2001.
Shares Reserved
At December 31, 2003, a total of 60 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, 2003,
6,202 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
II-57
NOTES (continued)
Southern Company and Subsidiary Companies 2003 Annual Report
in accordance with the plan. Stock option data for the plan has been adjusted to
reflect the Mirant spin off. Activity from 2001 to 2003 for the plan is
summarized below:
Shares Average
Subject Option Price
To Option Per Share
- ---------------------------------------------------------------
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 (104,212) 19.64
Options exercised (4,892,354) 15.16
- ---------------------------------------------------------------
Balance at December 31, 2002 32,674,814 19.72
Options granted 7,165,452 27.98
Options canceled (183,038) 24.35
Options exercised (5,725,336) 16.56
- ---------------------------------------------------------------
Balance at December 31, 2003 33,931,892 $21.97
===============================================================
Shares reserved for future grants:
At December 31, 2001 54,795,653
At December 31, 2002 46,788,994
At December 31, 2003 39,752,039
- ---------------------------------------------------------------
Options exercisable:
At December 31, 2001 11,965,858
At December 31, 2002 15,463,414
At December 31, 2003 18,872,769
- ----------------------------------------------------------------
The following table summarizes information about options outstanding at
December 31, 2003:
Dollar Price
Range of Options
---------------------------
13-19 19-25 25-30
- ---------------------------------------------------------------
Outstanding:
Shares (in thousands) 7,428 11,719 14,785
Average remaining
life (in years) 4.7 6.2 8.3
Average exercise price $15.32 $20.39 $26.57
Exercisable:
Shares (in thousands) 7,428 8,303 3,142
Average exercise price $15.32 $20.40 $25.49
- ---------------------------------------------------------------
The estimated fair values of stock options granted in 2003, 2002, and 2001
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:
2003 2002 2001
- ---------------------------------------------------------------
Interest rate 2.7% 2.8% 4.8%
Average expected life of
stock options (in years) 4.3 4.3 4.3
Expected volatility of
common stock 23.6% 26.3% 25.4%
Expected annual dividends
on common stock $1.37 $1.34 $1.34
Weighted average fair value
of stock options granted $3.59 $3.37 $2.82
- ---------------------------------------------------------------
The pro forma impact of fair-value accounting for options granted on earnings
from continuing operations is as follows:
As Pro
Reported Forma
- ---------------------------------------------------------------
2003
Net income (in millions) $1,474 $1,456
Earnings per share (dollars):
Basic $2.03 $2.00
Diluted $2.02 $1.99
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
- ---------------------------------------------------------------
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
-------------------------------
2003 2002 2001
- ---------------------------------------------------------------
(in thousands)
As reported shares 726,702 708,161 689,352
Effect of options 5,202 5,409 4,191
- ---------------------------------------------------------------
Diluted shares 731,904 713,570 693,543
===============================================================
II-58
NOTES (continued)
Southern Company and Subsidiary Companies 2003 Annual Report
Common Stock Dividend Restrictions
The income of Southern Company is derived primarily from equity in earnings of
its subsidiaries. At December 31, 2003, consolidated retained earnings included
$3.9 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.
In accordance with the PUHCA, the subsidiaries are also restricted from
paying common dividends from paid-in capital without SEC approval.
9. 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
$10.9 billion for public liability claims that could arise from a single nuclear
incident. Each nuclear plant is insured against this liability to a maximum of
$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 $101 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 $201 million and $203 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. The Price-Anderson
Amendments Act expired in August 2002; however, the indemnity provisions of the
act remain in place for commercial nuclear reactors.
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 up 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. Both companies, however, revised their policy
terms on a prospective basis to include an industry aggregate for all
"non-certified" terrorist acts, i.e., acts that are not certified acts of
terrorism pursuant to the Terrorism Risk Insurance Act of 2002 (TRIA). The NEIL
aggregate -- applies to non-certified claims stemming from terrorism within a
12-month duration -- is $3.24 billion plus any amounts available through
reinsurance or indemnity from an outside source. The non-certified ANI cap is a
$300 million shared industry aggregate. Any act of terrorism that is certified
pursuant to the TRIA will not be subject to the foregoing NEIL and ANI
limitations but will be subject to the TRIA annual aggregate limitation of $100
billion of insured losses arising from certified acts of terrorism. The TRIA
will expire on December 31, 2005.
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.
II-59
NOTES (continued)
Southern Company and Subsidiary Companies 2003 Annual Report
10. SEGMENT AND RELATED INFORMATION
Southern Company's reportable business segment is the sale of electricity in the
Southeast by the five retail 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 investments in synthetic fuels and leveraged
lease projects, telecommunications, energy-related services, and natural gas
marketing. Intersegment revenues are not material. Financial data for business
segments and products and services are as follows:
Business Segments
Electric Utilities
----------------------------------
Retail
Operating Southern All
Companies Power Eliminations Total Other Eliminations Consolidated
- ----------------------------------------------------------------------------------------------------------------------------------
(in millions)
2003
- -----
Operating revenues $10,502 $ 682 $(437) $10,747 $ 526 $ (22) $11,251
Depreciation and amortization 933 39 - 972 55 - 1,027
Interest income 33 - - 33 6 (3) 36
Interest expense 542 32 - 574 107 (3) 678
Income taxes 760 85 - 845 (233) - 612
Segment net income (loss) 1,269 155 - 1,424 50 - 1,474
Total assets 31,412 2,409 (122) 33,699 1,671 (325) 35,045
Gross property additions 1,625 344 - 1,969 33 - 2,002
- ----------------------------------------------------------------------------------------------------------------------------------
Electric Utilities
----------------------------------------------------------------------------------------------
Retail
Operating Southern All
Companies Power Eliminations Total Other Eliminations Consolidated
- ----------------------------------------------------------------------------------------------------------------------------------
(in millions)
2002
- -----
Operating revenues $10,109 $ 299 $(202) $10,206 $ 365 $ (22) $10,549
Depreciation and amortization 970 18 - 988 59 - 1,047
Interest income 19 - - 19 10 (7) 22
Interest expense 559 9 - 568 105 (6) 667
Income taxes 749 28 - 777 (249) - 528
Segment net income (loss) 1,242 54 - 1,296 23 (1) 1,318
Total assets 30,367 2,086 (78) 32,375 1,881 (535) 33,721
Gross property additions 1,773 1,215 (390) 2,598 119 - 2,717
- ----------------------------------------------------------------------------------------------------------------------------------
II-60
Electric Utilities
---------------------------------------------------------------------------------------------
Retail
Operating Southern All
Companies Power Eliminations Total Other Eliminations Consolidated
- ----------------------------------------------------------------------------------------------------------------------------------
(in millions)
2001
- ----
Operating revenues $ 9,883 $ 29 $ (6) $ 9,906 $ 267 $ (18) $10,155
Depreciation and amortization 1,141 3 - 1,144 29 - 1,173
Interest income 21 - - 21 8 (2) 27
Interest expense 590 1 - 591 137 (2) 726
Income taxes 700 2 - 702 (144) - 558
Segment net income (loss) 1,141 8 - 1,149 (30) 143 1,262
Gross property additions 2,444 751 (630) 2,565 52 - 2,617
- ----------------------------------------------------------------------------------------------------------------------------------
Products and Services
Electric Utilities Revenues
- ----------------------------------------------------------------------------------------------------------------------------------
Year Retail Wholesale Other Total
- ----------------------------------------------------------------------------------------------------------------------------------
(in millions)
2003 $8,875 $1,358 $514 $10,747
2002 8,728 1,168 310 10,206
2001 8,440 1,174 292 9,906
- ----------------------------------------------------------------------------------------------------------------------------------
11. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Summarized quarterly financial data for 2003 and 2002 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 2003 $2,548 $ 605 $298 $0.41 $0.3425 $30.81 $27.71
June 2003 2,845 806 432 0.60 0.3425 31.81 27.94
September 2003 3,318 1,118 619 0.85 0.3500 30.53 27.76
December 2003 2,540 366 125 0.17 0.3500 30.40 28.65
March 2002 $2,214 $ 526 $224 $0.32 $0.3350 $26.78 $24.49
June 2002 2,630 676 332 0.47 0.3350 28.39 25.65
September 2002 3,248 1,089 595 0.84 0.3425 29.02 23.89
December 2002 2,457 355 167 0.23 0.3425 30.85 25.17
- ----------------------------------------------------------------------------------------------------------------------------------
Southern Company's business is influenced by seasonal weather conditions.
II-61
SELLECTED CONSOLIDATED FINANCIAL AND OPERATING DATA 1999-2003
Southern Company and Subsidiary Companies 2003 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------------
2003 2002 2001 2000 1999
- ----------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in millions) $11,251 $10,549 $10,155 $10,066 $9,317
Total Assets (in millions) $35,045 $33,721 $31,856 $33,282 $31,102
Gross Property Additions (in millions) $2,002 $2,717 $2,617 $2,225 $1,881
Return on Average Common Equity (percent) 16.05 15.79 13.51 13.20 13.43
Cash Dividends Paid Per Share of Common Stock $1.385 $1.355 $1.34 $1.34 $1.34
- ----------------------------------------------------------------------------------------------------------------------------------
Consolidated Net Income (in millions):
Continuing operations $1,474 $1,318 $1,120 $ 994 $ 915
Discontinued operations - - 142 319 361
- ----------------------------------------------------------------------------------------------------------------------------------
Total $1,474 $1,318 $1,262 $1,313 $1,276
==================================================================================================================================
Earnings Per Share From Continuing Operations --
Basic $2.03 $1.86 $1.62 $1.52 $1.33
Diluted 2.02 1.85 1.61 1.52 1.33
Earnings Per Share Including Discontinued Operations --
Basic $2.03 $1.86 $1.83 $2.01 $1.86
Diluted 2.02 1.85 1.82 2.01 1.86
- ----------------------------------------------------------------------------------------------------------------------------------
Capitalization (in millions):
Common stock equity $ 9,648 $ 8,710 $ 7,984 $10,690 $ 9,204
Preferred stock 423 298 368 368 369
Long-term debt 12,064 11,094 10,573 10,089 9,497
- ----------------------------------------------------------------------------------------------------------------------------------
Total excluding amounts due within one year $22,135 $20,102 $18,925 $21,147 $19,070
==================================================================================================================================
Capitalization Ratios (percent):
Common stock equity 43.6 43.3 42.2 50.6 48.3
Preferred stock 1.9 1.5 1.9 1.7 1.9
Long-term debt 54.5 55.2 55.9 47.7 49.8
- ----------------------------------------------------------------------------------------------------------------------------------
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) $13.13 $12.16 $11.43 $15.69 $13.82
Market price per share (dollars):
High $31.810 $30.850 $26.000 $35.000 $29.625
Low 27.710 23.890 16.152 20.375 22.063
Close 30.250 28.390 25.350 33.250 23.500
Market-to-book ratio (year-end) (percent) 230.4 233.5 221.8 211.9 170.0
Price-earnings ratio (year-end) (times) 14.9 15.3 15.6 16.5 12.6
Dividends paid (in millions) $1,004 $958 $922 $873 $921
Dividend yield (year-end) (percent) 4.6 4.8 5.3 4.0 5.7
Dividend payout ratio (percent) 68.1 72.8 82.4 66.5 72.2
Shares outstanding (in thousands):
Average 726,702 708,161 689,352 653,087 685,163
Year-end 734,829 716,402 698,344 681,158 665,796
Stockholders of record (year-end) 134,068 141,784 150,242 160,116 174,179
- ----------------------------------------------------------------------------------------------------------------------------------
Customers (year-end) (in thousands):
Residential 3,552 3,496 3,441 3,398 3,339
Commercial 564 553 539 527 513
Industrial 14 14 14 14 15
Other 6 5 4 5 4
- ----------------------------------------------------------------------------------------------------------------------------------
Total 4,136 4,068 3,998 3,944 3,871
==================================================================================================================================
Employees (year-end) 25,762 26,178 26,122 26,021 26,269
- ----------------------------------------------------------------------------------------------------------------------------------
Note: Common stock data in 2001 declined as a result of the Mirant spin off.
II-62
SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA 1999-2003 (continued)
Southern Company and Subsidiary Companies 2003 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------------
2003 2002 2001 2000 1999
- ----------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in millions):
Residential $ 3,565 $ 3,556 $ 3,247 $ 3,361 $3,107
Commercial 3,075 3,007 2,966 2,918 2,745
Industrial 2,146 2,078 2,144 2,289 2,238
Other 89 87 83 32 -
- ----------------------------------------------------------------------------------------------------------------------------------
Total retail 8,875 8,728 8,440 8,600 8,090
Sales for resale within service area 403 393 338 377 350
Sales for resale outside service area 955 775 836 600 473
- ----------------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 10,233 9,896 9,614 9,577 8,913
Other revenues 1,018 653 541 489 404
- ----------------------------------------------------------------------------------------------------------------------------------
Total $11,251 $10,549 $10,155 $10,066 $9,317
==================================================================================================================================
Kilowatt-Hour Sales (in millions):
Residential 47,833 48,784 44,538 46,213 43,402
Commercial 48,372 48,250 46,939 46,249 43,387
Industrial 54,415 53,851 52,891 56,746 56,210
Other 998 1,000 977 970 945
- ----------------------------------------------------------------------------------------------------------------------------------
Total retail 151,618 151,885 145,345 150,178 143,944
Sales for resale within service area 10,610 10,597 9,388 9,579 9,440
Sales for resale outside service area 29,910 21,954 21,380 17,190 12,929
- ----------------------------------------------------------------------------------------------------------------------------------
Total 192,138 184,436 176,113 176,947 166,313
==================================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 7.45 7.29 7.29 7.27 7.16
Commercial 6.36 6.23 6.32 6.31 6.33
Industrial 3.94 3.86 4.05 4.03 3.98
Total retail 5.85 5.75 5.81 5.73 5.62
Sales for resale 3.35 3.59 3.82 3.65 3.68
Total sales 5.33 5.37 5.46 5.41 5.36
Average Annual Kilowatt-Hour
Use Per Residential Customer 13,562 14,036 13,014 13,702 13,107
Average Annual Revenue Per Residential Customer $1,010.82 $1,023.18 $948.83 $996.44 $938.39
Plant Nameplate Capacity Owned (year-end) (megawatts) 38,679 36,353 34,579 32,807 31,425
Maximum Peak-Hour Demand (megawatts):
Winter 31,318 25,939 26,272 26,370 25,203
Summer 32,949 32,355 29,700 31,359 30,578
System Reserve Margin (at peak) (percent) 21.4 13.3 19.3 8.1 8.5
Annual Load Factor (percent) 62.0 51.1 62.0 60.2 59.2
Plant Availability (percent):
Fossil-steam 87.7 84.8 88.1 86.8 83.3
Nuclear 94.4 90.3 90.8 90.5 89.9
- ----------------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 66.4 65.7 67.5 72.3 73.1
Nuclear 14.8 14.7 15.2 15.1 15.7
Hydro 3.8 2.6 2.6 1.5 2.3
Gas 8.8 11.4 8.4 4.0 2.8
Purchased power 6.2 5.6 6.3 7.1 6.1
- ----------------------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0 100.0 100.0
==================================================================================================================================
II-63
ALABAMA POWER COMPANY
FINANCIAL SECTION
II-64
MANAGEMENT'S REPORT
Alabama Power Company 2003 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 internal accounting controls are 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
four independent directors, provides a broad overview of management's financial
reporting and control functions. Additionally, the controls and compliance
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
March 1, 2004
II-65
INDEPENDENT AUDITORS' REPORT
Alabama Power Company:
We have audited the accompanying balance sheets and statements of capitalization
of Alabama Power Company (a wholly owned subsidiary of Southern Company) as of
December 31, 2003 and 2002, and the related statements of income, comprehensive
income, common stockholder's equity, and cash flows for the years 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 audits. The financial statements of Alabama Power
Company for the year ended December 31, 2001 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 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, the financial statements (pages II-83 to II-105) present
fairly, in all material respects, the financial position of Alabama Power
Company at December 31, 2003 and 2002, and the results of its operations and its
cash flows for the years then ended in conformity with accounting principles
generally accepted in the United States of America.
As discussed in Note 1 to the financial statements, in 2003 Alabama Power
Company changed its method of accounting for asset retirement obligations.
/s/Deloitte & Touche LLP
Birmingham, Alabama
March 1, 2004
THE FOLLOWING REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS IS A COPY OF THE REPORT
PREVIOUSLY ISSUED IN CONNECTION WITH THE COMPANY'S 2001 ANNUAL REPORT 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-66
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Alabama Power Company 2003 Annual Report
OVERVIEW OF EARNINGS AND BUSINESS
- ----------------------------------
ACTIVITIES
- ------------
Earnings
Alabama Power Company's 2003 net income after dividends on preferred stock was
$473 million, representing a $12 million (2.5 percent) increase from the prior
year. This improvement is due primarily to higher sales for resale, increases in
other revenues, and lower interest expense, partially offset by higher non-fuel
operating expenses.
In 2002, earnings were $461 million, representing a 19.3 percent increase
from the prior year. This improvement was 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. Earnings in 2001 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.
The return on average common equity for 2003 was 13.75 percent compared to
13.80 percent in 2002 and 11.89 percent in 2001.
Business Activities
The Company 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.
Several factors affect the opportunities, challenges, and risk of the
Company's primary business of selling electricity. These factors include the
ability to maintain a stable regulatory environment, to achieve energy sales
growth while containing costs, and to recover costs related to growing demand
and increasingly stricter environmental standards. 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, new energy
contracts with neighboring utilities, energy conservation practiced by
customers, the price elasticity of demand, and the rate of economic growth in
the service area.
RESULTS OF OPERATIONS
- ---------------------
A condensed income statement is as follows:
Increase (Decrease)
Amount From Prior Year
- ----------------------------------------------------------------
2003 2003 2002 2001
- ----------------------------------------------------------------
(in millions)
Operating revenues $3,960 $250 $124 $(81)
- ----------------------------------------------------------------
Fuel 1,068 98 (31) 38
Purchased power 315 66 (44) (56)
Other operation
and maintenance 921 67 71 (56)
Depreciation
and amortization 413 15 15 19
Taxes other than
income taxes 228 11 2 5
- ----------------------------------------------------------------
Total operating
expenses 2,945 257 13 (50)
- ----------------------------------------------------------------
Operating income 1,015 (7) 111 (31)
Other income
(expense), net (252) 17 7 (15)
Less --
Income taxes 290 (2) 44 (13)
- ----------------------------------------------------------------
Net Income $ 473 $ 12 $ 74 $(33)
================================================================
Revenues
Operating revenues for 2003 were nearly $4.0 billion, reflecting a $250 million
increase from 2002. The following table summarizes the principal factors that
have affected operating revenues for the past three years:
Amount
- ------------------------------------------------------------------
2003 2002 2001
- ------------------------------------------------------------------
(in millions)
Retail -- prior year $2,951 $2,748 $2,953
Change in -
Base rates 51 76 23
Sales growth 68 70 (36)
Weather (61) 60 (62)
Fuel cost recovery
and other 42 (3) (130)
- ------------------------------------------------------------------
Retail -- current year 3,051 2,951 2,748
- ------------------------------------------------------------------
Sales for resale --
Non-affiliates 488 474 486
Affiliates 277 188 245
- ------------------------------------------------------------------
Total sales for resale 765 662 731
- ------------------------------------------------------------------
Other operating revenues 144 97 107
- ------------------------------------------------------------------
Total operating revenues $3,960 $3,710 $3,586
==================================================================
Percent change 6.7% 3.5% (2.2)%
- ------------------------------------------------------------------
II-67
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2003 Annual Report
Retail revenues in 2003 were $3.1 billion. Revenues increased $100 million
(3.4 percent) from the prior year, increased $203 million (7.4 percent) in 2002,
and decreased $205 million (6.9 percent) in 2001. All sectors of retail revenues
increased for the Company in 2003 primarily due to increased fuel revenue and a
2.6 percent increase in retail base rates which went into effect in July 2003.
See Note 3 to the financial statements under "Retail Rate Adjustment Procedures"
for additional information.
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 both October 2001 and April 2002). The Company mitigated
the effect of these increases to customers with a decrease to the energy cost
recovery factor in April 2002.
The revenue decrease in 2001 was primarily due to the negative impact of
milder temperatures on energy sales and an economic downturn in the Company's
service territory.
Fuel rates billed to customers are designed to fully recover fluctuating
fuel costs over a period of time. At December 31, 2003, the Company had no
unrecovered fuel costs. Fuel revenues have no effect on net income because they
represent the recording of revenues to offset fuel expenses.
Sales for resale to non-affiliates are predominantly unit power sales under
long-term contracts to Florida utilities. Revenues from power sales contracts
have both capacity and energy components. Capacity revenues reflect the recovery
of fixed costs and a return on investment under the contracts. Energy is
generally sold at variable cost. These capacity and energy components of the
unit power contracts were as follows:
2003 2002 2001
------------------------------------
(in thousands)
Unit power -
Capacity $130,022 $119,193 $124,720
Energy 145,342 134,051 134,006
--------------------------------------------------- -----------
Total $275,364 $253,244 $258,726
===============================================================
There are no significant scheduled declines in unit power sales capacity
until the termination of the unit power sales contracts in 2010.
Short-term opportunity energy sales are also included in sales for resale
to non-affiliates. These opportunity sales are made at market rates that
generally include the recovery of fixed costs and a return, in addition to the
variable energy cost. Revenues associated with other power sales to
non-affiliates were as follows:
2003 2002 2001
--------------------------------
(in thousands)
Other power sales -
Capacity and other $33,858 $14,613 $ 13,324
Variable cost of energy 44,627 61,925 91,608
---------------------------------------------------- ----------
Total $78,485 $76,538 $104,932
===============================================================
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.
Sales for resale revenues increased $26.6 million in 2003 due to increased
capacity payments received in accordance with the affiliated company interchange
agreements as a result of increased capacity. Excluding the capacity revenues,
these transactions do not have a significant impact on earnings since the energy
is generally sold at marginal cost and energy purchases are generally offset by
energy revenues through the Company's energy cost recovery clause.
Other operating revenues in 2003 increased $47 million (48.6 percent) from
2002 due to an increase of $19.4 million in revenues from gas-fueled
co-generation steam facilities -- primarily as a result of higher gas prices --
and a $14.8 million increase in revenues from Alabama Public Service Commission
(Alabama PSC) approved fees charged to customers for connection, reconnection,
and collection when compared to the same period in 2002. Since co-generation
steam revenues are generally offset by fuel expenses, these revenues did not
have a significant impact on earnings.
The $11 million (9.9 percent) decrease in other operating revenues in 2002
resulted primarily from a $7.0 million decrease in revenues from gas-fueled
co-generation steam facilities due to lower gas prices and lower demand. The $21
million (23.9 percent) increase in 2001 was primarily attributed to a $6.4
million increase in steam sales in conjunction with the operation of the
Company's co-generation facilities, a $5.3 million increase in fuel sales, and a
$5.1 million increase in rent from electric property.
II-68
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2003 Annual Report
Energy Sales
Changes in revenues are influenced heavily by the volume of energy sold each
year. Kilowatt-hour (KWH) sales for 2003 and the percent change by year were as
follows:
KWH Percent Change
----------------------------------------
2003 2003 2002 2001
----------------------------------------
(millions)
Residential 16,960 (2.5)% 9.6% (5.3)%
Commercial 13,452 0.7 4.4 (1.5)
Industrial 21,593 2.3 3.1 (7.4)
Other 203 (1.1) 3.7 (3.9)
----------
Total retail 52,208 0.3 5.5 (5.2)
Sales for resale -
Non-affiliates 17,086 9.9 1.8 2.9
Affiliates 9,422 6.5 - 64.7
----------
Total 78,716 2.9 4.1 1.6
- ---------------------------------------------------------------
Residential energy sales for 2003 experienced a 2.5 percent decrease over
the prior year and total retail energy sales grew by 0.3 percent primarily as a
result of milder-than-normal summer temperatures compared to the previous year.
Although retail sales to industrial customers increased 2.3 percent in 2003 and
3.1 percent in 2002, overall sales to industrial customers remained depressed
due to the continuing effect of sluggish economic conditions.
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.
The decrease in 2001 retail energy sales was primarily 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.
Assuming normal weather, sales to retail customers are projected to grow
approximately 1.7 percent annually on average during 2004 through 2008.
Expenses
The total operating expenses in 2003 were approximately $3.0 billion, an
increase of $257 million (9.6 percent) over the previous year. This increase is
mainly due to a $98 million increase in fuel expense primarily related to an
increase in the average cost of natural gas and coal. In addition, purchased
power expenses increased a total of $66 million, maintenance expense increased
$30 million primarily related to transmission and distribution overhead lines,
and depreciation and amortization expense increased $15 million.
In 2002, total operating expenses of $2.7 billion increased by $13 million
(0.5 percent) over the previous year. This slight increase was mainly due to a
$35 million increase in administrative and general expenses primarily related to
employee salaries, insurance expense, and accrued expenses for liability
insurance, litigation and workers compensation, a $19 million increase in
production expenses related to boiler plant maintenance, and a $15 million
increase in depreciation and amortization expenses due to an increase in
depreciable property. These increases were offset by a $43 million decrease in
purchased power expenses and a $14 million decrease in fuel expenses related to
lower coal prices.
In 2001, total operating expenses of $2.7 billion were down $50 million
(1.8 percent) compared with 2000. This decline was 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 Southern Company Services (SCS) and
Southern Nuclear Operating Company, 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.
Fuel costs constitute the single largest expense for the
Company. The mix of fuel sources for generation of electricity is determined
primarily by demand, the unit cost of fuel consumed, and the availability of
fossil and nuclear generating units and hydro generation. The amount and sources
of generation and the average cost of fuel per net KWH generated and the average
cost of purchased power were as follows:
II-69
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2003 Annual Report
--------------------------
2003 2002 2001
--------------------------
Total generation
(billions of KWHs) 72 71 68
Sources of generation
(percent) --
Coal 64 62 64
Nuclear 19 19 18
Hydro 8 6 6
Gas 9 13 12
Average cost of fuel per net
kilowatt-hour generated
(cents) 1.67 1.47 1.56
Average cost of purchased
power per net kilowatt-hour
(cents) 3.56 2.91 3.28
- --------------------------------------------------------------
In 2003, total fuel and purchased power expenses of $1.4 billion increased
$164 million (13.4 percent) over 2002 due to a 58.3 percent increase in average
gas prices and a 2.2 percent increase in average coal prices. Fuel and purchased
power expenses in 2002 of $1.2 billion decreased $75 million (5.8 percent) due
primarily to lower average fuel cost, while total energy sales increased 3.0
billion 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 reduced generation due to milder temperatures in
2001. Fuel expenses, including purchased power, are offset by fuel revenues
through the Company's energy cost recovery clause and have no effect on net
income.
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. In 2003, purchased power from non-affiliates
increased $20 million (22 percent) due to a 19.3 percent increase in price and a
9.5 percent increase in energy purchased when compared to 2002. 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 3.6 percent in 2003, 3.9
percent in 2002, and 5.2 percent in 2001. These increases reflect additions to
property, plant, and equipment.
Allowance for Equity Funds Used During Construction (AFUDC) increased $1.4
million (12.8 percent) in 2003 due to an increase in the applicable AFUDC rate.
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 completing construction of Plant Barry
Unit 7 and placing it in service in May 2001.
Interest expense, net of amounts capitalized, of $214 million in 2003
decreased $11.4 million (5.1 percent) from 2002, which had decreased $21 million
(8.4 percent) from 2001. Both years reflect a decrease in interest rates on
long-term debt due to refinancing activities. Interest expense increased $11
million (4.7 percent) in 2001 compared to 2000.
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.
Future Earnings Potential
General
The results of 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. Major factors include the ability of the
Company to maintain a stable regulatory environment, to achieve energy sales
growth while containing costs, and to recover costs related to growing demand
and increasingly stricter environmental standards. Growth in energy sales is
II-70
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2003 Annual Report
subject to a number of factors. These factors include weather, competition, new
energy contracts with neighboring utilities, energy conservation practiced by
customers, the price elasticity of demand, and the rate of economic growth in
the Company's service area.
Industry Restructuring
The Company operates as a vertically integrated utility providing electricity to
customers within its traditional service area located in the State of Alabama
and to wholesale customers in the Southeast.
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
allowed independent power producers to access a utility's transmission network
and sell electricity to other utilities.
Although the Energy Act does not provide for retail customer access, it was
a major catalyst for 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, none
have been enacted. In October 2000, the Alabama PSC 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
Alabama PSC itself could not mandate retail competition or electric industry
restructuring without enabling state legislation. Electric utility restructuring
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 well as the August 2003 power outage in the Northeast.
Since 2001, merchant energy companies and traditional electric utilities
with significant energy marketing and trading activities have come 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 adverse financial impact regarding its limited energy trading
operations through SCS.
Continuing to be a low-cost producer could provide opportunities to
increase the size and profitability in markets that evolve with changing
regulation and competition. Conversely, future regulatory changes could
adversely affect the Company's growth, and 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.
Environmental Matters
New Source Review Actions
In November 1999, the Environmental Protection Agency (EPA) brought a civil
action against the Company alleging that the Company had violated the New Source
Review (NSR) 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 action against the Company has been stayed since the spring
of 2001 during the appeal of a very similar NSR action against the Tennessee
Valley Authority before the U.S. Court of Appeals for the Eleventh Circuit. The
Eleventh Circuit appeal was decided on September 16, 2003, and, on February 13,
2004, the EPA petitioned the U.S. Supreme Court to review the Eleventh Circuit's
decision. The EPA also filed a motion to lift the stay in the action against the
Company. See Note 3 to the financial statements under "New Source Review
Actions" for additional information.
In December 2002 and October 2003, the EPA issued final revisions to its
NSR regulations under the Clean Air Act. The December 2002 revisions included
changes to the regulatory exclusions and the methods of calculating emissions
increases. The October 2003 regulations clarified the scope of the existing
Routine Maintenance, Repair, and Replacement exclusion. A coalition of states
and environmental organizations filed petitions for review of these revisions
with the U.S. Court of Appeals for the District of Columbia Circuit. On December
24, 2003, the Court of Appeals granted a stay of the October 2003 revisions
II-71
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2003 Annual Report
pending its review of the rules and ordered that its review be conducted on an
expedited basis. In January 2004, the Bush Administration announced that it
would continue to enforce the existing rules until the courts resolve legal
challenges to the EPA's revised NSR regulations. In any event, the final
regulations must be adopted by the State of Alabama in order to apply to the
Company's facilities. The effect of these final regulations and the related
legal challenges cannot be determined 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 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 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
- -- both capital and operating -- a major portion of which is expected to be
recovered through existing ratemaking provisions. Environmental costs that are
known and estimable at this time are included in capital expenditures discussed
under "Capital Requirements and Contractual Obligations." 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. Title IV compliance,
effective in 2000, and associated construction expenditures totaled
approximately $88 million. Some of these expenditures 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 (SIP) for meeting the one-hour ozone standard. These
revisions required additional nitrogen oxide emission reductions from May
through September of each year at plants in and/or near those nonattainment
areas. Two plants in the Birmingham area are currently subject to those
requirements, the most recent of which went into effect in 2003. Construction
expenditures for compliance with the nitrogen oxide emission reduction
requirements are estimated to be approximately $249 million.
To help ozone nonattainment areas attain the one-hour ozone standard, the
EPA issued regional nitrogen oxide reduction rules in 1998. 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, must comply with the reduction
requirements by May 31, 2004. Additional construction expenditures for
compliance with these rules are currently estimated at approximately $361
million, of which $317 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
eight-hour ozone standard unlawful and remanded it to the EPA for further
rulemaking. During 2003, the EPA proposed implementation rules designed to
address the court's concerns. The EPA plans to designate areas as attainment or
nonattainment with the new eight-hour ozone standard in April 2004 and with the
new fine particulate matter standard by the end of 2004. These designations will
be based on air quality data for 2001 through 2003. Several areas within the
Company's service area are likely to be designated nonattainment under these
standards. SIPs, including new emission control regulations necessary to bring
those areas into attainment, could be required as early as 2007. These SIPs
could require reductions in sulfur dioxide emissions and 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 and
cannot be determined at this time.
II-72
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2003 Annual Report
In January 2004, the EPA issued a proposed Interstate Air Quality Rule to
address interstate transport of ozone and fine particles. This proposed rule
would require additional year-round sulfur dioxide and nitrogen oxide emission
reductions from power plants in the eastern United States in two phases - in
2010 and 2015. The EPA currently plans to finalize this rule by 2005. If
finalized, the rule could modify or supplant other SIP requirements for
attainment of the fine particulate matter standard and the eight-hour ozone
standard. The impact of this rule on the Company will depend upon the specific
requirements of the final rule and cannot be determined at this time.
Further reductions in sulfur dioxide and nitrogen oxides 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 SIPs in 2007. The SIPs must contain emission
reduction strategies for implementing BART and achieving progress toward the
Clean Air Act's 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.
The EPA has entered into an agreement that requires proposed revised rules in
April 2004 and final rules in 2005. Because new BART rules have not been
developed and state visibility assessments for progress 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. In 2004 and 2005, a number of
the Company's plants will likely become subject to CAM requirements for at least
one pollutant, in most cases particulate matter. The Company is in the process
of developing CAM plans. Because the plans are still under development, the
Company cannot determine the costs associated with implementation of the CAM
regulations. Actual ongoing monitoring costs are expensed as incurred and are
not material for any year presented.
In January 2004, the EPA issued proposed rules regulating mercury emissions
from electric utility boilers. The proposal solicits comments on two possible
approaches for the new regulations - a Maximum Achievable Control Technology
approach and a cap-and-trade approach. Either approach would require significant
reductions in mercury emissions from Company facilities. The regulations are
scheduled to be finalized by the end of 2004, and compliance could be required
as early as 2007. Because the regulations have not been finalized, the impact on
the Company cannot be determined at this time.
Several major bills to amend the Clean Air Act to impose more stringent
emissions limitations on power plants have been proposed by Congress. Three of
these, the Bush Administration's Clear Skies Act, the Clean Power Act of 2003,
and the Clean Air Planning Act of 2003, propose to further limit power plant
emissions of sulfur dioxide, nitrogen oxides, and mercury. The latter two bills
also propose to limit emissions of carbon dioxide. The cost impacts of such
legislation would depend upon the specific requirements enacted and cannot be
determined at this time.
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, known as Climate VISION, 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. The electric
utility sector has pledged to reduce its greenhouse gas intensity 3 percent to 5
percent over the next decade and is in the process of developing a memorandum of
understanding with the Department of Energy (DOE) to cover this voluntary
program.
The Company must comply with other environmental laws and regulations that
cover the handling and disposal of 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. Amounts for cleanup and ongoing monitoring costs
were not material for any new year presented. The Company may be liable for some
II-73
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2003 Annual Report
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 has been developing new rules aimed at
reducing impingement and entrainment of fish and fish larvae at power plants'
cooling water intake structures. On February 16, 2004, the EPA finalized these
rules. These rules will require biological studies and, perhaps, retrofits to
some intake structures at existing power plants. The impact of these new rules
will depend on the results of studies and analyses performed as part of the
rules' implementation.
In addition, under the Clean Water Act, the EPA and the ADEM are developing
total maximum daily loads (TMDLs) for certain impaired waters. Establishment of
maximum loads by the EPA or the 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 that
discharge 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.
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 or
regulations related to global climate change, electromagnetic fields, or other
environmental and health concerns could also significantly affect the Company.
The impact of any new legislation, changes to existing legislation, or
environmental regulations could affect many areas of the Company's operations.
The full impact of any such changes cannot, however, be determined at this time.
FERC Matters
Transmission
In December 1999, the Federal Energy Regulatory Commission (FERC) issued its
final rule (Order 2000) on Regional Transmission Organizations (RTOs). Order
2000 encouraged utilities owning transmission systems to form RTOs on a
voluntary basis. Through Southern Company, the Company worked with a number of
utilities in the Southeast to develop a for-profit RTO known as SeTrans. In
2002, the sponsors of SeTrans established a Stakeholder Advisory Committee to
provide input into the development of the RTO from other sectors of the electric
industry, as well as consumers. During the development of SeTrans, state
regulatory authorities expressed concern over certain aspects of the FERC's
policies regarding RTOs. In December 2003, the SeTrans sponsors announced that
they would suspend work on SeTrans because the regulated utility participants,
including Southern Company's retail operating companies, had determined that it
was highly unlikely to obtain support of both federal and state regulatory
authorities. Any impact of the FERC's rule on the Company will depend on the
regulatory reaction to the suspension of SeTrans and future developments, which
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 day ahead and spot energy markets;
and (7) revise the FERC policy on the pricing of transmission expansions.
Comments on the proposal were submitted by many interested parties, including
Southern Company and the Company, and the FERC has indicated that it has revised
certain aspects of the proposal in response to public comments. Proposed energy
legislation would prohibit the FERC from issuing the final rule before October
31, 2006, and from making any final rule effective before December 31, 2006.
That legislation has been approved by the House of Representatives but remains
pending before the Senate. Passage of the legislation now appears in doubt. It
is uncertain whether in the absence of legislation the FERC will move forward
II-74
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2003 Annual Report
with any part or all of the proposed rule. Any impact of this proposal on the
Company will depend on the form in which the final rule may be ultimately
adopted. However, the Company's financial statements could be adversely affected
by changes in the transmission regulatory structure in its regional power
market.
Hydro Relicensing
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.
Market-Based Rate Authority
The Company has obtained FERC approval to sell power to nonaffiliates at
market-based prices under specific contracts. Through SCS, as agent, the Company
also has FERC authority to make short-term opportunity sales at market rates.
Specific FERC approval must be obtained with respect to a market-based contract
with an affiliate. In November 2001, the FERC modified the test it uses to
consider utilities' applications to charge market-based rates and adopted a new
test called the Supply Margin Assessment (SMA). The FERC applied the SMA to
several utilities, including Southern Company's retail operating companies, and
found them to be "pivotal suppliers" in their service areas and ordered the
implementation of several mitigation measures. SCS, on behalf of the retail
operating companies, sought rehearing of the FERC order, and the FERC delayed
the implementation of certain mitigation measures. SCS, on behalf of the retail
operating companies, submitted comments to the FERC in 2002 regarding these
issues. In December 2003, the FERC issued a staff paper discussing alternatives
and held a technical conference in January 2004. The Company anticipates that
the FERC will address the requests for rehearing in the near future. Regardless
of the outcome of the SMA proposal, the FERC retains the ability to modify or
withdraw the authorization for any seller to sell at market-based rates, if it
determines that the underlying conditions for having such authority are no
longer applicable. The final outcome of this matter will depend on the form in
which the SMA test and mitigation measures rules may be ultimately adopted and
cannot be determined at this time.
Other Matters
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 $52 million, $56 million, and $57 million
in 2003, 2002, and 2001, respectively. Future pension income is dependent on
several factors including trust earnings and changes to the plan. The decline in
pension income is expected to continue and become an expense as early as 2011.
Postretirement benefit costs for the Company were $23 million, $23 million, and
$21 million in 2003, 2002, and 2001, respectively, 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. Pension income or
expense and postretirement benefit costs are a component of the regulated rates
and generally do not have a long-term effect on net income. For more information
regarding pension and postretirement benefits, see Note 2 to the financial
statements.
Prices for electricity provided by the Company to retail customers are set
by the Alabama PSC 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 range. Increases in retail rates
of 2 percent were effective in both April 2002 and October 2001 in accordance
with the Rate Stabilization Equalization plan.
The rates also provide for adjustments to recognize the placing of new
generating facilities into retail service and the recovery of retail costs
associated with certificated purchased power agreements (PPAs) 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. Effective July 2003,
the Company's retail rates were adjusted by approximately 2.6% under Rate CNP as
a result of two new certificated PPAs that began in June 2003. See Note 3 to the
financial statements under "Retail Rate Adjustment Procedures" for additional
information.
II-75
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2003 Annual Report
On December 8, 2003, President Bush signed into law the Medicare
Prescription Drug, Improvement and Modernization Act of 2003 (Medicare Act). The
Medicare Act introduces a prescription drug benefit for Medicare-eligible
retirees starting in 2006, as well as a federal subsidy to plan sponsors like
the Company that provide prescription drug benefits. In accordance with FASB
Staff Position No. 106-1, the Company has elected to defer recognizing the
effects of the Medicare Act for its postretirement plans under FASB Statement
No. 106, Employers' Accounting for Postretirement Benefits Other than Pension
until authoritative guidance on accounting for the federal subsidy is issued or
until a significant event occurs that would require remeasurement of the plans'
assets and obligations. The Company anticipates that the benefits it pays after
2006 will be lower as a result of the Medicare Act; however, the retiree medical
obligations and costs reported in Note 2 to the financial statements do not
reflect these changes. The final accounting guidance could require changes to
previously reported information.
Nuclear security legislation was recently introduced and considered in
Congress both as a free-standing bill in the Senate and as a part of
comprehensive energy legislation in a House-Senate Conference Report. Neither of
the proposals has been enacted. The Nuclear Regulatory Commission (NRC) also
ordered additional security measures for licensees in 2003. The Company is in
the process of implementation and must be in full compliance with these orders
by October 29, 2004. The requirements of the latest orders will have an impact
on the Company's Plant Farley and will result in increased operation and
maintenance expenses as well as additional capital expenditures. The precise
impact of the new requirements will depend upon the details of the
implementation of the new requirements, which have not been finalized.
The Company filed an application with the NRC in September 2003 to extend
the operating license for Plant Farley for an additional 20 years. If approved
by the NRC, the Company's depreciation and amortization expense could be reduced
pending approval by the Alabama PSC.
The Company is involved in various matters being litigated and regulatory
matters that could affect future earnings. See Note 3 to the financial
statements for information regarding material issues.
ACCOUNTING POLICIES
- -------------------
Application of Critical Accounting Policies and
Estimates
The Company prepares its financial statements in accordance with accounting
principles generally accepted in the United States. Significant accounting
policies are described in Note 1 to the financial statements. In the application
of these policies, certain estimates are made that may have a material impact on
the Company's results of operations and related disclosures. Different
assumptions and measurements could produce estimates that are significantly
different from those recorded in the financial statements. Senior management has
discussed the development and selection of the critical accounting policies and
estimates described below with the Controls and Compliance Committee of the
Company's Board of Directors and the Audit Committee of Southern Company's Board
of Directors.
Electric Utility Regulation
The Company is subject to retail regulation by the Alabama PSC and wholesale
regulation by the FERC. These regulatory agencies set the rates the Company is
permitted to charge customers based on allowable costs. As a result, the Company
applies FASB Statement No. 71, Accounting for the Effects of Certain Types of
Regulation. Through the ratemaking process, the regulators may require the
inclusion of costs or revenues in periods different than when they would be
recognized by a non-regulated company. This treatment may result in the deferral
of expenses and the recording of related regulatory assets based on anticipated
future recovery through rates or the deferral of gains or creation of
liabilities and the recording of related regulatory liabilities. The application
of Statement No. 71 has a further effect on the Company's financial statements
as a result of the estimates of allowable costs used in the ratemaking process.
These estimates may differ from those actually incurred by the Company;
therefore, the accounting estimates inherent in specific costs such as
depreciation, nuclear decommissioning, and pension and post-retirement benefits
have less of a direct impact on the Company's results of operations than they
would on a non-regulated company.
As reflected in Note 1 to the financial statements under "Regulatory Assets
and Liabilities," significant regulatory assets and liabilities have been
recorded. Management reviews the ultimate recoverability of these regulatory
II-76
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2003 Annual Report
assets and liabilities based on applicable regulatory guidelines. However,
adverse legislation and judicial or regulatory actions could materially impact
the amounts of such regulatory assets and liabilities and could adversely impact
the Company's financial statements.
Contingent Obligations
The Company is subject to a number of federal and state laws and regulations, as
well as other factors and conditions that potentially subject it to
environmental, litigation, income tax, and other risks. See "Future Earnings
Potential" and Note 3 to the financial statements for more information regarding
certain of these contingencies. The Company periodically evaluates its exposure
to such risks and records reserves for those matters where a loss is considered
probable and reasonably estimable in accordance with generally accepted
accounting principles. The adequacy of reserves can be significantly affected by
external events or conditions that can be unpredictable; thus, the ultimate
outcome of such matters could materially affect the Company's financial
statements. These events or conditions include the following:
o Changes in existing state or federal regulation by governmental authorities
having jurisdiction over air quality, water quality, control of toxic
substances, hazardous and solid wastes, and other environmental matters.
o Changes in existing income tax regulations or changes in Internal Revenue
Service interpretations of existing regulations.
o Identification of sites that require environmental remediation or the filing
of other complaints in which the Company may be asserted to be a potentially
responsible party.
o Identification and evaluation of other potential lawsuits or complaints in
which the Company may be named as a defendant.
o Resolution or progression of existing matters through the legislative
process, the court systems, or the EPA.
New Accounting Standards
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
established 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 of an asset's future retirement is recorded in the
period in which the liability is incurred. The costs are capitalized as part of
the related long-lived asset and depreciated over the asset's useful life.
Additionally, non-regulated companies are no longer permitted 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 "Asset Retirement Obligations and Other Costs of Removal."
FASB Statement No. 149, Amendment of Statement 133 on Derivative
Instruments and Hedging Activities, which further amends and clarifies the
accounting and reporting for derivative instruments, became effective generally
for financial instruments entered into or modified after June 30, 2003. Current
interpretations of Statement No. 149 indicate that certain electricity forward
transactions subject to unplanned netting -- including those typically referred
to as "book outs" -- may only qualify as cash flow hedges if an entity can
demonstrate that physical delivery or receipt of power occurred. The Company's
forward electricity contracts continue to be exempt from fair value accounting
requirements or to qualify as cash flow hedges, with the related gains and
losses deferred in other comprehensive income. The implementation of Statement
No. 149 did not have a material effect on the Company's financial statements.
In July 2003, the Emerging Issues Task Force (EITF) of FASB issued EITF No.
03-11, which became effective on October 1, 2003. The standard addresses the
reporting of realized gains and losses on derivative instruments and is being
interpreted to require book outs to be recorded on a net basis in operating
revenues. Adoption of this standard did not have a material impact on the
Company's financial statements.
FASB Interpretation No. 46, Consolidation of Variable Interest Entities,
which was originally issued in January 2003, requires the primary beneficiary of
a variable interest entity to consolidate the related assets and liabilities. In
December 2003, the FASB revised Interpretation No. 46 and deferred the effective
date until March 31, 2004 for interests held in variable interest entities other
than special purpose entities.
Current analysis indicates that the trusts established by the Company to
issue preferred securities are variable interest entities under Interpretation
No. 46, and that the Company is not the primary beneficiary of these trusts. If
II-77
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2003 Annual Report
this conclusion is finalized, effective March 31, 2004, the trust assets and
liabilities -- including the preferred securities issued by the trusts -- will
be deconsolidated. The investments in the trusts and the loans from the trusts
to the Company will be reflected as equity method investments and as long-term
notes payable to affiliates, respectively, on the Balance Sheets. Based on
December 31, 2003 values, this treatment would result in an increase of
approximately $9 million to both total assets and total liabilities. See Note 6
to the financial statements under "Mandatorily Redeemable Preferred Securities"
for additional information.
In May 2003, the FASB issued Statement No. 150, Accounting for Certain
Financial Instruments with Characteristics of Both Liabilities and Equity, which
requires classification of certain financial instruments within its scope,
including shares that are mandatorily redeemable, as liabilities. Statement No.
150 was effective for financial instruments entered into or modified after May
31, 2003, and otherwise on July 1, 2003. In accordance with Statement No. 150,
mandatorily redeemable preferred securities are reflected in the Balance Sheets
as liabilities. The adoption of Statement No. 150 had no impact on the
Statements of Income and Cash Flows.
FINANCIAL CONDITION AND LIQUIDITY
- ---------------------------------
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 operated at high
levels of reliability while achieving industry-leading customer satisfaction
levels and continuing to have retail prices below the national average.
The Company had gross property additions of $649 million in 2003. The
majority of funds needed for gross property additions for the last several years
have been provided from operating activities. The Statements of Cash Flows
provide additional details.
The Company's ratio of common equity to total capitalization -- including
short-term debt -- was 43.3 percent in 2003, 42.6 percent in 2002, and 42.8
percent in 2001. See Note 6 to the financial statements for additional
information.
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 operating cash flows. 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 preferred
securities.
The Company obtains financing separately without credit support from any
affiliate. The Southern Company system does not maintain a centralized cash or
money pool. Therefore, funds of the Company are not commingled with funds of any
other company. In accordance with the Public Utility Holding Company Act, most
loans between affiliated companies must be approved in advance by the Securities
and Exchange Commission (SEC).
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 2004.
To meet short-term cash needs and contingencies, the Company has various
internal and external sources of liquidity. At the beginning of 2004, the
Company had approximately $43 million of cash and cash equivalents and $865
million of unused credit arrangements with banks, as shown in the following
table. In addition, the Company has substantial cash flow from operating
activities and access to the capital markets, including commercial paper
programs, to meet liquidity needs. Cash flows from operating activities were
$1,118 million in 2003, $973 million in 2002, and $843 million in 2001.
At the beginning of 2004, bank credit arrangements are as follows:
Expires
----------------------------------
2005
Total Unused 2004 & Beyond
- ------------------------------------------------------------------
(in millions)
$865 $865 $865 -
- -----------------------------------------------------------------
Approximately $450 million of the credit facilities expiring in 2004 allow
for the execution of term loans for an additional two-year period and $245
million allow for the execution for a one-year period. See Note 6 to the
II-78
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2003 Annual Report
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 retail operating companies. Proceeds from such issuances for
the benefit of the Company are loaned directly to the Company and are not
commingled with proceeds from such issuances for the benefit of any other
operating company. The obligations of each company under these arrangements are
several; there is no cross affiliate credit support. At December 31, 2003, the
Company had no commercial paper outstanding.
Financing Activities
In 2003, the Company's financing costs decreased due to lower interest rates
despite the issuance of an increased amount of senior securities during the
year. New issues during 2001 through 2003 totaled $3.3 billion and retirement or
repayment of higher-cost securities totaled $2.8 billion.
Composite financing rates for long-term debt, preferred stock, and
preferred securities for the years 2001 through 2003, as of year-end, were as
follows:
2003 2002 2001
- ----------------------------------------------------------------
Long-term debt interest
rate 4.42% 5.05% 5.72%
Preferred securities
distribution rate 5.25 5.25 6.96
Preferred stock dividend
rate 5.10 5.17 4.79
- ----------------------------------------------------------------
Subsequent to December 31, 2003, the Company has entered into interest rate
hedging transactions related to the anticipated refinancing of $470 million of
securities due within one year. Also, an additional $300 million of securities
have been issued for other general corporate purposes including repayment of
outstanding short-term indebtedness and the funding of the Company's continuous
construction program.
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
purchases and sales, fixed-price physical gas purchases, and agreements covering
interest rate swaps. At December 31, 2003, the maximum potential collateral
requirements under the electricity purchase and sale contracts were
approximately $26.7 million. Generally, collateral may be provided for by a
Company guaranty, a letter of credit, or cash. At December 31, 2003, there were
no material collateral requirements for the gas purchase contracts or other
financial instrument agreements.
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.
Derivative positions are monitored using techniques that include market
valuation and sensitivity analysis.
To mitigate exposure to interest rates, the Company has entered into
interest rate swaps that have been designated as hedges. The weighted average
interest rate on outstanding variable long-term debt, that has not been hedged
at December 31, 2003 was 1.38 percent. If the Company sustained a 100 basis
point change in interest rates for all unhedged variable rate long-term debt,
the change would affect annualized interest expense by approximately $0.5
million at December 31, 2003. 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 6 to the financial statements under
"Financial Instruments."
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,
into similar contracts for gas purchases.
In addition, in October 2001, the Alabama PSC 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
II-79
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2003 Annual Report
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, 2003, 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:
Changes in Fair Value
- ---------------------------------------------------------------
2003 2002
- ---------------------------------------------------------------
(in thousands)
Contracts beginning of year $ 21,402 $ 214
Contracts realized or settled (38,809) (21,088)
New contracts at inception - -
Changes in valuation techniques - -
Current period changes 23,820 42,276
- --------------------------------------------------------------
Contracts end of year $ 6,413 $ 21,402
==============================================================
Source of 2003 Year-End
Valuation Prices
----------------------------------
Maturity
Total -------------------------
Fair Value 2004 2005-2006
- --------------------------------------------------------------
(in thousands)
- --------------------------------------------------------------
Actively quoted $6,413 $7,803 $ (1,390)
External sources - - -
Models and other
methods - - -
- --------------------------------------------------------------
Contracts end of Year $6,413 $7,803 $ (1,390)
==============================================================
Unrealized gains and losses from mark to market adjustments on derivative
contracts related to the Company's 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 derivative contracts that are not
designated as hedges are recognized in the income statement as incurred. At
December 31, 2003, the fair value of derivative energy contracts was reflected
in the financial statements as follows:
Amounts
---------------------------------------------------------
(in
thousands)
Regulatory liabilities, net $6,402
Net income 11
----------------------------------------------------------
Total fair value $6,413
==========================================================
Unrealized pre-tax gains (losses) on energy contracts of $(0.1) million,
$(2.0) million, and $2.0 million were recognized in income in 2003, 2002, and
2001, respectively. The Company is exposed to market price risk in the event of
nonperformance by counterparties 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 6 to the financial statements under "Financial Instruments."
Capital Requirements and Contractual Obligations
The construction program of the Company is currently estimated to be $791
million for 2004, $863 million for 2005, and $884 million for 2006. Over the
next three years, the Company estimates spending $713 million on environmental
related additions (including $358 million on Selective Catalytic Reduction
facilities), $267 million on Plant Farley (including $155 million for nuclear
fuel, $29 million on cooling towers and $26 million on replacing reactor vessel
heads), $701 million on distribution facilities, and $402 million on
transmission additions. See Note 7 to the financial statements under
"Construction Program" for additional details.
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.
In addition to the funds required for the Company's construction program,
approximately $1.5 billion will be required by the end of 2006 for maturities of
long-term debt. The Company plans to continue, when economically feasible, to
retire higher cost debt, preferred securities, and preferred stock and replace
these obligations with lower-cost capital if market conditions permit.
As a result of requirements by the NRC, 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
II-80
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2003 Annual Report
approved by the Alabama PSC. The amount expensed in 2003 was $18 million. For
additional information, see Note 1 to the financial statements under "Nuclear
Decommissioning." Additionally, as discussed in Note 1 to the financial
statements under "Revenues and Fuel Costs," in 1993, the DOE implemented a
special assessment over a 15-year period on utilities with nuclear plants to be
used for the decontamination and decommissioning of its nuclear fuel enrichment
facilities.
In 1994, the Company also established an external trust fund for
postretirement benefits as ordered by the Alabama PSC. 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."
The capital requirements, lease obligations, purchase commitments, and
trust requirements - discussed above and in the financial statements - are
summarized as follows: (See Notes 1, 6, and 7 to the financial statements for
additional information.)
2005- 2007- After
2004 2006 2008 2008 Total
- ------------------------------------------------------------------------------------------------------------------------------
(in millions)
Long-term debt and preferred securities(a) --
Principal $ 526.0 $ 940.5 $ 610.0 $2,135.1 $ 4,211.6
Interest and distributions 188.8 302.5 241.9 2,048.0 2,781.2
Preferred stock dividends(b) 19.0 38.0 38.0 - 95.0
Operating leases 29.7 42.7 13.5 35.2 121.1
Purchase commitments(c) --
Capital(d) 778.0 1,729.1 - - 2,507.1
Coal and nuclear fuel 750.4 951.0 582.7 - 2,284.1
Natural gas(e) 318.3 338.5 133.1 107.7 897.6
Purchased power 85.0 175.0 178.0 129.0 567.0
Long-term service agreements 18.3 17.8 57.6 119.2 212.9
Trusts --
Nuclear decommissioning 20.3 40.6 40.6 222.5 324.0
Postretirement benefits(f) 4.2 48.5 - - 52.7
DOE assessments 4.4 8.7 - - 13.1
- ------------------------------------------------------------------------------------------------------------------------------
Total $2,742.4 $4,632.9 $1,895.4 $4,796.7 $14,067.4
==============================================================================================================================
(a) All amounts are reflected based on final maturity dates. The Company will continue to retire higher-cost securities and
replace these obligations with lower-cost capital if market conditions permit. Variable rate interest obligations are
estimated based on rates as of January 1, 2004, as reflected in the Statements of Capitalization.
(b) Preferred stock does not mature; therefore, amounts are provided for the next five years only.
(c) The Company generally does not enter into non-cancelable commitments for other operation and maintenance expenditures. Total
other operation and maintenance expenses for the last three years were $921 million, $854 million, and $784 million,
respectively.
(d) The Company forecasts capital expenditures over a three-year period. Amounts represent current estimates of total
expenditures excluding those amounts related to contractual purchase commitments for uranium and nuclear fuel conversion,
enrichment, and fabrication services. At December 31, 2003, significant purchase commitments were outstanding in
connection with the construction program.
(e) Natural gas purchase commitments are based on various indices at the time of delivery. Amounts reflected have been estimated
based on the New York Mercantile future prices at December 31, 2003.
(f) The Company forecasts post-retirement trust contributions over a three-year period. No contributions related to the
Company's pension trust are currently expected during this period. See Note 2 to the financial statements for additional
information related to the pension plan.
II-81
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2003 Annual Report
Cautionary Statement Regarding Forward-Looking Information
The Company's 2003 Annual Report includes forward-looking statements in addition
to historical information. Forward-looking information includes, among other
things, statements concerning the Company's estimated construction and other
expenditures, and the Company's projections for energy sales and its goals for
future generating capacity 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. 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:
o 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, tax, and other laws and regulations to which the Company is
subject, as well as changes in application of existing laws and regulations;
o current and future litigation, regulatory investigations, proceedings or
inquiries, including the pending EPA civil action against the Company;
o the effects, extent, and timing of the entry of additional competition in the
markets in which the Company operates;
o the impact of fluctuations in commodity prices, interest rates, and
customer demand;
o available sources and costs of fuels;
o ability to control costs;
o investment performance of the Company's employee benefit plans;
o advances in technology;
o state and federal rate regulations and pending and future rate cases and
negotiations;
o effects of and changes in political, legal, and economic conditions and
developments in the United States, including the current soft economy;
o internal restructuring or other restructuring options that may be pursued;
o potential business strategies, including acquisitions or dispositions of
assets, which cannot be assured to be completed or beneficial to the Company;
o the ability of counterparties of the Company to make payments as and when due;
o the ability to obtain new short- and long-term contracts with neighboring
utilities;
o the direct or indirect effects on the Company's business resulting from the
terrorist incidents on September 11, 2001, or any similar incidents or
responses to such incidents;
o financial market conditions and the results of financing efforts, including
the Company's credit ratings;
o the ability of the Company to obtain additional generating capacity at
competitive prices;
o weather and other natural phenomena;
o the direct or indirect effects on the Company's business
resulting from the August 2003 power outage in the Northeast, or any similar
incidents;
o the effect of accounting pronouncements issued periodically by
standard-setting bodies; and
o other factors discussed elsewhere herein and in
other reports (including the Form 10-K) filed from time to time by the
Company with the SEC.
II-82
STATEMENTS OF INCOME
For the Years Ended December 31, 2003, 2002, and 2001
Alabama Power Company 2003 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------------
2003 2002 2001
- -----------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Revenues:
Retail sales $3,051,463 $2,951,217 $2,747,673
Sales for resale --
Non-affiliates 487,456 474,291 485,974
Affiliates 277,287 188,163 245,189
Other revenues 143,955 96,862 107,554
- -----------------------------------------------------------------------------------------------------------------------------------
Total operating revenues 3,960,161 3,710,533 3,586,390
- -----------------------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Fuel 1,067,821 969,521 1,000,828
Purchased power --
Non-affiliates 110,885 90,998 144,991
Affiliates 204,353 158,121 147,967
Other operations 611,418 574,979 508,264
Maintenance 309,451 279,406 275,510
Depreciation and amortization 412,919 398,428 383,473
Taxes other than income taxes 228,414 216,919 214,665
- -----------------------------------------------------------------------------------------------------------------------------------
Total operating expenses 2,945,261 2,688,372 2,675,698
- -----------------------------------------------------------------------------------------------------------------------------------
Operating Income 1,014,900 1,022,161 910,692
Other Income and (Expense):
Allowance for equity funds used during construction 12,594 11,168 7,092
Interest income 15,220 13,991 15,101
Interest expense, net of amounts capitalized (214,302) (225,706) (246,436)
Distributions on mandatorily redeemable preferred securities (15,255) (24,599) (24,775)
Other income (expense), net (31,702) (28,785) (11,177)
- -----------------------------------------------------------------------------------------------------------------------------------
Total other income and (expense) (233,445) (253,931) (260,195)
- -----------------------------------------------------------------------------------------------------------------------------------
Earnings Before Income Taxes 781,455 768,230 650,497
Income taxes 290,378 292,436 248,597
- -----------------------------------------------------------------------------------------------------------------------------------
Earnings Before Cumulative Effect of 491,077 475,794 401,900
Accounting Change
Cumulative effect of accounting change--
less income taxes of $215 thousand - - 353
- -----------------------------------------------------------------------------------------------------------------------------------
Net Income 491,077 475,794 402,253
Dividends on Preferred Stock 18,267 14,439 15,524
- -----------------------------------------------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred Stock $ 472,810 $ 461,355 $ 386,729
===================================================================================================================================
The accompanying notes are an integral part of these financial statements.
II-83
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2003, 2002, and 2001
Alabama Power Company 2003 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------
2003 2002 2001
- -----------------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Activities:
Net income $491,077 $475,794 $402,253
Adjustments to reconcile net income
to net cash provided from operating activities --
Depreciation and amortization 467,085 442,660 437,490
Deferred income taxes and investment tax credits, net 153,154 48,828 (21,569)
Deferred capacity revenues (9,589) (8,099) -
Pension, postretirement, and other employee benefits (32,029) (34,977) (58,118)
Tax benefit of stock options 8,680 6,670 -
Settlement of interest rate hedges (7,957) - -
Other, net 11,393 4,663 (64,533)
Changes in certain current assets and liabilities --
Receivables, net 7,134 (50,423) 88,325
Fossil fuel stock (13,251) 25,535 (38,663)
Materials and supplies (4,651) 3,728 (13,025)
Other current assets (953) 1,479 (15,474)
Accounts payable 50,928 1,068 (83,077)
Accrued taxes (33,507) (40,922) 46,187
Energy cost recovery, retail 1,195 84,429 154,320
Other current liabilities 29,385 12,730 3,790
- -----------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities 1,118,094 973,163 837,906
- -----------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (648,560) (634,094) (635,540)
Cost of removal net of salvage (35,440) (32,111) (37,304)
Sales of property - - 102,068
Other (13,763) (6,151) 2,533
- -----------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities (697,763) (672,356) (568,243)
- -----------------------------------------------------------------------------------------------------------------------------
Financing Activities:
Increase (decrease) in notes payable, net (36,991) 26,994 (271,347)
Proceeds --
Pollution control bonds - - 35,000
Senior notes 1,415,000 975,000 442,000
Mandatorily redeemable preferred securities - 300,000 -
Preferred stock 125,000 - -
Common stock 50,000 - 15,642
Capital contributions from parent company 17,826 43,118 107,313
Redemptions --
First mortgage bonds - (350,000) (138,991)
Pollution control bonds - - (15,000)
Senior notes (1,507,000) (415,602) (3,179)
Other long-term debt (943) (883) (842)
Mandatorily redeemable preferred securities - (347,000) -
Preferred stock - (70,000) -
Payment of preferred stock dividends (18,181) (14,176) (14,942)
Payment of common stock dividends (430,200) (431,000) (393,900)
Other (14,775) (30,329) (9,908)
- -----------------------------------------------------------------------------------------------------------------------------
Net cash used for financing activities (400,264) (313,878) (248,154)
- -----------------------------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents 20,067 (13,071) 21,509
Cash and Cash Equivalents at Beginning of Period 22,685 35,756 14,247
- -----------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ 42,752 $ 22,685 $ 35,756
=============================================================================================================================
Supplemental Cash Flow Information:
Cash paid during the period for --
Interest (net of $6,367, $6,738, and $11,690 capitalized,
respectively) $185,272 $230,102 $246,316
Income taxes (net of refunds) 161,004 269,043 223,961
- -------------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
II-84
BALANCE SHEETS
At December 31, 2003 and 2002
Alabama Power Company 2003 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------------
Assets 2003 2002
- -----------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Current Assets:
Cash and cash equivalents $ 42,752 $ 22,685
Receivables --
Customer accounts receivable 240,562 240,052
Unbilled revenues 95,953 89,336
Other accounts and notes receivable 53,547 47,535
Affiliated companies 48,876 74,099
Accumulated provision for uncollectible accounts (4,756) (4,827)
Fossil fuel stock, at average cost 86,993 73,742
Vacation pay 35,530 33,901
Materials and supplies, at average cost 211,690 207,872
Prepaid expenses 44,608 40,411
Other 19,454 27,210
- -----------------------------------------------------------------------------------------------------------------------------------
Total current assets 875,209 852,016
- -----------------------------------------------------------------------------------------------------------------------------------
Property, Plant, and Equipment:
In service 14,224,117 13,506,170
Less accumulated provision for depreciation 4,905,920 4,658,803
- -----------------------------------------------------------------------------------------------------------------------------------
9,318,197 8,847,367
Nuclear fuel, at amortized cost 93,611 103,088
Construction work in progress 321,316 458,375
- -----------------------------------------------------------------------------------------------------------------------------------
Total property, plant, and equipment 9,733,124 9,408,830
- -----------------------------------------------------------------------------------------------------------------------------------
Other Property and Investments:
Equity investments in unconsolidated subsidiaries 47,811 45,553
Nuclear decommissioning trusts, at fair value 384,574 292,297
Other 16,992 16,477
- -----------------------------------------------------------------------------------------------------------------------------------
Total other property and investments 449,377 354,327
- -----------------------------------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets:
Deferred charges related to income taxes 321,077 327,276
Prepaid pension costs 446,256 389,793
Unamortized loss on reacquired debt 110,946 103,819
Department of Energy assessments 13,092 17,144
Other 121,543 138,461
- -----------------------------------------------------------------------------------------------------------------------------------
Total deferred charges and other assets 1,012,914 976,493
- -----------------------------------------------------------------------------------------------------------------------------------
Total Assets $12,070,624 $11,591,666
===================================================================================================================================
The accompanying notes are an integral part of these financial statements.
II-85
BALANCE SHEETS
At December 31, 2003 and 2002
Alabama Power Company 2003 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------------
Liabilities and Stockholder's Equity 2003 2002
- -----------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Current Liabilities:
Securities due within one year $ 526,019 $ 1,117,945
Notes payable - 36,991
Accounts payable --
Affiliated 135,017 109,790
Other 162,314 141,251
Customer deposits 47,507 44,410
Accrued taxes --
Income taxes 83,544 80,438
Other 22,273 20,561
Accrued interest 46,489 36,344
Accrued vacation pay 35,530 33,901
Accrued compensation 75,620 74,099
Other 34,513 49,715
- -----------------------------------------------------------------------------------------------------------------------------------
Total current liabilities 1,168,826 1,745,445
- -----------------------------------------------------------------------------------------------------------------------------------
Long-term debt (See accompanying statements) 3,377,148 2,872,609
- -----------------------------------------------------------------------------------------------------------------------------------
Mandatorily redeemable preferred securities (See accompanying statements) 300,000 300,000
- -----------------------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 1,571,076 1,436,559
Deferred credits related to income taxes 162,168 177,205
Accumulated deferred investment tax credits 216,309 227,270
Employee benefit obligations 180,960 156,526
Deferred capacity revenues 36,567 46,155
Asset retirement obligations 358,759 -
Asset retirement obligation regulatory liability 127,346 -
Other cost of removal obligations 574,445 884,613
Miscellaneous regulatory liabilities 86,323 79,545
Other 37,525 40,487
- -----------------------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 3,351,478 3,048,360
- -----------------------------------------------------------------------------------------------------------------------------------
Total liabilities 8,197,452 7,966,414
- -----------------------------------------------------------------------------------------------------------------------------------
Cumulative preferred stock (See accompanying statements) 372,512 247,512
- -----------------------------------------------------------------------------------------------------------------------------------
Common stockholder's equity (See accompanying statements) 3,500,660 3,377,740
- -----------------------------------------------------------------------------------------------------------------------------------
Total Liabilities and Stockholder's Equity $12,070,624 $11,591,666
===================================================================================================================================
Commitments and Contingent Matters (See notes)
- -----------------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
II-86
STATEMENTS OF CAPITALIZATION
At December 31, 2003 and 2002
Alabama Power Company 2003 Annual Report
- -------------------------------------------------------------------------------------------------------------------------------
2003 2002 2003 2002
- -------------------------------------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
Long-Term Debt:
Long-term notes payable --
Variable rate (1.525% at 1/1/03)
due 2003 $ - $ 517,000
5.35% to 7.85% due 2003 - 406,200
4.875% to 7.125% due 2004 525,000 525,000
5.49% due November 1, 2005 225,000 225,000
2.65% to 2.80% due 2006 520,000 -
Floating rate (1.37% at 1/1/04)
due 2006 195,000 -
7.125% due October 1, 2007 200,000 200,000
3.125% to 5.375% due 2008 410,000 160,000
4.70% to 6.75% due 2010-2039 1,275,000 1,408,800
- -------------------------------------------------------------------------------------------------------------------------------
Total long-term notes payable 3,350,000 3,442,000
- -------------------------------------------------------------------------------------------------------------------------------
Other long-term debt --
Pollution control revenue bonds --
Collateralized:
5.50% due 2024 24,400 24,400
Variable rates (1.27% to 1.33% at 1/1/04)
due 2015-2017 89,800 89,800
Non-collateralized:
Variable rates (1.23% to 1.45% at 1/1/04)
due 2021-2031 445,940 445,940
- -------------------------------------------------------------------------------------------------------------------------------
Total other long-term debt 560,140 560,140
- -------------------------------------------------------------------------------------------------------------------------------
Capitalized lease obligations 1,497 2,439
- -------------------------------------------------------------------------------------------------------------------------------
Unamortized debt premium (discount), net (8,470) (14,025)
- -------------------------------------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
requirement -- $173.0 million) 3,903,167 3,990,554
Less amount due within one year 526,019 1,117,945
- -------------------------------------------------------------------------------------------------------------------------------
Long-term debt excluding amount due within one year $3,377,148 $2,872,609 44.7% 42.3%
- -------------------------------------------------------------------------------------------------------------------------------
II-87
STATEMENTS OF CAPITALIZATION (continued)
At December 31, 2003 and 2002
Alabama Power Company 2003 Annual Report
- --------------------------------------------------------------------------------------------------------------------------------
2003 2002 2003 2002
- --------------------------------------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
Mandatorily Redeemable Preferred Securities:
$1,000 liquidation value due 2042 --
4.75% through 2007* $ 100,000 $ 100,000
5.50% through 2009* 200,000 200,000
- --------------------------------------------------------------------------------------------------------------------------------
Total (annual distribution requirement -- $15.8 million) 300,000 300,000 4.0 4.4
- --------------------------------------------------------------------------------------------------------------------------------
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
$100,000 stated value --
4.95% 125,000 -
- --------------------------------------------------------------------------------------------------------------------------------
Total (annual dividend requirement -- $19.0 million) 372,512 247,512 4.9 3.6
- --------------------------------------------------------------------------------------------------------------------------------
Common Stockholder's Equity:
Common stock, par value $40 per share --
Authorized - 15,000,000 shares in 2003
and 6,000,000 shares in 2002
Outstanding - 7,250,000 shares in 2003
and 6,000,000 shares in 2002
Par value 290,000 240,000
Paid-in capital 1,926,970 1,900,464
Premium on Preferred Stock 99 99
Retained earnings 1,291,558 1,250,594
Accumulated other comprehensive income (loss) (7,967) (13,417)
- ---------------------------------------------------------------------------------------------------------------------------------
Total common stockholder's equity 3,500,660 3,377,740 46.4 49.7
- ---------------------------------------------------------------------------------------------------------------------------------
Total Capitalization $7,550,320 $6,797,861 100.0% 100.0%
=================================================================================================================================
*The fixed rates thereafter are 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.
The accompanying notes are an integral part of these financial statements.
II-88
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
For the Years Ended December 31, 2003, 2002, and 2001
Alabama Power Company 2003 Annual Report
- -------------------------------------------------------------------------------------------------------------------------------
Premium on Other
Common Paid-In Preferred Retained Comprehensive
Stock Capital Stock Earnings Income (loss) Total
- -----------------------------------------------------------------------------------------------------------------------------
(in thousands)
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
Issuance of common stock 15,642 - - - - 15,642
Capital contributions from parent company - 107,313 - - - 107,313
Cash dividends on common stock - - - (393,900) - (393,900)
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
Net income after dividends on preferred stock - - - 472,810 - 472,810
Issuance of common stock 50,000 - - - - 50,000
Capital contributions from parent company - 26,506 - - - 26,506
Other comprehensive income (loss) - - - - 5,450 5,450
Cash dividends on common stock - - - (430,200) - (430,200)
Other - - - (1,646) - (1,646)
- -----------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2003 $290,000 $1,926,970 $99 $1,291,558 $ (7,967) $3,500,660
=============================================================================================================================
The accompanying notes are an integral part of these financial statements.
STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2003, 2002, and 2001
Alabama Power Company 2003 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------------
2003 2002 2001
- ----------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Net income after dividends on preferred stock $472,810 $461,355 $386,729
- ----------------------------------------------------------------------------------------------------------------------------------
Other comprehensive income (loss):
Change in additional minimum pension liability, net of tax of (3,785) (4,172) -
$(2,301) and $(2,536), respectively
Changes in fair value of qualifying hedges, net of tax of 2,188 (10,576) -
$1,330 and $(6,430), respectively
Less: Reclassification adjustment for amounts included in 7,047 1,331 -
net income, net of tax of $4,285 and $810, respectively
- ----------------------------------------------------------------------------------------------------------------------------------
Total other comprehensive income (loss) 5,450 (13,417) -
- ----------------------------------------------------------------------------------------------------------------------------------
Comprehensive Income $478,260 $447,938 $386,729
==================================================================================================================================
The accompanying notes are an integral part of these financial statements.
II-89
NOTES TO FINANCIAL STATEMENTS
Alabama Power Company 2003 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 retail operating companies,
Southern Power Company (Southern Power), Southern Company Services (SCS),
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 retail operating companies -- the Company, Georgia
Power Company, Gulf Power Company, Mississippi Power Company, and Savannah
Electric and Power Company -- provide electric service in four Southeastern
states. The Company 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.
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 retail 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 -- 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 retail 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 is a competitive retail natural gas marketer serving customers in
Georgia. Southern Holdings is an intermediate holding subsidiary for Southern
Company's investments in synthetic fuels and leveraged leases and an energy
services business. Southern Nuclear operates and provides services to Southern
Company's nuclear power plants, including the Company's Plant Farley.
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 (Alabama PSC). The Company follows accounting principles generally
accepted in the United States and complies with the accounting policies and
practices prescribed by its 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 $218 million, $218 million, and $183 million during 2003,
2002, and 2001, respectively. 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 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,
employee relations, and other services with respect to business and operations.
Costs for these services amounted to $153 million, $154 million, and $160
million during 2003, 2002, and 2001, 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 $6.7 million in 2003, $6.4 million in 2002, and $5.5
million in 2001. See Note 4 for additional information.
Southern Company holds a 30 percent ownership interest in Alabama Fuel
Products, LLC (AFP), which produces synthetic fuel. The Company has an agreement
with an indirect subsidiary of Southern Company that provides services for AFP.
Under this agreement, the Company provides certain accounting functions,
including processing and paying fuel transportation invoices, and the Company is
II-90
NOTES (continued)
Alabama Power Company 2003 Annual Report
reimbursed for its expenses. Amounts billed under this agreement totaled
approximately $27.5 million and $34.5 million in 2003 and 2002, respectively. In
addition, the Company purchases synthetic fuel from AFP for use at several of
the Company's plants. Fuel purchases for 2003 and 2002 totaled $209.2 million
and $211.0 million, respectively.
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. Upon the plant becoming operational in June
2003, the Company entered into an agreement with Southern Power to operate and
maintain Plant Harris at cost and provide fuel at cost. In 2003, the Company
billed Southern Power $0.8 million for operation and maintenance. Purchased
power costs from Plant Harris in 2003 totaled $75.6 million. Additionally, the
Company recorded $8.3 million of prepaid capacity expenses included in Other
Deferred Charges and Other Assets on the Balance Sheets at December 31, 2003.
See Note 3 under "Retail Rate Adjustment Procedures" and Note 7 under "Purchased
Power Commitments" for additional information.
Also, see Note 4 for information regarding the Company's ownership in and
purchased power agreement with Southern Electric Generating Company (SEGCO).
The retail operating companies, including the Company, Southern Power, and
Southern Company GAS, 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.
Revenues and Fuel Costs
Capacity revenues are generally recognized on a levelized basis over the
appropriate contract periods. Energy and 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
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 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 $64
million in 2003, $63 million in 2002, and $58 million in 2001. 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 pool storage capacity for spent fuel is available at Plant Farley to
maintain full-core discharge capability until the refueling outage scheduled in
2006 for Plant Farley Unit 1 and the refueling outage scheduled in 2008 for
Plant Farley Unit 2. Procurement of on-site dry spent fuel storage capacity at
Plant Farley is in progress and scheduled for operation in 2005. See Note 7
under "Construction Program" for additional information.
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 $13 million at December 31, 2003.
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.
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
II-91
NOTES (continued)
Alabama Power Company 2003 Annual Report
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:
2003 2002 Note
--------------- ----
(in millions)
Deferred income tax charges $ 321 $ 327 (a)
Loss on reacquired debt 111 104 (b)
DOE assessments 13 17 (c)
Vacation pay 36 34 (d)
Rate CNP under recovery 17 - (e)
Other assets 13 17 (e)
Asset retirement obligations (127) - (a)
Other cost of removal obligations (574) (885) (a)
Deferred income tax credits (162) (177) (a)
Natural disaster reserve (13) (12) (e)
Nuclear outage (14) (10) (e)
Deferred purchased power (15) - (e)
Other liabilities (5) (2) (e)
Fuel-hedging liabilities (6) (21) (f)
Mine reclamation & remediation (33) (35) (g)
- ------------------------------------------------------
Total $(438) $(643)
======================================================
Note: The recovery and amortization periods for these regulatory assets and
(liabilities) are as follows:
(a) Asset retirement and removal liabilities are recorded, deferred income
tax assets are recovered, and deferred tax liabilities are amortized over
the related property lives, which may range up to 50 years. Asset
retirement and removal liabilities will be settled and trued up following
completion of the related activities.
(b) Recovered over the remaining life of the original issue which may range
up to 40 years.
(c) Assessments for the decontamination and decommissioning of the DOE
nuclear fuel enrichment facilities are recorded annually from 1993
through 2008.
(d) Recorded as earned by employees and recovered as paid, generally within
one year.
(e) Recorded and recovered or amortized as approved by the Alabama PSC.
(f) Fuel-hedging assets and liabilities are recorded over the life of the
underlying hedged purchase contracts, which generally do not exceed two
years. Upon final settlement, actual costs incurred are recovered through
the fuel cost recovery clauses.
(g) Recovered from customers to settle future costs.
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.
Depreciation and Amortization
Depreciation of the original cost of depreciable utility plant in service is
provided primarily by using composite straight-line rates, which approximated
3.1 percent in 2003 and 3.2 percent in each of 2002 and 2001. 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.
Asset Retirement Obligations
and Other Costs of Removal
In accordance with regulatory requirements, prior to January 2003, the Company
followed the industry practice of accruing for the ultimate costs of retiring
most long-lived assets over the life of the related asset as part of the annual
depreciation expense provision. In accordance with SEC requirements, such
amounts are reflected on the Balance Sheet as regulatory liabilities. Effective
January 1, 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 costs of
retiring long-lived assets. The present value of the ultimate costs of an
asset's future retirement must be recorded in the period in which the liability
is incurred. The costs 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 the continued accrual of future retirement costs for
long-lived assets that the Company does not have a legal obligation to retire.
However, the Company has received guidance regarding accounting for the
financial statement impacts of Statement No. 143 from the Alabama PSC and will
continue to recognize the accumulated removal costs for other obligations as a
regulatory liability. Therefore, the Company had no cumulative effect to net
income resulting from the adoption of Statement No. 143.
The liability recognized to retire long-lived assets primarily relates to
the Company's nuclear facility, Plant Farley. The fair value of assets legally
restricted for settling retirement obligations related to nuclear facilities as
of December 31, 2003 was $385 million. In addition, the Company has retirement
II-92
NOTES (continued)
Alabama Power Company 2003 Annual Report
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 allowed removal costs in accordance with its regulatory
treatment. Any difference between costs recognized under Statement No. 143 and
those reflected in rates are recognized as either a regulatory asset or
liability, as ordered by the Alabama PSC, and are reflected in the Balance
Sheets. The Company also revised the estimated cost to retire Plant Farley as a
result of a new site-specific decommissioning study. The effect of the revision
is an increase of $35 million included in asset retirement obligations, with a
corresponding increase in property, plant, and equipment. See "Nuclear
Decommissioning" for further information on amounts included in rates.
Details of the asset retirement obligations included in the Balance Sheets
are as follows:
2003
----------------
(in millions)
Balance beginning of year $ -
Liabilities incurred 301
Liabilities settled -
Accretion 23
Cash flow revisions 35
- ---------------------------------------------------------------
Balance end of year $ 359
===============================================================
If Statement No. 143 had been adopted on January 1, 2002, the pro-forma
asset retirement obligations would have been $281 million.
Nuclear Decommissioning
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. The funds set aside
for decommissioning are managed and invested in accordance with applicable
requirements of various regulatory bodies, including the NRC, the FERC, and the
Alabama PSC, as well as the Internal Revenue Service (IRS). Funds are invested
in a tax efficient manner in a diversified mix of equity and fixed income
securities. Equity securities typically range from 50 to 75 percent of the funds
and fixed income securities from 25 to 50 percent. Amounts previously recorded
in internal reserves are being transferred into the external trust funds over
periods approved by the Alabama PSC. 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. The estimated costs of decommissioning, based on the most current
study as of December 31, 2003, for Plant Farley were as follows:
Site study year 2003
Decommissioning periods:
Beginning year 2017
Completion year 2046
-------------------------------------------------------------
(in millions)
Site study costs:
Radiated structures $892
Non-radiated structures 63
-------------------------------------------------------------
Total $955
=============================================================
Significant assumptions:
Inflation rate 4.5%
Trust earning rate 7.0
-------------------------------------------------------------
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 Alabama PSC. The amount expensed in 2003 and fund
balances were as follows:
(in millions)
Amount expensed in 2003 $ 18
-------------------------------------------------------------
Accumulated provisions:
External trust funds, at fair value $ 385
Internal reserves 31
-------------------------------------------------------------
Total $ 416
=============================================================
All of the Company's decommissioning costs for ratemaking are based on the
site study. The Company expects the Alabama PSC to periodically review and
II-93
NOTES (continued)
Alabama Power Company 2003 Annual Report
adjust, if necessary, the amounts collected in rates for the anticipated cost of
decommissioning.
The Company filed an application with the NRC in September 2003 to extend
the operating license for Plant Farley for an additional 20 years.
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 regulated 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 9.0 percent in 2003, 8.2 percent in 2002, and 7.7 percent in
2001. AFUDC and interest capitalized, net of income tax, as a percent of net
income after dividends on preferred stock was 3.5 percent in 2003 and 3.3
percent in each of 2002 and 2001.
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 Alabama PSC 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 2003, the Company accrued $28.5 million
to the nuclear refueling outage reserve and at December 31, 2003 the reserve
balance was $14.0 million.
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 either by the amount of the regulatory disallowance or
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.
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 Alabama PSC 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 2003, the Company accrued $3
million to the reserve and at December 31, 2003, the reserve balance was $12.6
million.
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
II-94
NOTES (continued)
Alabama Power Company 2003 Annual Report
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
that meet the definition of a derivative are exempt from fair value accounting
requirements and are accounted for under the accrual method. Other derivative
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. Other
derivative contracts 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.
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, 2003 $3,903 $3,958
At December 31, 2002 3,991 4,065
Preferred Securities:
At December 31, 2003 300 305
At December 31, 2002 300 303
--------------------------------------------------------------
The fair value for long-term debt and preferred securities was based on
either closing market prices or closing prices of comparable instruments.
Comprehensive Income
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. Comprehensive
income consists 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.
2. RETIREMENT BENEFITS
The Company has a defined benefit, trusteed, pension plan covering substantially
all employees. The plan is funded in accordance with Employee Retirement Income
Security Act (ERISA) requirements. The Company also provides certain
non-qualified benefit plans for a selected group of management and
highly-compensated employees. Benefits under these non-qualified plans are
funded on a cash basis. In addition, the Company provides certain medical care
and life insurance benefits for retired employees. The Company funds trusts to
the extent required by the Alabama PSC. For the year ended December 31, 2004,
postretirement benefit contributions are expected to total approximately $4.2
million.
The measurement date for plan assets and obligations is September 30 for
each year. In 2002, the Company adopted several plan changes that had the effect
of increasing benefits to both current and future retirees.
Pension Plans
The accumulated benefit obligation for the pension plans was $1.20 billion in
2003 and $1.09 billion in 2002. Changes during the year in the projected benefit
obligations, accumulated benefit obligations, and fair value of plan assets were
as follows:
Projected
Benefit Obligations
---------------------------
2003 2002
- -------------------------------------------------------------
(in millions)
Balance at beginning of year $1,088 $1,011
Service cost 27 26
Interest cost 68 74
Benefits paid (61) (61)
Plan amendments 3 22
Actuarial (gain) loss 75 16
- -------------------------------------------------------------
Balance at end of year $1,200 $1,088
=============================================================
II-95
NOTES (continued)
Alabama Power Company 2003 Annual Report
Plan Assets
---------------------------
2003 2002
- -------------------------------------------------------------
(in millions)
Balance at beginning of year $1,419 $1,584
Actual return on plan assets 226 (106)
Benefits paid (62) (59)
- -------------------------------------------------------------
Balance at end of year $1,583 $1,419
=============================================================
Pension plan assets are managed and invested in accordance with all
applicable requirements, including ERISA and the IRS revenue code. The Company's
investment policy covers a diversified mix of assets, including equity and fixed
income securities, real estate, and private equity, as described in the table
below. Derivative instruments are used primarily as hedging tools but may also
be used to gain efficient exposure to the various asset classes. The Company
primarily minimizes the risk of large losses through diversification but also
monitors and manages other aspects of risk.
Plan Assets
------------------------------
Target 2003 2002
- -------------------------------------------------------------
Domestic equity 37% 37% 35%
International equity 20 20 18
Global fixed income 26 24 25
Real estate 10 11 12
Private equity 7 8 10
- -------------------------------------------------------------
Total 100% 100% 100%
=============================================================
The accrued pension costs recognized in the Balance Sheets
were as follows:
2003 2002
- -------------------------------------------------------------
(in millions)
Funded status $383 $331
Unrecognized transition amount (5) (10)
Unrecognized prior service cost 87 93
Unrecognized net (gain) loss (37) (40)
- --------------------------------------------------------------
Prepaid pension asset, net 428 374
Portion included in
benefit obligations 18 16
- -------------------------------------------------------------
Total prepaid assets recognized in
the Balance Sheets $446 $390
=============================================================
In 2003 and 2002, amounts recognized in the Balance Sheets for accumulated
other comprehensive income and intangible assets to record the minimum pension
liability related to the non-qualified plans were $12.8 million and $6.7 million
and $6.7 and $4.8 million, respectively.
Components of the pension plans' net periodic cost were as follows:
2003 2002 2001
- -------------------------------------------------------------
(in millions)
Service cost $ 27 $ 26 $ 25
Interest cost 68 74 70
Expected return on plan assets (138) (138) (131)
Recognized net gain (12) (20) (22)
Net amortization 3 2 1
- -------------------------------------------------------------
Net pension cost (income) $ (52) $(56) $ (57)
=============================================================
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
---------------------------
2003 2002
- -------------------------------------------------------------
(in millions)
Balance at beginning of year $405 $348
Service cost 6 5
Interest cost 26 26
Benefits paid (20) (20)
Actuarial (gain) loss 24 46
- -------------------------------------------------------------
Balance at end of year $441 $405
=============================================================
Plan Assets
---------------------------
2003 2002
- -------------------------------------------------------------
(in millions)
Balance at beginning of year $158 $169
Actual return on plan assets 25 (12)
Employer contributions 23 21
Benefits paid (20) (20)
- -------------------------------------------------------------
Balance at end of year $186 $158
=============================================================
Postretirement benefits plan assets are managed and invested in accordance
with all applicable requirements, including ERISA and the IRS revenue code. The
Company's investment policy covers a diversified mix of assets, including equity
and fixed income securities, real estate, and private equity, as described in
the table below. Derivative instruments are used primarily as hedging tools but
may also be used to gain efficient exposure to the various asset classes. The
Company primarily minimizes the risk of large losses through diversification but
also monitors and manages other aspects of risk.
Plan Assets
------------------------------
Target 2003 2002
- -------------------------------------------------------------
Domestic equity 46% 50% 42%
International equity 13 14 9
Global fixed income 34 28 40
Real estate 4 5 5
Private equity 3 3 4
- -------------------------------------------------------------
Total 100% 100% 100%
=============================================================
II-96
NOTES (continued)
Alabama Power Company 2003 Annual Report
The accrued postretirement costs recognized in the Balance Sheets were as
follows:
2003 2002
- -------------------------------------------------------------
(in millions)
Funded status $(255) $(247)
Unrecognized transition obligation 37 41
Unrecognized prior service cost 73 77
Unrecognized net loss (gain) 82 66
Fourth quarter contributions 6 8
- -------------------------------------------------------------
Accrued liability recognized in the
Balance Sheets $ (57) $ (55)
=============================================================
Components of the postretirement plan's net periodic cost
were as follows:
2003 2002 2001
- -------------------------------------------------------------
(in millions)
Service cost $ 6 $ 5 $ 5
Interest cost 25 25 24
Expected return on plan assets (17) (16) (15)
Net amortization 9 9 7
- -------------------------------------------------------------
Net postretirement cost $ 23 $ 23 $ 21
=============================================================
The weighted average rates assumed in the actuarial calculations used to
determine both the benefit obligations and the net periodic costs for the
pension and postretirement benefit plans were as follows:
2003 2002 2001
- ---------------------------------------------------------------
Discount 6.00% 6.50% 7.50%
Annual salary increase 3.75 4.00 5.00
Long-term return on plan assets 8.50 8.50 8.50
- ---------------------------------------------------------------
The Company determined the long-term rate of return on historical asset
class returns and current market conditions, taking into account the
diversification benefits of investing in multiple asset classes.
An additional assumption used in measuring the accumulated postretirement
benefit obligations was a weighted average medical care cost trend rate of 8.25
percent for 2003, 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,
2003 as follows:
1 Percent 1 Percent
Increase Decrease
- ---------------------------------------------------------------
(in millions)
Benefit obligation $34 $30
Service and interest costs 2 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 were $12 million for each of the years 2003,
2002, and 2001.
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. In addition, 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 against the Company cannot be predicted at this time;
however, management does not anticipate that the liabilities, if any, arising
from such current proceedings would have a material adverse effect on the
Company's financial statements.
New Source Review Actions
In November 1999, the Environmental Protection Agency (EPA) brought a civil
action in the U.S. District Court for the Northern District of Georgia against
the Company. The complaint alleged violations of the New Source Review (NSR)
provisions of the Clean Air Act and violations of related state laws with
respect to coal-fired generating facilities at the Company's Plants Miller,
Barry, and Gorgas. The civil action requested 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 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.
In August 2000, the U.S. District Court in Georgia granted the Company's
motion to dismiss for lack of jurisdiction in Georgia. The EPA refiled its claim
against the Company in the U.S. District Court for the Northern District of
II-97
NOTES (continued)
Alabama Power Company 2003 Annual Report
Alabama. The EPA brought similar NSR enforcement actions against several other
electric utility companies across the country including Georgia Power and
Savannah Electric. In each case, the EPA alleged that the utilities failed to
comply with the NSR permitting requirements when performing maintenance and
construction activities at coal-burning plants, which activities the utilities
considered to be routine or otherwise not subject to NSR.
The action against the Company was stayed in the spring of 2001 during the
appeal of a very similar NSR enforcement action against the Tennessee Valley
Authority (TVA) before the U.S. Court of Appeals for the Eleventh Circuit. The
TVA appeal involves many of the same legal issues raised by the actions against
the Company. Because the final resolution of the TVA appeal could have a
significant impact on the Company, it has been involved in that appeal. On June
24, 2003, the court of appeals issued its ruling in the TVA case. It found
unconstitutional the statutory scheme set forth in the Clean Air Act that
allowed the EPA to impose penalties for failing to comply with an administrative
compliance order, like the one issued to TVA, without the EPA having to prove
the underlying violation. Thus, the court of appeals held that the compliance
order was of no legal consequence, and TVA was free to ignore it. The court did
not, however, rule directly on the substantive legal issues about the proper
interpretation and application of certain NSR provisions that had been raised in
the TVA appeal. On September 16, 2003, the court of appeals denied the EPA's
request for a rehearing of the decision. On February 13, 2004, the EPA
petitioned the U.S. Supreme Court to review the decision of the court of
appeals. The EPA also filed a motion to lift the stay in the action against the
Company.
Since the inception of the NSR proceedings against the Company, the EPA has
also been proceeding with similar NSR enforcement actions against other
utilities, involving many of the same legal issues. In each case, the EPA
alleged that the utilities failed to comply with the NSR permitting requirements
when performing maintenance and construction activities at coal-burning plants,
which activities the utilities considered to be routine or otherwise not subject
to NSR. In 2003, district courts addressing these cases have issued opinions
that reached conflicting conclusions.
In October 2003, the EPA issued final revisions to its NSR regulations
under the Clean Air Act clarifying the scope of the existing Routine
Maintenance, Repair, and Replacement exclusion. On December 24, 2003, the U.S.
Court of Appeals for the District of Columbia Circuit stayed the effectiveness
of these revisions pending resolution of related litigation over those
revisions. In January 2004, the Bush Administration announced that it would
continue to enforce the existing rules.
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 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 if such costs are not
recovered through regulated rates.
Open Access Transmission Tariff
In October 2003, the FERC approved a new Open Access Transmission Tariff for the
Company of $1.73 per kilowatt-month based on an 11.25 percent return on equity.
The Company had requested a rate increase effective April 2002 based on a 13
percent return on equity. In September 2002, pending FERC approval, the Company
began collecting from customers based on the 13 percent rate, but recorded
revenue subject to refund for amounts above the previously approved rate of
$1.37 per kilowatt-month. As a result of the final settlement, a total of
approximately $2.4 million was refunded to the Company's transmission customers
in October 2003 and $7.6 million was recorded as revenue.
Retail Rate Adjustment Procedures
The Alabama PSC 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,
amounting to an annual increase of $55 million and $58 million, respectively. In
March 2002, the Alabama PSC 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 and the recovery of retail costs
II-98
NOTES (continued)
Alabama Power Company 2003 Annual Report
associated with certificated purchased power agreements (PPAs) under Rate CNP
(Certificated New Plant). Effective July 2001, the Company's retail rates were
adjusted by 0.6 percent ($17 million annually) under Rate CNP to recover costs
for Plant Barry Unit 7, which was placed into commercial operation on May 1,
2001.
In November 2000, the Alabama PSC certificated a seven-year, 615 megawatt,
PPA with Southern Power beginning in June 2003. In addition, the Alabama PSC
certificated a seven-year PPA with a third party for approximately 630
megawatts; one half of the capacity became available in 2003 while the remaining
half is scheduled to become available in 2004. As a result, the Company's retail
rates were adjusted beginning July 2003 by approximately 2.6 percent ($79
million annually) under Rate CNP. One month after the contracted capacity
delivery begins, which is scheduled for June 2004, Rate CNP will adjust retail
rates by approximately 0.8 percent ($25 million annually) to recover costs
associated with the scheduled 2004 PPA capacity.
In October 2001, the Alabama PSC 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 Alabama
PSC votes to modify or discontinue them.
FERC Matters
The Company has obtained FERC approval to sell power to nonaffiliates at
market-based prices under specific contracts. Through SCS, as agent, the Company
also has FERC authority to make short-term opportunity sales at market rates.
Specific FERC approval must be obtained with respect to a market-based contract
with an affiliate. In November 2001, the FERC modified the test it uses to
consider utilities' applications to charge market-based rates and adopted a new
test called the Supply Margin Assessment (SMA). The FERC applied the SMA to
several utilities, including Southern Company's retail operating companies, and
found them to be "pivotal suppliers" in their service areas and ordered the
implementation of several mitigation measures. SCS, on behalf of the retail
operating companies, sought rehearing of the FERC order, and the FERC delayed
the implementation of certain mitigation measures. SCS, on behalf of the retail
operating companies, submitted comments to the FERC in 2002 regarding these
issues. In December 2003, the FERC issued a staff paper discussing alternatives
and held a technical conference in January 2004. The Company anticipates that
the FERC will address the requests for rehearing in the near future. Regardless
of the outcome of the SMA proposal, the FERC retains the ability to modify or
withdraw the authorization for any seller to sell at market-based rates, if it
determines that the underlying conditions for having such authority are no
longer applicable. The final outcome of this matter will depend on the form in
which the SMA test and mitigation measures rules may be ultimately adopted and
cannot be determined at this time.
4. JOINT OWNERSHIP AGREEMENTS
The Company and Georgia Power own equally all of the outstanding capital stock
of 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 purchased power totaled $87
million in 2003, $84 million in 2002, and $80 million in 2001 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.
II-99
NOTES (continued)
Alabama Power Company 2003 Annual Report
At December 31, 2003, the capitalization of SEGCO consisted of $63 million
of equity and $94 million of debt on which the annual interest requirement is
$3.4 million. SEGCO paid dividends totaling $2.3 million in 2003, $5.8 million
in 2002, and $0.7 million in 2001, of which one-half of each was paid to the
Company. In addition, the Company recognizes 50 percent of SEGCO's net income.
In addition to the Company's ownership of SEGCO, the Company's percentage
ownership and investment in jointly-owned generating plants at December 31, 2003
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.
(2) Jointly owned with Alabama Electric Cooperative, Inc.
Company Accumulated
Facility Investment Depreciation
--------------------- -------------- ---------------
(in millions)
Greene County $110 $ 54
Plant Miller
Units 1 and 2 767 355
----------------------------------------------------------
The Company has contracted to operate and maintain the jointly owned
facilities as agent for their co-owners. The Company's proportionate share of
its plant operating expenses is included in the operating expenses in the
Statements of Income.
5. INCOME TAXES
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 IRS regulations,
each company is jointly and severally liable for the tax liability.
At December 31, 2003, the Company's tax-related regulatory assets and
liabilities were $321 million and $162 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.
Details of the income tax provisions are as follows:
2003 2002 2001
--------------------------------
(in millions)
Total provision for income taxes:
Federal --
Current $111 $209 $234
Deferred 137 41 (20)
- -----------------------------------------------------------------
248 250 214
- -----------------------------------------------------------------
State --
Current 26 35 37
Deferred 16 7 (2)
- -----------------------------------------------------------------
42 42 35
- -----------------------------------------------------------------
Total $290 $292 $249
=================================================================
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:
2003 2002
-------------------
(in millions)
Deferred tax liabilities:
Accelerated depreciation $1,204 $1,081
Property basis differences 401 381
Premium on reacquired debt 42 39
Pensions 117 103
Other 29 38
- -----------------------------------------------------------------
Total 1,793 1,642
- -----------------------------------------------------------------
Deferred tax assets:
Capacity prepayments 8 11
Other deferred costs 13 13
Postretirement benefits 14 18
Unbilled revenue 21 20
Other 86 87
- -----------------------------------------------------------------
Total 142 149
- -----------------------------------------------------------------
Total deferred tax liabilities, net 1,651 1,493
Portion included in current liabilities, net (80) (56)
- -----------------------------------------------------------------
Accumulated deferred income taxes
in the Balance Sheets $1,571 $1,437
=================================================================
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 each of 2003, 2002,
and 2001. At December 31, 2003, 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:
II-100
NOTES (continued)
Alabama Power Company 2003 Annual Report
2003 2002 2001
--------------------------
Federal statutory rate 35.0% 35.0% 35.0%
State income tax,
net of federal deduction 3.5 3.5 3.5
Non-deductible book
depreciation 1.2 1.3 1.5
Differences in prior years'
deferred and current tax rates (0.9) (1.2) (1.3)
Other (1.6) (0.5) (0.5)
- ---------------------------------------------------------------
Effective income tax rate 37.2% 38.1% 38.2%
===============================================================
6. FINANCING
Mandatorily Redeemable Preferred Securities
The Company has formed certain wholly owned trust subsidiaries for the purpose
of issuing preferred securities. The proceeds of the related equity investments
and preferred security sales were loaned back to the Company through the
issuance of junior subordinated notes totaling $309 million, which constitute
substantially all assets of these trusts. The Company considers that the
mechanisms and obligations relating to the preferred securities issued for its
benefit, taken together, constitute a full and unconditional guarantee by it of
the respective trusts' payment obligations with respect to these securities. At
December 31, 2003, preferred securities of $300 million were outstanding and
recognized as liabilities in the Balance Sheets. For additional information, see
the Statements of Capitalization.
First Mortgage Bonds
In October 1991, the Company entered into a firm power sales contract with the
Alabama Municipal Electric Authority (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, 2003, $26.7 million of
these bonds were held by the escrow agent under the contract.
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.
Senior Notes
The Company issued a total of $1.4 billion of unsecured senior notes in 2003.
The proceeds of these issues were used to redeem higher cost debt and for other
general corporate purposes.
At December 31, 2003 and 2002, the Company had $3.4 billion of senior notes
outstanding. These senior notes are subordinate to all secured debt of the
Company which amounted to approximately $295 million at December 31, 2003.
Long-Term Debt Due Within One Year
A summary of the improvement fund requirements and scheduled maturities and
redemptions of long-term debt due within one year at December 31 is as follows:
2003 2002
-----------------------
(in millions)
Capitalized leases $ 1 $ 1
Senior notes 525 1,117
------------------------------------------------- -----------
Total $526 $1,118
=============================================================
Debt redemptions and/or serial maturities through 2008 applicable to total
long-term debt are as follows: $526 million in 2004; $225 million in 2005; $715
million in 2006; $200 million in 2007; and $410 million in 2008.
II-101
NOTES (continued)
Alabama Power Company 2003 Annual Report
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.
Bank Credit Arrangements
The Company maintains committed lines of credit in the amount of $865 million
(including $504 million of such lines which are dedicated to funding purchase
obligations relating to variable rate pollution control bonds), all of which
expire at various times during 2004. Approximately $450 million of the credit
facilities expiring in 2004 allow for the execution of term loans for an
additional two-year period, and $245 million allow for the execution of one-year
term loans. All of the credit arrangements 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 1/4 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. For syndicated credit arrangements, a 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, as defined in
the agreements. Exceeding this debt level would result in a default under the
credit arrangements. At December 31, 2003, the Company was in compliance with
the debt limit covenants. In addition, the credit arrangements typically contain
cross default provisions that would be triggered if the Company defaulted on
other indebtedness (including guarantee obligations) above a specified
threshold. None of the arrangements contain material adverse change clauses at
the time of borrowings.
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 through extendible commercial note programs.
As of December 31, 2003, the Company had no extendible commercial notes and no
commercial paper outstanding. The amount of commercial paper outstanding at
December 31, 2002 was $37 million. During 2003, the peak amount outstanding for
commercial paper was $255 million and the average amount outstanding was $30
million. The average annual interest rate on commercial paper in 2003 was 1.29
percent. Commercial paper and extendible commercial notes are included in notes
payable on the Balance Sheets.
At December 31, 2003, the Company had regulatory approval to have
outstanding up to $1 billion of short-term borrowings.
Financial Instruments
The Company enters into energy-related derivatives to hedge exposures to
electricity, gas, and other fuel price changes. However, due to cost-based rate
regulations, the Company has limited exposure to market volatility in commodity
fuel prices and prices of electricity. The Company has implemented fuel-hedging
programs at the instruction of the Alabama PSC. The Company also enters into
hedges of forward electricity sales.
At December 31, 2003, the fair value of derivative energy contracts was
reflected in the financial statements as follows:
Amounts
------------
(in thousands)
Regulatory liabilities, net $6,402
Net income 11
- ------------------------------------------------------------
Total fair value $6,413
============================================================
The fair value gain or loss for cash flow hedges that are recoverable
through the regulatory fuel clauses are recorded in the regulatory assets and
liabilities and are recognized in earnings at the same time the hedged items
affect earnings.
The Company also enters into derivatives to hedge exposure of interest rate
changes. Interest derivatives related to variable rate securities or forecasted
transactions are accounted for as cash flow hedges. The interest derivatives are
generally structured to match the critical terms of the hedged debt instruments;
therefore, no material ineffectiveness has been recorded in earnings.
At December 31, 2003, the Company had $1.2 billion notional amount of
interest rate swaps outstanding with net deferred gains of $5.7 million as
follows:
Cash Flow Hedges
Weighted Average
-------------------- Fair
Fixed Value
Rate Notional Gain/
Maturity Paid Amount (Loss)
- ------------------------------------ --------------------
(in millions)
2004 1.63* $486 $(0.2)
2006 1.89 195 1.5
2007 1.99* 486 4.4
- -----------------------------------------------------------
*Hedged using the Bond Market Association Municipal Swap Index.
II-102
NOTES (continued)
Alabama Power Company 2003 Annual Report
The fair value gain or loss for cash flow hedges is recorded in other
comprehensive income and is reclassified into earnings at the same time the
hedged items affect earnings. In 2003 and 2002, the Company recognized losses of
$8 million and $13 million, respectively, upon termination of certain interest
derivatives at the same time it issued debt. These losses have been deferred in
other comprehensive income and will be amortized to interest expense over the
life of the related debt. For 2003, approximately $11.3 million of pre-tax
losses were reclassified from other comprehensive income to interest expense.
For 2004, pre-tax losses of approximately $5.8 million are expected to be
reclassified from other comprehensive income to interest expense.
7. COMMITMENTS
Construction Program
The Company is engaged in continuous construction programs, currently estimated
to total $791 million in 2004, $863 million in 2005, and $884 million in 2006.
These amounts include $12.5 million, $11.3 million, and $6.6 million in 2004,
2005, and 2006, respectively, for construction expenditures related to
contractual purchase commitments for uranium and nuclear fuel conversion,
enrichment, and fabrication services included in this note under "Fuel
Commitments." The construction programs are subject to periodic review and
revision, and actual construction costs may vary from the above estimates
because of numerous factors. These factors include: changes in business
conditions; revised load growth estimates; changes in environmental regulations;
changes in existing nuclear plants to meet new regulatory requirements; changes
in FERC rules and transmission regulations; increasing costs of labor,
equipment, and materials; and cost of capital. At December 31, 2003, significant
purchase commitments were outstanding in connection with the construction
program. The Company has no generating plants under construction. Construction
of new transmission and distribution facilities and capital improvements,
including those needed to meet environmental standards for existing generation
transmission, and distribution facilities, will continue.
Southern Company has guaranteed Southern Power's obligations to the Company
for transmission interconnection facilities of $6.8 million related to Plant
Harris units 1 & 2. The obligations were guaranteed at December 31, 2003, but,
upon completion of construction, were released in February 2004.
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. 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. At December 31,
2003, the remaining balance was approximately $213 million. 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. Total estimated minimum long-term obligations at December 31, 2003
were as follows:
Commitments
------------------------------------
Non-
Year Affiliated Affiliated Total
- ---- ------------------------------------
(in millions)
2004 $ 49 $ 36 $ 85
2005 49 38 87
2006 49 39 88
2007 49 40 89
2008 49 40 89
2009 and thereafter 62 67 129
- ---------------------------------------------------------------
Total commitments $307 $260 $567
===============================================================
II-103
NOTES (continued)
Alabama Power Company 2003 Annual Report
Fuel Commitments
To supply a portion of the fuel requirements of its generating plants, the
Company has entered into various long-term commitments for the procurement of
fossil and nuclear fuel. In most cases, these contracts contain provisions for
price escalations, minimum purchase levels, and other financial commitments.
Natural gas purchase commitments contain fixed volumes with prices based on
various indices at the time of delivery. Amounts included in the chart below
represent estimates based on New York Mercantile future prices at December 31,
2003. Total estimated minimum long-term commitments at December 31, 2003 were as
follows:
Coal &
Natural Nuclear
Year Gas Fuel
- ---- ---------------------------
(in millions)
2004 $ 318 $ 750
2005 181 514
2006 158 437
2007 107 429
2008 26 154
2009 and thereafter 108 -
- -------------------------------------------------------------
Total commitments $ 898 $2,284
==============================================================
Additional commitments for fuel will be required to supply the Company's
future needs.
SCS may enter into various types of wholesale energy and natural gas
contracts acting as an agent for the Company and all of the other Southern
Company retail operating companies, Southern Power, and Southern Company GAS.
Under these agreements, each of the retail operating companies, Southern Power,
and Southern Company GAS may be jointly and severally liable. The
creditworthiness of Southern Power and Southern Company GAS is currently
inferior to the creditworthiness of the retail operating companies. Accordingly,
Southern Company has entered into keep-well agreements with the Company and each
of the other retail operating companies to insure the Company will not subsidize
or be responsible for any costs, losses, liabilities, or damages resulting from
the inclusion of Southern Power or Southern Company 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
$29.5 million in 2003, $29.6 million in 2002, and $27.9 million in 2001. Of
these amounts, $19.4 million, $19.1 million, and $21.1 million for 2003, 2002,
and 2001, respectively, relates to the rail car leases and are recoverable
through the Company's energy cost recovery clause. At December 31, 2003,
estimated minimum rental commitments for noncancellable operating leases were as
follows:
Rail Vehicles
Year Cars & Other Total
- ---------------------------------------------------------------
(in millions)
2004 $19.1 $10.6 $29.7
2005 16.3 8.9 25.2
2006 11.3 6.2 17.5
2007 4.1 3.6 7.7
2008 3.8 2.0 5.8
2009 and thereafter 30.7 4.5 35.2
- ---------------------------------------------------------------
Total minimum payments $85.3 $35.8 $121.1
===============================================================
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 $66.0 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, 2003, 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.
8. NUCLEAR INSURANCE
Under the Price-Anderson Amendments Act of 1988 (Act), the Company maintains
agreements of indemnity with the NRC that, together with private insurance,
cover third-party liability arising from any nuclear incident occurring at Plant
Farley. The Act provides funds up to $10.9 billion for public liability claims
that could arise from a single nuclear incident. Plant Farley is insured against
this liability to a maximum of $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 $100.5 million per incident for
II-104
NOTES (continued)
Alabama Power Company 2003 Annual Report
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
$201 million per incident but not more than an aggregate of $20 million to be
paid for each incident in any one year. The Price-Anderson Amendments Act
expired in August 2002; however, the indemnity provisions of the act remain in
place for commercial nuclear reactors.
The Company is a member of Nuclear Electric Insurance Limited (NEIL), a
mutual insurer established to provide property damage insurance in an amount up
to $500 million for members' nuclear generating facilities.
Additionally, the Company has policies that currently provide
decontamination, excess property insurance, and premature decommissioning
coverage up to $2.25 billion for losses in excess of the $500 million primary
coverage. This excess insurance is also provided by NEIL.
NEIL also covers the additional costs that would be incurred in obtaining
replacement power during a prolonged accidental outage at a member's nuclear
plant. Members can purchase this coverage, subject to a deductible waiting
period of up 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
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 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
"non-certified" terrorist acts, i.e., acts that are not certified acts of
terrorism pursuant to the Terrorism Risk Insurance Act of 2002 (TRIA). The NEIL
aggregate -- applies to all non-certified claims stemming from terrorism within
a 12 month duration -- is $3.24 billion plus any amounts available through
reinsurance or indemnity from an outside source. The non-certified ANI cap is a
$300 million shared industry aggregate. Any act of terrorism that is certified
pursuant to the TRIA will not be subject to the foregoing NEIL and ANI
limitations but will be subject to the TRIA annual aggregate limitation of $100
billion of insured losses arising from certified acts of terrorism. The TRIA
will expire on December 31, 2005.
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.
9. QUARTERLY FINANCIAL INFORMATION
(UNAUDITED)
Summarized quarterly financial information for 2003 and 2002 are as follows:
Net Income
After
Dividends
Quarter Operating Operating on Preferred
Ended Revenues Income Stock
- -------------------- -------------------------------------------
(in millions)
March 2003 $ 890 $211 $ 92
June 2003 950 227 107
September 2003 1,216 414 217
December 2003 904 163 57
March 2002 $ 802 $191 $ 72
June 2002 924 256 116
September 2002 1,119 393 201
December 2002 865 182 72
- -----------------------------------------------------------------
The Company's business is influenced by seasonal weather conditions.
II-105
SELECTED FINANCIAL AND OPERATING DATA 1999-2003
Alabama Power Company 2003 Annual Report
- ---------------------------------------------------------------------------------------------------------------------------------
2003 2002 2001 2000 1999
- ---------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands) $3,960,161 $3,710,533 $3,586,390 $3,667,461 $3,385,474
Net Income after Dividends
on Preferred Stock (in thousands) $472,810 $461,355 $386,729 $419,916 $399,880
Cash Dividends
on Common Stock (in thousands) $430,200 $431,000 $393,900 $417,100 $399,600
Return on Average Common Equity (percent) 13.75 13.80 11.89 13.58 13.85
Total Assets (in thousands) $12,070,624 $11,591,666 $11,303,605 $11,228,118 $10,450,052
Gross Property Additions (in thousands) $648,560 $634,094 $635,540 $870,581 $809,044
- ---------------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $3,500,660 $3,377,740 $3,310,877 $3,195,772 $2,988,863
Preferred stock 372,512 247,512 317,512 317,512 317,512
Mandatorily redeemable preferred securities 300,000 300,000 347,000 347,000 347,000
Long-term debt 3,377,148 2,872,609 3,742,346 3,425,527 3,190,378
- ---------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $7,550,320 $6,797,861 $7,717,735 $7,285,811 $6,843,753
=================================================================================================================================
Capitalization Ratios (percent):
Common stock equity 46.4 49.7 42.9 43.9 43.7
Preferred stock 4.9 3.6 4.1 4.4 4.6
Mandatorily redeemable preferred securities 4.0 4.4 4.5 4.8 5.1
Long-term debt 44.7 42.3 48.5 46.9 46.6
- ---------------------------------------------------------------------------------------------------------------------------------
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+ A+ AA- AA-
Preferred Stock -
Moody's Baa1 Baa1 Baa1 a2 a2
Standard and Poor's BBB+ BBB+ BBB+ BBB+ 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 1,160,129 1,148,645 1,139,542 1,132,410 1,120,574
Commercial 204,561 203,017 196,617 193,106 188,368
Industrial 5,032 4,874 4,728 4,819 4,897
Other 757 789 751 745 735
- ---------------------------------------------------------------------------------------------------------------------------------
Total 1,370,479 1,357,325 1,341,638 1,331,080 1,314,574
=================================================================================================================================
Employees (year-end): 6,730 6,715 6,706 6,871 6,792
- ---------------------------------------------------------------------------------------------------------------------------------
II-106
SELECTED FINANCIAL AND OPERATING DATA 1999-2003 (continued)
Alabama Power Company 2003 Annual Report
- --------------------------------------------------------------------------------------------------------------------------------
2003 2002 2001 2000 1999
- --------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $1,276,800 $1,264,431 $1,138,499 $1,222,509 $1,145,646
Commercial 913,697 882,669 829,760 854,695 807,098
Industrial 844,538 788,037 763,934 859,668 843,090
Other 16,428 16,080 15,480 15,835 15,283
- --------------------------------------------------------------------------------------------------------------------------------
Total retail 3,051,463 2,951,217 2,747,673 2,952,707 2,811,117
Sales for resale - non-affiliates 487,456 474,291 485,974 461,730 415,377
Sales for resale - affiliates 277,287 188,163 245,189 166,219 92,439
- --------------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 3,816,206 3,613,671 3,478,836 3,580,656 3,318,933
Other revenues 143,955 96,862 107,554 86,805 66,541
- --------------------------------------------------------------------------------------------------------------------------------
Total $3,960,161 $3,710,533 $3,586,390 $3,667,461 $3,385,474
================================================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 16,959,566 17,402,645 15,880,971 16,771,821 15,699,081
Commercial 13,451,757 13,362,631 12,798,711 12,988,728 12,314,085
Industrial 21,593,519 21,102,568 20,460,022 22,101,407 21,942,889
Other 203,178 205,346 198,102 205,827 201,149
- --------------------------------------------------------------------------------------------------------------------------------
Total retail 52,208,020 52,073,190 49,337,806 52,067,783 50,157,204
Sales for resale - non-affiliates 17,085,376 15,553,545 15,277,839 14,847,533 12,437,599
Sales for resale - affiliates 9,422,301 8,844,050 8,843,094 5,369,474 5,031,781
- --------------------------------------------------------------------------------------------------------------------------------
Total 78,715,697 76,470,785 73,458,739 72,284,790 67,626,584
================================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 7.53 7.27 7.17 7.29 7.30
Commercial 6.79 6.61 6.48 6.58 6.55
Industrial 3.91 3.73 3.73 3.89 3.84
Total retail 5.84 5.67 5.57 5.67 5.60
Sales for resale 2.88 2.72 3.03 3.11 2.91
Total sales 4.85 4.73 4.74 4.95 4.91
Residential Average Annual
Kilowatt-Hour Use Per Customer 14,688 15,198 13,981 14,875 14,097
Residential Average Annual
Revenue Per Customer $1,105.77 $1,104.28 $1,002.30 $1,084.26 $1,028.76
Plant Nameplate Capacity
Ratings (year-end) (megawatts) 12,174 12,153 12,153 12,122 11,379
Maximum Peak-Hour Demand (megawatts):
Winter 10,409 9,423 9,300 9,478 8,863
Summer 10,462 10,910 10,241 11,019 10,739
Annual Load Factor (percent) 64.1 62.9 62.5 59.3 59.7
Plant Availability (percent):
Fossil-steam 85.9 85.8 87.1 89.4 80.4
Nuclear 94.7 93.2 83.7 88.3 91.0
- --------------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 56.5 55.5 56.8 63.0 64.1
Nuclear 17.0 17.1 15.8 16.9 17.8
Hydro 7.0 5.1 5.1 2.9 4.7
Gas 7.6 11.6 10.7 4.9 1.1
Purchased power -
From non-affiliates 4.1 4.0 4.4 4.6 4.5
From affiliates 7.8 6.7 7.2 7.7 7.8
- --------------------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0 100.0 100.0
================================================================================================================================
II-107
GEORGIA POWER COMPANY
FINANCIAL SECTION
II-108
MANAGEMENT'S REPORT
Georgia Power Company 2003 Annual Report
The management of Georgia 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 upon 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 internal accounting controls are 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
four independent directors, provides a broad overview of management's financial
reporting and control functions. Additionally, the Controls and Compliance
Committee of the Company'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
Chief Executive Officer
/s/Michael D. Garrett
Michael D. Garrett
President
/s/C. B. Harreld
C. B. Harreld
Executive Vice President, Treasurer,
and Chief Financial Officer
March 1, 2004
II-109
INDEPENDENT AUDITORS' REPORT
Georgia Power Company:
We have audited the accompanying balance sheets and statements of capitalization
of Georgia Power Company (a wholly owned subsidiary of Southern Company) as of
December 31, 2003 and 2002, and the related statements of income, comprehensive
income, common stockholder's equity, and cash flows of the years then ended.
These financial statements are the responsibility of Georgia Power Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits. The financial statements of Georgia Power
Company for the year ended December 31, 2001 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 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, the financial statements (pages II-128 to II-154) present
fairly, in all material respects, the financial position of Georgia Power
Company at December 31, 2003 and 2002, and the results of its operations and its
cash flows for the years then ended in conformity with accounting principles
generally accepted in the United States of America.
As discussed in Note 1 to the financial statements, in 2003 Georgia Power
Company changed its method of accounting for asset retirement obligations.
/s/Deloitte & Touche LLP
Atlanta, Georgia
March 1, 2004
THE FOLLOWING REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS IS A COPY OF THE REPORT
PREVIOUSLY ISSUED IN CONNECTION WITH THE COMPANY'S 2001 ANNUAL REPORT 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-110
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Georgia Power Company 2003 Annual Report
OVERVIEW OF EARNINGS AND BUSINESS
- ---------------------------------
ACTIVITIES
- ----------
Earnings
Georgia Power Company's 2003 earnings totaled $631 million, representing a
$13 million (2.1 percent) increase over 2002. Operating income increased in 2003
despite lower base retail revenues resulting from the extremely mild summer
weather. Higher wholesale revenues and lower non-fuel operating expenses
contributed to the increase. The 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 resulted from
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.
Business Activities
The Company 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.
Several factors affect the opportunities, challenges and risk of the
Company's primary business of selling electricity. These factors include the
ability to maintain a stable regulatory environment, to achieve energy sales
growth while containing costs, and to recover costs related to growing demand
and increasingly strict environmental standards. 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 energy contracts with neighboring utilities, energy
conservation practiced by customers, the price of electricity, the price
elasticity of demand, and the rate of economic growth in the service area.
RESULTS OF OPERATIONS
- ---------------------
A condensed income statement for the Company is as follows:
Increase (Decrease)
Amount From Prior Year
------------------------------------------
2003 2003 2002 2001
- -----------------------------------------------------------------
(in millions)
Operating revenues $4,914 $ 92 $(144) $ 95
- -----------------------------------------------------------------
Fuel 1,104 101 64 (79)
Purchased power 776 92 (87) 175
Other operation
and maintenance 1,247 (78) 85 41
Depreciation and
amortization 350 (54) (197) (19)
Taxes other than
income taxes 213 11 (1) (1)
- -----------------------------------------------------------------
Total operating
expenses 3,690 72 (136) 117
- -----------------------------------------------------------------
Operating income 1,224 20 (8) (22)
Other income and
(expense) (227) 2 9 76
Less -
Income taxes 366 9 (7) 3
- -----------------------------------------------------------------
Net income $ 631 $13 $ 8 $ 51
=================================================================
II-111
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2003 Annual Report
Revenues
Operating revenues in 2003, 2002, and 2001 and the percent of change from the
prior year are as follows:
Amount
------------------------------------
2003 2002 2001
------------------------------------
(in millions)
Retail - prior year $4,288 $4,349 $4,317
Change in -
Base rates - (118) -
Sales growth and other 30 2 90
Weather (66) 82 (107)
Fuel cost recovery
and other 58 (27) 49
- --------------------------------------------------------------------
Retail - current year 4,310 4,288 4,349
- --------------------------------------------------------------------
Sales for resale -
Non-affiliates 260 271 366
Affiliates 175 98 100
- --------------------------------------------------------------------
Total sales for resale 435 369 466
- --------------------------------------------------------------------
Other operating revenues 169 165 151
- --------------------------------------------------------------------
Total operating revenues $4,914 $4,822 $4,966
====================================================================
Percent change 1.9% (2.9)% 2.0%
- --------------------------------------------------------------------
Retail base revenues of $3.0 billion in 2003 decreased by $36 million (1.2
percent) from 2002 primarily due to extremely mild summer temperatures in 2003
and the sluggish economy. Residential kilowatt-hour (KWH) sales decreased by 1.7
percent. Retail base revenues of $3.1 billion in 2002 decreased by $34 million
(1.1 percent) from 2001 primarily due to a base rate reduction effective January
2002 under the GPSC retail rate order and generally lower prices to large
business customers. This decrease was partially offset by a 10.1 percent
increase in residential KWH sales due to warmer weather. Retail base revenues of
$3.1 billion in 2001 decreased $17 million (0.5 percent) from 2000, primarily
due to a 2.5 percent decrease in retail KWH sales from the prior year.
Milder-than-normal weather and a slowdown in the economy contributed to the
decline in such sales.
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, 2003, the Company had $151 million in
under-recovered fuel costs. On August 19, 2003, the GPSC issued an order
allowing the Company to increase customer fuel rates to recover existing
under-recovered deferred fuel costs. See Note 3 to the financial statements
under "Fuel Cost Recovery" for further information regarding this order.
Wholesale revenues from sales to non-affiliated utilities were:
2003 2002 2001
------------------------------
(in millions)
Unit power sales --
Capacity $ 34 $ 34 $ 26
Energy 31 34 35
Other power sales --
Capacity 38 41 72
Energy 157 162 233
- --------------------------------------------------------------
Total $260 $271 $366
==============================================================
Revenues from unit power contracts decreased slightly in 2003 due to
decreased energy sales. Approximately 103 megawatts of capacity is scheduled to
be sold annually through 2010. Revenues from other non-affiliated sales
decreased $8 million (3.9 percent) in 2003, decreased $102 million (33.4
percent) in 2002 and increased $62 million in 2001 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 Company
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. In 2003, energy sales to affiliates increased 47.5 percent due to
the combination of increased demand by Southern Power to meet contractual
obligations and the availability of power due to milder-than-normal weather in
the Company's service territory. These transactions do not have a significant
impact on earnings since this energy is generally sold at marginal cost.
Other operating revenues increased $4 million (2.4 percent) in 2003
primarily due to an increase in the open access transmission tariff rate, which
increased revenues $7 million, and higher revenues from increased customer
demand for outdoor lighting services of $4 million, partially offset by lower
revenue from the rental of electric property of $4 million. See Note 3 to the
financial statements under "Open Access Transmission Tariff" for further
II-112
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2003 Annual Report
information regarding the increase in the open access transmission tariff rate.
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 of $7 million and higher revenues from increased
customer demand for outdoor lighting services of $5 million and the transmission
of electricity of $3 million. 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.
Energy Sales
KWH sales for 2003 and the percent change by year were as follows:
KWH Percent Change
-----------------------------------------
2003 2003 2002 2001
-----------------------------------------
(in billions)
Residential 21.8 (1.7)% 10.1% (2.8)%
Commercial 26.9 (0.1) 1.7 3.4
Industrial 25.7 (0.1) 1.5 (8.0)
Other 0.6 0.4 1.7 2.5
--------
Total retail 75.0 (0.5) 4.0 (2.5)
--------
Sales for resale -
Non-affiliates 8.9 9.5 (0.5) 25.5
Affiliates 5.8 47.5 26.5 28.7
--------
Total sales for
resale 14.7 22.0 7.0 26.3
--------
Total sales 89.7 2.6 4.4 0.5
================================================================
Residential KWH sales decreased 1.7 percent in 2003 due to the effect of
the milder summer weather despite the 2 percent increase in residential
customers. Commercial KWH sales declined slightly due to the milder summer
weather, while industrial KWH sales declined slightly due to the sluggish
economy. Residential KWH sales increased 10.1 percent in 2002 due to the effect
of the warmer weather. Commercial and industrial KWH 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 KWH sales decreased 2.8
percent in 2001 due to milder-than-normal weather. Commercial KWH sales
increased 3.4 percent due to an increase in customers, while industrial KWH
sales decreased 8.0 percent due to an economic slowdown. Retail sales growth
assuming normal weather is expected to be 1.6 percent on average from 2004 to
2013.
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:
2003 2002 2001
------------------------------
Total generation
(billions of KWH) 73.1 70.4 68.9
Sources of generation
(percent) --
Coal 75.4 77.4 74.9
Nuclear 21.6 21.1 23.2
Hydro 2.7 1.2 1.4
Oil and gas 0.3 0.3 0.5
Average cost of fuel per net
KWH generated
(cents) -- 1.46 1.42 1.38
Average cost of purchased
power per net KWH
(cents) -- 4.03 3.29 3.79
- ------------------------------------------------------------------
Fuel expense increased 10.1 percent in 2003 due to an increase in
generation of 3.9 percent because of higher wholesale energy demands and a 2.8
percent higher average cost of fuel due to the higher prices of coal and natural
gas in 2003. Fuel expense increased 6.8 percent in 2002 due to a 2.2 percent
increase in generation because of higher energy demands and a 2.9 percent higher
average cost of fuel due to the higher cost of coal. 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.
Purchased power expense increased $91 million (13.3 percent) in 2003
primarily due to $75 million of additional capacity expense associated with new
purchased power contracts that went into effect in 2003 and 2002. Purchased
power expense decreased $87 million (11.2 percent) in 2002 and increased $175
million (29.4 percent) in 2001 primarily due to fluctuations in off-system
energy purchases used to meet off-system sales commitments. The 2002 decrease in
energy purchases was partially offset by a $43 million increase in capacity
expense associated with new purchased power contracts.
II-113
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2003 Annual Report
In 2003, other operation and maintenance expenses decreased $78 million
(5.9 percent) due to the timing of generating plant maintenance of $46 million
and transmission and distribution maintenance of $8 million and lower severance
costs of $8 million. In 2002, other operation and maintenance expenses increased
$85 million (6.8 percent) due to the timing of generating plant maintenance of
$44 million and transmission maintenance of $17 million, and increased property
insurance expense of $5 million. 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.
Depreciation and amortization decreased $54 million in 2003 primarily as a
result of lower regulatory charges related to the inclusion of new certified
purchased power costs in retail rates on a levelized basis as ordered by the
GPSC. 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. See Note 3 to the financial statements under "Retail
Rate Orders" for additional information.
Taxes other than income taxes increased $11 million (5.4 percent) in 2003
due mainly to a favorable true-up of state property tax valuations in 2002.
Taxes other than income taxes remained relatively constant in 2002.
Interest income increased $12 million in 2003 when compared to the prior
year due to interest on a favorable income tax settlement of $14.5 million.
Interest income remained relatively constant in 2002.
Interest expense increased in 2003 primarily related to an increase in
senior notes outstanding that was partially offset by a reduction in short-term
debt outstanding. Interest expense decreased in 2002 and 2001 primarily due to
lower interest rates that offset new financing costs. The Company refinanced or
retired $665 million, $929 million, and $775 million of securities in 2003,
2002, and 2001, respectively. Interest capitalized decreased in 2003 and 2002
due to the transfer of three new generation projects to Southern Power in 2002
and 2001. Interest capitalized increased in 2001 during the construction phase
of these new projects. See Note 7 to the financial statements under
"Construction Program" for additional information regarding the construction and
subsequent transfer of these generation assets. Distributions on mandatorily
redeemable preferred securities decreased in 2003 due to the redemption of
securities in the second half of 2002 and increased in 2002 due to the issuance
of additional securities while remaining unchanged in 2001.
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 operations for the past three years are not necessarily
indicative of future earnings. The level of future earnings depends on numerous
factors including the Company's ability to maintain a stable regulatory
environment, to achieve energy sales growth while containing costs, and to
recover costs related to growing demand and increasingly strict environmental
standards.
Growth in energy sales is subject to a number of factors which include
weather, competition, new energy contracts with neighboring utilities, energy
conservation practiced by customers, the price of electricity, the price
elasticity of demand, and the rate of economic growth in the service area.
Industry Restructuring
The Company operates as a vertically integrated utility providing electricity to
retail customers within its traditional service area located in the State of
II-114
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2003 Annual Report
Georgia and to wholesale customers in the Southeast. Prices for electricity
provided by the Company to retail customers are set by the GPSC under cost-based
regulatory principles.
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
allowed independent power producers to access a utility's transmission network
and sell electricity to other utilities.
Although the Energy Act does not provide for retail customer access, it was
a major catalyst for 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 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, as well as the August 2003 power outage in
the Northeast. 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.
Since 2001, merchant energy companies and traditional electric utilities
with significant energy marketing and trading activities have come 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).
Continuing to be a low-cost producer could provide opportunities to
increase the size and profitability in markets that evolve with changing
regulation and competition. Conversely, future regulatory changes could
adversely affect the Company's growth, and 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.
Environmental Matters
New Source Review Actions
In November 1999, the Environmental Protection Agency (EPA) brought a civil
action against the Company alleging the Company had violated the New Source
Review (NSR) 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 action against the Company has been stayed since the spring of 2001 during
the appeal of a very similar NSR action against the Tennessee Valley Authority
before the U.S. Court of Appeals for the Eleventh Circuit. The Eleventh Circuit
appeal was decided on September 16, 2003, and, on February 13, 2004, the EPA
petitioned the U.S. Supreme Court to review the Eleventh Circuit's decision. At
this time, no party to the Company's action, which was administratively closed
two years ago, has asked the court to reopen that case. See Note 3 to the
financial statements under "New Source Review Actions" for additional
information.
In December 2002 and October 2003, the EPA issued final revisions to its
NSR regulations under the Clean Air Act. The December 2002 revisions included
changes to the regulatory exclusions and the methods of calculating emissions
increases. The October 2003 regulations clarified the scope of the existing
Routine Maintenance Repair and Replacement exclusion. A coalition of states and
environmental organizations filed petitions for review of these revisions with
the U.S. Court of Appeals for the District of Columbia Circuit. On December 24,
2003, the Court of Appeals granted a stay of the October 2003 revisions pending
its review of the rules, and ordered that its review would be conducted on an
expedited basis. In January 2004, the Bush Administration announced that it
would continue to enforce the existing rules until the courts resolve legal
challenges to the EPA's revised NSR regulations. In any event, the final
II-115
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2003 Annual Report
regulations must be adopted by the State of Georgia in order to apply to the
Company's facilities. The effect of these final regulations and the related
legal challenges cannot be determined 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 this matter 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 Environmental 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 the Company for alleged violations of the Clean Air Act
at four of the units at Plant Wansley. 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. This case is currently scheduled
for trial during the summer of 2004. See Note 3 to the financial statements
under "Plant Wansley Environmental Litigation" for additional information.
While the Company 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
capital and operating costs, a major portion of which is expected to be
recovered through existing ratemaking provisions. Environmental costs that are
known and estimable at this time are included in capital expenditures under
"Capital Requirements and Contractual Obligations." 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. Title IV compliance
was effective in 2000 and associated construction expenditures totaled
approximately $206 million. Some of these expenditures 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 adopted
regulations that required additional nitrogen oxide emission reductions from May
through September of each year at plants in and/or near those nonattainment
areas. Seven generating plants in the Atlanta area are currently subject to
those requirements, the most recent of which went into effect in 2003.
Construction expenditures for compliance with the nitrogen oxide emission
reduction requirements are estimated to be $698 million, of which $17 million
remains to be spent.
On September 26, 2003, the EPA published a final rule effective January 1,
2004 reclassifying the Atlanta area from a "serious" to a "severe" nonattainment
area for the one-hour ozone air quality standard under Title I of the Clean Air
Act. The attainment deadline is to be as expeditious as practicable but not
later than November 15, 2005. If the Atlanta area fails to comply with the
one-hour ozone standard by the deadline, all major sources of nitrogen oxides
and volatile organic compounds located in the nonattainment area, including the
Company's plants McDonough and Yates, could be subject to payment of annual
emissions fees for nitrogen oxides emitted above 80 percent of the baseline
period. The baseline period is expected to be the calendar year 2005. Based on
average emissions at these units over the past three years, such fees could
reach $23 million annually. The final outcome of this matter will depend on the
baseline period selected and the development, approval, and implementation of
applicable regulations including new regulations for the eight-hour ozone air
quality standard.
To help ozone nonattainment areas attain the one-hour ozone standard, the
EPA issued regional nitrogen oxide reduction rules in 1998. Those rules required
21 states, including Georgia, to reduce and cap nitrogen oxide emissions from
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2003 Annual Report
power plants and other large industrial sources. As a result of litigation
challenging the rule, the courts required the EPA to complete a separate
rulemaking before the requirements can be applied in Georgia. The final EPA
rules have not been issued in Georgia. The impact of this rule on the Company
will depend on the form in which it is finalized and cannot be determined at
this time.
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
eight-hour ozone standard unlawful and remanded it to the EPA for further
rulemaking. During 2003, the EPA proposed implementation rules designed to
address the court's concerns. The EPA plans to designate areas as attainment or
nonattainment with the new eight-hour ozone standard in April 2004 and with the
new fine particulate matter standard by the end of 2004. These designations will
be based on air quality data for 2001 through 2003. Several areas within the
Company's service area are likely to be designated nonattainment under these
standards. State implementation plans (SIPs), including new emission control
regulations necessary to bring those areas into attainment, could be required as
early as 2007. Those SIPs could require reductions in sulfur dioxide emissions
and 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 and cannot be determined at this time.
In January 2004, the EPA issued a proposed Interstate Air Quality Rule to
address interstate transport of ozone and fine particles. This proposed rule
would require additional year-round sulfur dioxide and nitrogen oxide emission
reductions from power plants in the eastern United States in two phases - in
2010 and 2015. The EPA currently plans to finalize this rule by 2005. If
finalized, the rule could modify or supplant other SIP requirements for
attainment of the fine particulate matter standard and the eight-hour ozone
standard. The impact of this rule on the Company will depend upon the specific
requirements of the final rule and cannot be determined at this time.
Further reductions in sulfur dioxide and nitrogen oxides 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 SIPs in 2007. The SIPs must contain emission
reduction strategies for implementing BART and achieving progress toward the
Clean Air Act's 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.
The EPA has entered into an agreement that requires proposed revised rules in
April 2004 and final rules in 2005. Because new BART rules have not been
developed and state visibility assessments for progress 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. In 2004 and 2005, a number of
the Company's 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. Because the plans are still under development, the Company
cannot determine the costs associated with implementation of the CAM
regulations. Actual ongoing monitoring costs are expensed as incurred and are
not material for any year presented.
In January 2004, the EPA issued proposed rules regulating mercury emissions
from electric utility boilers. The proposal solicits comments on two possible
approaches for the new regulations - a Maximum Achievable Control Technology
approach and a cap-and-trade approach. Either approach would require significant
reductions in mercury emissions from Company facilities. The regulations are
scheduled to be finalized by the end of 2004, and compliance could be required
as early as 2007. Because the regulations have not been finalized, the impact on
the Company cannot be determined at this time.
Several major bills to amend the Clean Air Act to impose more stringent
emissions limitations on power plants have been proposed by Congress. Three of
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2003 Annual Report
these, the Bush Administration's Clear Skies Act, the Clean Power Act of 2003,
and the Clean Air Planning Act of 2003, propose to further limit power plant
emissions of sulfur dioxide, nitrogen oxides, and mercury. The latter two bills
also propose to limit emissions of carbon dioxide. The cost impacts of such
legislation would depend upon the specific requirements enacted and cannot be
determined at this time.
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, known
as Climate VISION, 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.
Through Southern Company, the Company is involved in a voluntary electric
utility industry sector climate change initiative in partnership with the
government. The electric utility sector has pledged to reduce its greenhouse gas
intensity 3 to 5 percent over the next decade, and is in the process of
developing a memorandum of understanding with the Department of Energy (DOE) to
cover this voluntary program.
The Company must comply with other environmental laws and regulations that
cover the handling and disposal of 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 and monitor known sites. Amounts expensed for cleanup and
ongoing monitoring costs were not material for any year presented. 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 "Potentially Responsible Party Status" for information
regarding the Company's potentially responsible party status at sites in
Georgia.
Under the Clean Water Act, the EPA has been developing new rules aimed at
reducing impingement and entrainment of fish and fish larvae at power plants'
cooling water intake structures. On February 16, 2004, the EPA finalized these
rules. These rules will require numerous biological studies, and, perhaps,
retrofits to some intake structures at existing power plants. The impact of
these new rules will depend on the results of studies and analyses performed as
part of the rules' implementation.
The Company is also planning to install cooling towers at some of its
facilities to cool water prior to discharge under the Clean Water Act. Cooling
towers for two plants near Atlanta are scheduled for completion in 2004 and 2008
at an estimated total of $160 million, of which $90 million remains to be spent.
Also, the Company is conducting a study of the aquatic environment at another
facility to determine if additional controls are necessary.
In addition, under the Clean Water Act, the EPA and the State of Georgia
Environmental Protection Division (EPD) are developing total maximum daily loads
(TMDLs) for certain impaired waters. Establishment of maximum loads by the EPA
or EPD 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 that discharge 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.
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 or
regulations related to global climate change, electromagnetic fields, or other
environmental and health concerns could also significantly affect the Company.
The impact of any new legislation, changes to existing legislation, or
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2003 Annual Report
environmental regulations could affect many areas of the Company's operations.
The full impact of any such changes cannot, however, be determined at this time.
FERC Matters
Transmission
In December 1999, the Federal Energy Regulatory Commission (FERC) issued its
final rule (Order 2000) on Regional Transmission Organizations (RTOs). Order
2000 encouraged utilities owning transmission systems to form RTOs on a
voluntary basis. Through Southern Company, the Company worked with a number of
utilities in the Southeast to develop a for-profit RTO known as SeTrans. In
2002, the sponsors of SeTrans established a Stakeholder Advisory Committee to
provide input into the development of the RTO from other sectors of the electric
industry, as well as consumers. During the development of SeTrans, state
regulatory authorities expressed concern over certain aspects of the FERC's
policies regarding RTOs. In December 2003, the SeTrans sponsors announced that
they would suspend work on SeTrans because the regulated utility participants,
including the Company, had determined that it was highly unlikely to obtain
support of both federal and state regulatory authorities. Any impact of the
FERC's rule on the Company will depend on the regulatory reaction to the
suspension of SeTrans and future developments, which 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 day ahead and spot energy markets;
and (7) revise the FERC policy on the pricing of transmission expansions.
Comments on the proposal were submitted by many interested parties, including
Southern Company, and the FERC has indicated that it has revised certain aspects
of the proposal in response to public comments. Proposed energy legislation
would prohibit the FERC from issuing the final rule before October 31, 2006, and
from making any final rule effective before December 31, 2006. That legislation
has been approved by the House of Representatives but remains pending before the
Senate. Passage of the legislation now appears in doubt. It is uncertain whether
in the absence of legislation the FERC will move forward with any part or all of
the proposed rule. Any impact of this proposal on the Company will depend on the
form in which the final rule may be ultimately adopted. However, the Company's
financial statements could be adversely affected by changes in the transmission
regulatory structure in its regional power market.
Market-Based Rate Authority
The Company has obtained FERC approval to sell power to non-affiliates at
market-based prices under specific contracts. Through SCS, as agent, the Company
also has FERC authority to make short-term opportunity sales at market rates.
Specific FERC approval must be obtained with respect to a market-based contract
with an affiliate. In November 2001, the FERC modified the test it uses to
consider utilities' applications to charge market-based rates and adopted a new
test called the Supply Margin Assessment (SMA). The FERC applied the SMA to
several utilities, including Southern Company's retail operating companies, and
found them to be "pivotal suppliers" in their control area market and ordered
the implementation of several mitigation measures. SCS, on behalf of the Company
and the other retail operating companies, sought rehearing of the FERC order and
the FERC delayed implementation of certain mitigation measures. SCS, on behalf
of the Company and the other retail operating companies, submitted comments to
the FERC in 2002 regarding these issues. In December 2003, the FERC issued a
staff paper discussing alternatives and held a technical conference in January
2004. The Company anticipates that the FERC will address the requests for
rehearing in the near future. Regardless of the outcome of the SMA proposal, the
FERC retains the ability to modify or withdraw the authorization for any seller
to sell at market-based rates, if it determines that the underlying conditions
for having such authority are no longer applicable. The final outcome of this
matter will depend on the form in which the SMA test and mitigation measures
rules may be ultimately adopted and cannot be determined at this time.
Purchased power agreements (PPAs) by the Company and Savannah Electric for
Southern Power's Plant McIntosh capacity were certified by the GPSC in December
2002 after a competitive bidding process. In April 2003, Southern Power applied
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2003 Annual Report
for FERC approval of the PPAs. Interveners have made filings in opposition of
the FERC's acceptance of the PPAs, alleging that the PPAs do not meet the
applicable standards for market-based rates between alliliates. In July 2003,
the FERC accepted the PPAs to become effective as scheduled on June 1, 2005,
subject to refund, and ordered that hearings be held. For additional
information, see Note 3 to the financial statements under "FERC Matters."
Other Matters
The Company is currently operating under a GPSC approved three-year retail rate
order ending December 31, 2004. Under the terms of the order, earnings are
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 are
applied to rate refunds with the remaining one-third retained by the Company.
The Company 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.
The Company has entered into various long-term PPAs which will result in
higher capacity and operating and maintenance payments in future years. These
agreements have been certified by the GPSC under Georgia's Integrated Resource
Plan statute. Once certified, these costs are recoverable in rates under the
statute. See Notes 3 and 7 to the financial statements under "Retail Rate
Orders" and "Fuel and Purchased Power Commitments," respectively, for additional
information.
On December 24, 2002, the GPSC approved an order allowing the Company to
implement a natural gas and oil procurement and hedging program effective
January 1, 2003. This order allows the Company to use financial instruments to
hedge price and commodity risk associated with these fuels. 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 the Company retaining 25 percent of the net gains. There were no net gains
in 2003.
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 $54 million, $59 million, and $60
million in 2003, 2002, and 2001, respectively. Future pension income is
dependent on several factors including trust earnings and changes to the plan.
The decline in pension income is expected to continue and to become an expense
by as early as 2007. Postretirement benefit costs for the Company were $41
million, $43 million and $43 million in 2003, 2002, and 2001, respectively, and
are expected 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 generally do not have a significant long-term effect on net
income. For additional information, see Note 2 to the financial statements.
On December 8, 2003, President Bush signed into law the Medicare
Prescription Drug, Improvement, and Modernization Act of 2003 (Medicare Act).
The Medicare Act introduces a prescription drug benefit for Medicare-eligible
retirees starting in 2006, as well as a federal subsidy to plan sponsors like
the Company that provide prescription drug benefits. In accordance with FASB
Staff Position No. 106-1, the Company has elected to defer recognizing the
effects of the Medicare Act for its postretirement plans under FASB Statement
No. 106, Employers' Accounting for Postretirement Benefits Other than Pension
until authoritative guidance on accounting for the federal subsidy is issued or
until a significant event occurs that would require remeasurement of the plans'
assets and obligations. The Company anticipates that the benefits it pays after
2006 will be lower as a result of the Medicare Act; however, the retiree medical
obligations and costs reported in Note 2 to the financial statements do not
reflect these changes. The final accounting guidance could require changes to
previously reported information.
Nuclear security legislation was recently introduced and considered in
Congress both as a free-standing bill in the Senate and as a part of
comprehensive energy legislation in a House-Senate Conference Report. Neither of
the proposals has been enacted. The Nuclear Regulatory Commission (NRC) also has
ordered additional security measures for licensees in 2003. The Company is in
the process of implementation and must be in full compliance with these orders
by October 29, 2004. The requirements of the latest orders will have an impact
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2003 Annual Report
on the Company's nuclear power plants and result in increased operation and
maintenance expenses as well as additional capital expenditures. The precise
impact of the new requirements will depend upon the details of the
implementation of the new requirements, which have not been finalized.
The Georgia General Assembly has recently adopted legislation that changes
the law concerning condemnation of land for electric transmission lines. The
legislation requires that a utility planning to construct or expand a
transmission line hold public meetings in each county where the line would be
located and that the utility attempt to negotiate a settlement with each
affected property owner. The legislation also provides for the reconveyance of
property interests that are condemned for a transmission line but are not used
for that purpose within a specified number of years. The legislation, unless
vetoed by Governor Perdue, will become effective on July 1, 2004.
The Company is involved in various matters being litigated, regulatory
matters, and related issues that could affect future earnings. See Note 3 to the
financial statements for information regarding material issues.
ACCOUNTING POLICIES
- -------------------
Application of Critical Accounting Policies
and Estimates
The Company prepares its financial statements in accordance with accounting
principles generally accepted in the United States. Significant accounting
policies are described in Note 1 to the financial statements. In the application
of these policies, certain estimates are made that may have a material impact on
the Company's results of operations and related disclosures. Different
assumptions and measurements could produce estimates that are significantly
different from those recorded in the financial statements. Senior management has
discussed the development and selection of the critical accounting policies and
estimates described below with the Controls and Compliance Committee of the
Company's Board of Directors and the Audit Committee of Southern Company's Board
of Directors.
Electric Utility Regulation
The Company is subject to retail regulation by the GPSC and wholesale regulation
by the FERC. These regulatory agencies set the rates the Company is permitted to
charge customers based on allowable costs. As a result, the Company applies FASB
Statement No. 71, Accounting for the Effects of Certain Types of Regulation.
Through the ratemaking process, the regulators may require the inclusion of
costs or revenues in periods different than when they would be recognized by a
non-regulated company. This treatment may result in the deferral of expenses and
the recording of related regulatory assets based on anticipated future recovery
through rates or the deferral of gains or creation of liabilities and the
recording of related regulatory liabilities. The application of Statement No. 71
has a further effect on the Company's financial statements as a result of the
estimates of allowable costs used in the ratemaking process. These estimates may
differ from those actually incurred by the Company; therefore, the accounting
estimates inherent in specific costs such as depreciation, nuclear
decommissioning, and pension and postretirement benefits have less of a direct
impact on the Company's results of operations than they would on a non-regulated
company.
As reflected in Note 1 to the financial statements under "Regulatory Assets
and Liabilities," significant regulatory assets and liabilities have been
recorded. Management reviews the ultimate recoverability of these regulatory
assets and liabilities based on applicable regulatory guidelines. However,
adverse legislation and judicial or regulatory actions could materially impact
the amounts of such regulatory assets and liabilities and could adversely impact
the Company's financial statements.
Contingent Obligations
The Company is subject to a number of federal and state laws and regulations, as
well as other factors and conditions that potentially subject it to
environmental, litigation, income tax, and other risks. See "Future Earnings
Potential" and Note 3 to the financial statements for more information regarding
certain of these contingencies. The Company periodically evaluates its exposure
to such risks and records reserves for those matters where a loss is considered
probable and reasonably estimable in accordance with generally accepted
accounting principles. The adequacy of reserves can be significantly affected by
external events or conditions that can be unpredictable; thus, the ultimate
outcome of such matters could materially affect the Company's financial
statements. These events or conditions include the following:
II-121
o Changes in existing state or federal regulation by governmental authorities
having jurisdiction over air quality, water quality, control of toxic
substances, hazardous and solid wastes, and other environmental matters.
o Changes in existing income tax regulations or changes in Internal Revenue
Service interpretations of existing regulations.
o Identification of additional sites that require environmental remediation or
the filing of other complaints in which the Company may be asserted to be a
potentially responsible party.
o Identification and evaluation of other potential lawsuits or complaints in
which the Company may be named as a defendant.
o Resolution or progression of existing matters through the legislative
process, the court systems, the EPA, or the EPD.
New Accounting Standards
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,
established 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 is recorded in the
period in which the liability is incurred. The costs are capitalized as part of
the related long-lived asset and depreciated over the asset's useful life.
Additionally, non-regulated companies are no longer permitted to continue
accruing future retirement costs for long-lived assets that they do not have a
legal obligation to retire. For additional information regarding the impact of
adopting this standard effective January 1, 2003, see Note 1 to the financial
statements under "Asset Retirement Obligations and Other Costs of Removal."
FASB Statement No. 149, Amendment of Statement 133 on Derivative
Instruments and Hedging Activities, which further amends and clarifies the
accounting and reporting for derivative instruments, became effective generally
for financial instruments entered into or modified after June 30, 2003. Current
interpretations of Statement No. 149 indicate that certain electricity forward
transactions subject to unplanned netting --including those typically referred
to as "book outs" -- may only qualify as cash flow hedges if an entity can
demonstrate that physical delivery or receipt of power occurred. The Company's
forward electricity contracts continue to be exempt from fair value accounting
requirements or to qualify as cash flow hedges, with the related gains and
losses deferred in other comprehensive income. The implementation of Statement
No. 149 did not have a material effect on the Company's financial statements.
In July 2003, the Emerging Issues Task Force (EITF) of the FASB issued EITF
No. 03-11, which became effective on October 1, 2003. The standard addresses the
reporting of realized gains and losses on derivative instruments and is being
interpreted to require book outs to be recorded on a net basis in operating
revenues. Adoption of this standard did not have a material impact on the
Company's financial statements.
FASB Interpretation No. 46, Consolidation of Variable Interest Entities,
which was originally issued in January 2003, requires the primary beneficiary of
a variable interest entity to consolidate the related assets and liabilities. In
December 2003, the FASB revised Interpretation No. 46 and deferred the effective
date until March 31, 2004 for interests held in variable interest entities other
than special purpose entities.
Current analysis indicates that the trusts established by the Company to
issue preferred securities are variable interest entities under Interpretation
No. 46, and that the Company is not the primary beneficiary of the trusts. If
this conclusion is finalized, effective March 31, 2004, the trust assets and
liabilities -- including the preferred securities issued by the trusts -- will
be deconsolidated. The investments in the trusts and the loans from the trusts
to the Company will be reflected as equity method investments and as long-term
notes payable to affiliates, respectively, on the Balance Sheets. Based on
December 31, 2003 values, this treatment would result in an increase of
approximately $29 million to both total assets and liabilities. See Note 6 to
the financial statements under "Mandatorily Redeemable Preferred Securities" for
additional information.
In May 2003, the FASB issued Statement No. 150, Accounting for Certain
Financial Instruments with Characteristics of Both Liabilities and Equity, which
requires classification of certain financial instruments within its scope,
including shares that are mandatorily redeemable, as liabilities. Statement No.
150 was effective for financial instruments entered into or modified after May
31, 2003, and otherwise on July 1, 2003. In accordance with Statement No. 150,
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2003 Annual Report
the Company's mandatorily redeemable preferred securities are reflected as
liabilities on the Balance Sheets. The adoption of Statement No. 150 had no
impact on the Statements of Income and Cash Flows.
FINANCIAL CONDITION AND LIQUIDITY
- ---------------------------------
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, preferred stock and preferred securities. The
Company operated at high levels of reliability while achieving industry-leading
customer satisfaction levels and continuing to have retail prices below the
national average.
In 2003, gross utility plant additions were $743 million. These additions
were primarily related to transmission and distribution facilities and the
purchase of nuclear fuel and equipment to comply with environmental standards.
The majority of funds needed for gross property additions for the last several
years have been provided from operating activities. The Statements of Cash Flows
provide additional details.
The Company's ratio of common equity to total capitalization -- including
short-term debt -- was 48.3 percent in 2003, 48.3 percent in 2002, and 47.7
percent in 2001. See Note 6 to the financial statements for additional
information.
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 securities, term loans, and short-term borrowings.
The Company had $137 million of GPSC approved financing authority as of December
31, 2003. The Company used this remaining authority in February 2004. The type
and timing of future financings will depend on market conditions and regulatory
approval of additional financing authority. Recently, the Company has relied on
the issuance of unsecured debt and preferred securities, in addition to
unsecured pollution control bonds issued for its benefit by public authorities,
to meet its long-term external financing requirements.
In February 2002, the Company defeased its first mortgage bond indenture
and all related liens or encumbrances on the Company's property were discharged.
As a result, the Company cannot issue any securities pursuant to this indenture.
See "First Mortgage Bond Indenture" under Note 6 to the financial statements for
additional information.
The Company obtains financing separately without credit support from any
affiliate. The Southern Company system does not maintain a centralized cash or
money pool. Therefore, funds of the Company are not commingled with funds of any
other company. In accordance with the Public Utility Holding Company Act, most
loans between affiliated companies must be approved in advance by the Securities
and Exchange Commission (SEC).
The Company's current liabilities frequently exceed current assets because
of the continued use of short-term debt as a funding source to meet cash needs
which can fluctuate significantly due to the seasonality of the business.
To meet short-term cash needs and contingencies, the Company had
approximately $725 million of unused credit arrangements with banks at the
beginning of 2004. See Note 6 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. Proceeds from such issuances for the
benefit of the Company are loaned directly to the Company and are not commingled
with proceeds from issuances for the benefits of any other operating company.
The obligations of each company under these arrangements are several; there is
no cross affiliate credit support. At December 31, 2003, the Company had
outstanding $137 million of commercial paper and no extendible commercial notes.
At the beginning of 2004, the Company had not used any of its available
credit arrangements. Bank credit arrangements are as follows:
Expires
--------------------------------
Total Unused 2004
--------------------------------------------------------
(in millions)
$725 $725 $725
----------------------------------------------------------
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2003 Annual Report
All of these credit arrangements allow for the execution of term loans for
an additional two year period.
Financing Activities
In 2003, the Company's financing costs increased due to the issuance of new debt
during the year. New issues during 2001 through 2003 totaled $3.2 billion and
retirement or repayment of higher-cost securities totaled $2.4 billion.
Composite financing rates for long-term debt, preferred stock, and
preferred securities for the years 2001 through 2003, as of year-end, were as
follows:
2003 2002 2001
---------------------------------
Composite interest rate
on long-term debt 4.01% 4.47% 4.26%
Composite preferred
stock dividend rate 4.60 4.60 4.60
Composite preferred
securities distribution 6.35 6.35 7.49
rate
- ----------------------------------------------------------------
Subsequent to December 31, 2003, the Company has issued $550 million of new
securities with the proceeds used primarily to retire higher coupon long-term
debt and for construction and general corporate purposes.
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
purchases and sales, fixed-price physical gas purchases, and agreements covering
interest rate swaps. At December 31, 2003, the maximum potential collateral
requirements were approximately $227 million. At December 31, 2003, there were
no material collateral requirements for the gas purchase contracts or other
financial instrument agreements.
Market Price Risk
Due to cost-based 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.
To 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. At December 31, 2003 the
Company had no variable long-term debt outstanding that had not been hedged.
Therefore, there would be no effect on annualized interest expense if the
Company sustained a 100 basis point change in interest rates for all variable
rate long-term debt. The Company is not aware of any facts or circumstances that
would significantly affect such exposures in 2004. See Notes 1 and 6 to the
financial statements under "Financial Instruments" for additional information.
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,
into similar contracts for gas purchases. Fair value of changes in derivative
energy contracts and year-end valuations were as follows:
Changes in Fair Value
- ------------------------------------------------------------------
2003 2002
- ------------------------------------------------------------------
(in millions)
Contracts beginning of year $0.1 $0.4
Contracts realized or settled (0.4) 0.9
New contracts at inception - -
Changes in valuation techniques - -
Current period changes 3.5 (1.2)
- ------------------------------------------------------------------
Contracts end of year $3.2 $0.1
==================================================================
Source of 2003 Year-End Valuation Prices
- ------------------------------------------------------------------
Maturity
Total --------------------------
Fair Value Year 1 1-3 Years
- ------------------------------------------------------------------
(in millions)
Actively quoted $3.2 $2.8 $0.4
External sources - - -
Models and other
methods - - -
- ------------------------------------------------------------------
Contracts end of year $3.2 $2.8 $0.4
==================================================================
II-124
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2003 Annual Report
Unrealized gains and losses from mark to market adjustments on derivative
contracts related to the Company's 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 mechanism. Gains and losses on derivative contracts that are not
designated as hedges are recognized in the income statement as incurred. At
December 31, 2003, the fair value of derivative energy contracts reflected in
the financial statements was as follows:
Amounts
----------------------------------------------------------
(in millions)
Regulatory liabilities, net $3.2
Other comprehensive income -
Net income -
----------------------------------------------------------
Total fair value $3.2
==========================================================
Gains (losses) recognized in income in 2003, 2002, and 2001 were not
material. The Company is exposed to market price risk in the event of
nonperformance by counterparties 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 6 to the financial statements under "Financial Instruments."
Capital Requirements and Contractual
Obligations
The construction program of the Company is currently estimated to be $747
million for 2004, $812 million for 2005, and $1,043 million for 2006.
Environmental expenditures included in these amounts are $91 million, $113
million, and $316 million for 2004, 2005, and 2006, respectively. 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.
The Company has no generating plants under construction. However,
construction related to new transmission and distribution facilities and capital
improvements to existing generation, transmission and distribution facilities,
including those needed to meet the environmental standards previously discussed,
are ongoing.
As a result of requirements by the NRC, the Company has established
external trust funds for nuclear decommissioning costs. For additional
information, see Note 1 to the financial statements under "Nuclear
Decommissioning." Also as discussed in Note 1 to the financial statements under
"Revenues and Fuel Costs," in 1993 the DOE implemented a special assessment over
a 15-year period on utilities with nuclear plants to be used for the
decontamination and decommissioning of its nuclear fuel enrichment facilities.
In addition, as discussed in Note 2 to the financial statements, the
Company provides postretirement benefits to substantially all employees and
funds trusts to the extent required by the GPSC and the FERC.
II-125
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2003 Annual Report
Other funding requirements related to obligations associated with scheduled
maturities of long-term debt and preferred securities, as well as the related
interest and distributions, preferred stock dividends, leases, and other
purchase commitments are as follows. See Notes 1, 6, and 7 to the financial
statements for additional information.
2005- 2007- After
2004 2006 2008 2008 Total
- --------------------------------------------------------------------------------------------------------------------------------
(in millions)
Long-term debt and preferred
securities(a) --
Principal $ 2 $ 605 $ 306 $ 3,792 $ 4,705
Interest and distributions 211 409 363 3,885 4,868
Preferred stock dividends(b) 1 1 1 - 3
Operating leases 34 56 44 72 206
Purchase commitments(c) --
Capital (d) 718 1,815 2,286 - 4,819
Coal and nuclear fuel 1,321 1,940 975 183 4,419
Natural gas(e) 156 297 280 1,625 2,358
Purchased power 293 828 852 2,573 4,546
Trusts(f) --
Nuclear decommissioning 9 17 17 95 138
Postretirement benefits 9 21 - - 30
DOE assessments 3 7 - - 10
- --------------------------------------------------------------------------------------------------------------------------------
Total $2,757 $5,996 $5,124 $12,225 $26,102
================================================================================================================================
(a) All amounts are reflected based on final maturity dates. The Company will continue to retire higher-cost securities and
replace these obligations with lower-cost capital if market conditions permit. Variable rate interest obligations are
estimated based on rates as of January 1, 2004, as reflected in the Statements of Capitalization.
(b) Preferred stock does not mature; therefore, amounts are provided for the next five years only.
(c) The Company generally does not enter into non-cancelable commitments for other operation and maintenance expenditures.
Total other operation and maintenance expenses for the last three years were $1.2 billion, $1.3 billion, and $1.2 billion,
respectively.
(d) The Company forecasts capital expenditures over a five-year period. Amounts represent current estimates of total
expenditures, excluding those amounts related to contractual purchase commitments for uranium and nuclear fuel conversion,
enrichment, and fabrication services. At December 31, 2003, significant purchase commitments were outstanding in
connection with the construction program.
(e) Natural gas purchase commitments are based on various indices at the time of delivery. Amounts reflected have been
estimated based on New York Mercantile future prices at December 31, 2003.
(f) Projections of nuclear decommissioning trust contributions are based on the current GPSC order which will be reevaluated in
the Company's upcoming rate case and is subject to change. The Company forecasts postretirement trust contributions over
a three-year period. No contributions related to the Company's pension trust are currently expected during this period.
See Note 2 to the financial statements for additional information related to the pension plans.
II-126
Cautionary Statement Regarding Forward-Looking Information
The Company's 2003 Annual Report includes forward-looking statements in addition
to historical information. Forward-looking information includes, among other
things, statements concerning the estimated construction and other expenditures
and the Company's projections for energy sales and its goals for future
generating capacity 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. 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:
o 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, tax and other laws and regulations to which the Company is
subject, as well as changes in application of existing laws and
regulations;
o current and future litigation, regulatory investigations, proceedings or
inquiries, including the pending EPA civil action against the Company;
o the effects, extent, and timing of the entry of additional competition in
the markets in which the Company operates;
o the impact of fluctuations in commodity prices, interest rates, and
customer demand;
o available sources and costs of fuels;
o ability to control costs;
o investment performance of the Company's employee benefit plans;
o advances in technology;
o state and federal rate regulations and pending and future rate cases and
negotiations;
o effects of and changes in political, legal, and economic conditions and
developments in the United States, including the current soft economy;
o internal restructuring or other restructuring options that may be pursued;
o potential business strategies, including acquisitions or dispositions of
assets, which cannot be assured to be completed or beneficial to the
Company;
o the ability of counterparties of the Company to make payments as and when
due;
o the ability to obtain new short- and long-term contracts with neighboring
utilities;
o the direct or indirect effects on the Company's business resulting from the
terrorist incidents on September 11, 2001, or any similar incidents or
responses to such incidents;
o financial market conditions and the results of financing efforts, including
the Company's credit ratings;
o the ability of the Company to obtain additional generating capacity at
competitive prices;
o weather and other natural phenomena;
o the direct or indirect effects on the Company's business resulting from
the August 2003 power outage in the Northeast, or any similar incidents;
o the effect of accounting pronouncements issued periodically by
standard-setting bodies; and
o other factors discussed elsewhere herein and in other reports (including
the Form 10-K) filed from time to time by the Company with the SEC.
II-127
STATEMENTS OF INCOME
For the Years Ended December 31, 2003, 2002, and 2001
Georgia Power Company 2003 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------
2003 2002 2001
- ----------------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Revenues:
Retail sales $4,309,972 $4,288,097 $4,349,312
Sales for resale --
Non-affiliates 259,376 270,678 366,085
Affiliates 174,855 98,323 99,411
Other revenues 169,304 165,362 150,986
- ----------------------------------------------------------------------------------------------------------------------------
Total operating revenues 4,913,507 4,822,460 4,965,794
- ----------------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Fuel 1,103,963 1,002,703 939,092
Purchased power --
Non-affiliates 258,621 264,814 442,196
Affiliates 516,944 419,839 329,232
Other operations 827,972 848,436 810,043
Maintenance 419,206 476,962 430,413
Depreciation and amortization 349,984 403,507 600,631
Taxes other than income taxes 212,827 201,857 202,483
- ----------------------------------------------------------------------------------------------------------------------------
Total operating expenses 3,689,517 3,618,118 3,754,090
- ----------------------------------------------------------------------------------------------------------------------------
Operating Income 1,223,990 1,204,342 1,211,704
Other Income and (Expense):
Allowance for equity funds used during construction 10,752 7,622 9,081
Interest income 15,625 3,857 4,264
Interest expense, net of amounts capitalized (182,583) (168,391) (183,879)
Distributions on mandatorily redeemable preferred securities (59,675) (62,553) (59,104)
Other income (expense), net (10,551) (9,259) (7,719)
- ----------------------------------------------------------------------------------------------------------------------------
Total other income and (expense) (226,432) (228,724) (237,357)
- ----------------------------------------------------------------------------------------------------------------------------
Earnings Before Income Taxes 997,558 975,618 974,347
Income taxes 366,311 357,319 363,599
- ----------------------------------------------------------------------------------------------------------------------------
Earnings Before Cumulative Effect of
Accounting Change 631,247 618,299 610,748
Cumulative effect of accounting change--
less income taxes of $162 - - 257
- ----------------------------------------------------------------------------------------------------------------------------
Net Income 631,247 618,299 611,005
Dividends on Preferred Stock 670 670 670
- ----------------------------------------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred Stock $630,577 $617,629 $610,335
============================================================================================================================
The accompanying notes are an integral part of these financial statements.
II-128
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2003, 2002, and 2001
Georgia Power Company 2003 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------
2003 2002 2001
- -----------------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Activities:
Net income $631,247 $ 618,299 $ 611,005
Adjustments to reconcile net income
to net cash provided from operating activities --
Depreciation and amortization 390,201 411,435 697,143
Deferred income taxes and investment tax credits, net 230,221 65,550 (48,329)
Pension, postretirement, and other employee benefits (29,118) (64,771) (57,239)
Tax benefit of stock options 11,649 8,184 -
Settlement of interest rate hedges (11,250) 860 -
Other, net 2,768 (50,282) (43,458)
Changes in certain current assets and liabilities --
Receivables, net (4,870) 68,527 60,914
Fossil fuel stock (17,490) 82,711 (103,296)
Materials and supplies (7,677) 15,874 (15,628)
Other current assets (2,352) (18,880) 3,755
Accounts payable (49,598) 64,902 (15,406)
Accrued taxes 52,348 (6,540) 18,392
Other current liabilities 16,734 16,166 (46,691)
- -----------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities 1,212,813 1,212,035 1,061,162
- -----------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (742,810) (883,968) (1,389,751)
Cost of removal net of salvage (28,265) (60,912) (50,093)
Sales of property - 387,212 534,760
Change in construction payables, net of joint owner portion (32,223) (7,411) 24,457
Other 15,961 34,580 20,862
- -----------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities (787,337) (530,499) (859,765)
- -----------------------------------------------------------------------------------------------------------------------------
Financing Activities:
Increase (decrease) in notes payable, net (220,400) (389,860) 43,698
Proceeds --
Senior notes 1,000,000 500,000 600,000
Pollution control bonds - - 404,535
Mandatorily redeemable preferred securities - 740,000 -
Capital contributions from parent company 40,809 165,299 225,060
Redemptions --
First mortgage bonds - (1,860) (390,140)
Pollution control bonds - (7,800) (385,035)
Senior notes (665,000) (330,000) -
Mandatorily redeemable preferred securities - (589,250) -
Capital distributions to parent company - (200,000) (160,000)
Payment of preferred stock dividends (696) (721) (578)
Payment of common stock dividends (565,800) (542,900) (527,300)
Other (22,563) (30,831) (17,747)
- -----------------------------------------------------------------------------------------------------------------------------
Net cash used for financing activities (433,650) (687,923) (207,507)
- -----------------------------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents (8,174) (6,387) (6,110)
Cash and Cash Equivalents at Beginning of Period 16,873 23,260 29,370
- -----------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ 8,699 $ 16,873 $ 23,260
=============================================================================================================================
Supplemental Cash Flow Information:
Cash paid during the period for --
Interest (net of $5,428, $9,368, and $38,331 capitalized,
respectively) $215,463 $203,707 $234,456
Income taxes (net of refunds) 145,048 326,698 381,995
- -----------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
II-129
BALANCE SHEETS
At December 31, 2003 and 2002
Georgia Power Company 2003 Annual Report
- ------------------------------------------------------------------------------------------------------------------------------
Assets 2003 2002
- ------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Current Assets:
Cash and cash equivalents $ 8,699 $ 16,873
Receivables --
Customer accounts receivable 261,771 302,995
Unbilled revenues 117,327 104,454
Under recovered regulatory clause revenues 151,447 117,580
Other accounts and notes receivable 101,783 122,585
Affiliated companies 52,413 40,501
Accumulated provision for uncollectible accounts (5,350) (5,825)
Fossil fuel stock, at average cost 137,537 120,048
Materials and supplies, at average cost 271,040 263,364
Vacation pay 50,150 53,677
Prepaid expenses 46,157 42,809
Other 83 436
- ------------------------------------------------------------------------------------------------------------------------------
Total current assets 1,193,057 1,179,497
- ------------------------------------------------------------------------------------------------------------------------------
Property, Plant, and Equipment:
In service 18,171,862 17,222,661
Less accumulated provision for depreciation 6,898,725 6,533,412
- ------------------------------------------------------------------------------------------------------------------------------
11,273,137 10,689,249
Nuclear fuel, at amortized cost 129,056 119,588
Construction work in progress 341,783 667,581
- ------------------------------------------------------------------------------------------------------------------------------
Total property, plant, and equipment 11,743,976 11,476,418
- ------------------------------------------------------------------------------------------------------------------------------
Other Property and Investments:
Equity investments in unconsolidated subsidiaries 38,714 36,167
Nuclear decommissioning trusts, at fair value 423,319 346,870
Other 37,142 28,612
- ------------------------------------------------------------------------------------------------------------------------------
Total other property and investments 499,175 411,649
- ------------------------------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets:
Deferred charges related to income taxes 509,887 524,510
Prepaid pension costs 405,164 341,944
Unamortized debt issuance expense 75,245 67,362
Unamortized loss on reacquired debt 177,707 178,590
Other 177,817 162,686
- ------------------------------------------------------------------------------------------------------------------------------
Total deferred charges and other assets 1,345,820 1,275,092
- ------------------------------------------------------------------------------------------------------------------------------
Total Assets $14,782,028 $14,342,656
==============================================================================================================================
The accompanying notes are an integral part of these financial statements.
II-130
BALANCE SHEETS
At December 31, 2003 and 2002
Georgia Power Company 2003 Annual Report
- ------------------------------------------------------------------------------------------------------------------------------
Liabilities and Stockholder's Equity 2003 2002
- ------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Current Liabilities:
Securities due within one year $ 2,304 $ 322,125
Notes payable 137,277 357,677
Accounts payable --
Affiliated 121,928 135,260
Other 238,069 314,327
Customer deposits 103,756 94,859
Accrued taxes --
Income taxes 107,532 20,245
Other 166,892 134,269
Accrued interest 70,844 59,608
Accrued vacation pay 38,206 42,442
Accrued compensation 134,004 130,893
Other 105,234 112,131
- ------------------------------------------------------------------------------------------------------------------------------
Total current liabilities 1,226,046 1,723,836
- ------------------------------------------------------------------------------------------------------------------------------
Long-term debt (See accompanying statements) 3,762,333 3,109,619
- ------------------------------------------------------------------------------------------------------------------------------
Mandatorily redeemable preferred securities (See accompanying statements) 940,000 940,000
- ------------------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 2,303,085 2,176,438
Deferred credits related to income taxes 186,625 208,410
Accumulated deferred investment tax credits 312,506 324,994
Employee benefit obligations 295,788 248,415
Asset retirement obligations 475,585 -
Other cost of removal obligations 412,161 800,117
Miscellaneous regulatory liabilities 249,687 331,241
Other 63,432 30,570
- ------------------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 4,298,869 4,120,185
- ------------------------------------------------------------------------------------------------------------------------------
Total liabilities 10,227,248 9,893,640
- ------------------------------------------------------------------------------------------------------------------------------
Preferred stock (See accompanying statements) 14,569 14,569
- ------------------------------------------------------------------------------------------------------------------------------
Common stockholder's equity (See accompanying statements) 4,540,211 4,434,447
- ------------------------------------------------------------------------------------------------------------------------------
Total Liabilities and Stockholder's Equity $14,782,028 $14,342,656
==============================================================================================================================
Commitments and Contingent Matters (See notes)
- ------------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
II-131
STATEMENTS OF CAPITALIZATION
At December 31, 2003 and 2002
Georgia Power Company 2003 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------------
2003 2002 2003 2002
- ----------------------------------------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
Long-Term Debt:
Long-term notes payable --
5.25% to 5.75% due 2003 $ - $ 320,000
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 300,000 300,000
5.125% to 6.875% due 2011-2047 1,100,000 745,000
Variable rate (1.25% to 1.30% at 1/1/04) 300,000 -
- ----------------------------------------------------------------------------------------------------------------------------------
Total long-term notes payable 2,000,000 1,665,000
- ----------------------------------------------------------------------------------------------------------------------------------
Other long-term debt --
Pollution control revenue bonds --
Non-collateralized:
1.20% to 5.45% due 2012-2034 812,560 751,760
Variable rates (1.10% to 1.40% at 1/1/04)
due 2011-2032 873,330 934,130
- ---------------------------------------------------------------------------------------------------------------------------------
Total other long-term debt 1,685,890 1,685,890
- ---------------------------------------------------------------------------------------------------------------------------------
Capitalized lease obligations 79,286 81,411
- ---------------------------------------------------------------------------------------------------------------------------------
Unamortized debt premium (discount), net (539) (557)
- ---------------------------------------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
requirement -- $151.2 million) 3,764,637 3,431,744
Less amount due within one year 2,304 322,125
- ---------------------------------------------------------------------------------------------------------------------------------
Long-term debt excluding amount due within one year 3,762,333 3,109,619 40.6% 36.5%
- ---------------------------------------------------------------------------------------------------------------------------------
Mandatorily Redeemable Preferred Securities:
$25 liquidation value --
6.85% due 2029 200,000 200,000
7.125% due 2042 440,000 440,000
$1,000 liquidation value --
4.875% due 2042* 300,000 300,000
- ---------------------------------------------------------------------------------------------------------------------------------
Total (annual distribution requirement -- $59.7 million) 940,000 940,000 10.2 11.1
- ---------------------------------------------------------------------------------------------------------------------------------
Cumulative Preferred Stock:
$100 stated value at 4.60% 14,569 14,569
- ---------------------------------------------------------------------------------------------------------------------------------
Total (annual dividend requirement -- $0.7 million) 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 2,208,498 2,156,040
Premium on preferred stock 40 40
Retained earnings 2,010,297 1,945,520
Accumulated other comprehensive income (loss) (22,874) (11,403)
- ---------------------------------------------------------------------------------------------------------------------------------
Total common stockholder's equity 4,540,211 4,434,447 49.0 52.2
- ---------------------------------------------------------------------------------------------------------------------------------
Total Capitalization $9,257,113 $8,498,635 100.0% 100.0%
=================================================================================================================================
*The fixed rate thereafter is determined through remarketings for specific periods of varying length at floating rates determined
by reference to 3-month LIBOR plus 3.05%.
The accompanying notes are an integral part of these financial statements.
II-132
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
For the Years Ended December 31, 2003, 2002, and 2001
Georgia Power Company 2003 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------------
Premium on Other
Common Paid-In Preferred Retained Comprehensive
Stock Capital Stock Earnings Income (loss) Total
- -----------------------------------------------------------------------------------------------------------------------------------
(in thousands)
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 distributions to parent company - (200,000) - - - (200,000)
Capital contributions from parent company - 173,483 - - - 173,483
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
Net income after dividends on preferred stock - - - 630,577 - 630,577
Capital contributions from parent company - 52,458 - - - 52,458
Other comprehensive income (loss) - - - - (11,471) (11,471)
Cash dividends on common stock - - - (565,800) - (565,800)
- ----------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2003 $344,250 $2,208,498 $40 $2,010,297 $(22,874) $4,540,211
==================================================================================================================================
The accompanying notes are an integral part of these financial statements.
STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2003, 2002, and 2001
Georgia Power Company 2003 Annual Report
- ---------------------------------------------------------------------------------------------------------------------------------
2003 2002 2001
- ---------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Net income after dividends on preferred stock $630,577 $617,629 $610,335
- ---------------------------------------------------------------------------------------------------------------------------------
Other comprehensive income (loss):
Change in additional minimum pension liability, net of tax of (8,138) (7,693) -
$(5,133) and $(4,853), respectively
Cumulative effect of accounting change for qualifying hedges, - - 286
net of tax of $180
Changes in fair value of qualifying hedges, net of tax of (5,550) (3,555) (439)
$(3,241), $(2,502) and $(277), respectively
Less: Reclassification adjustment for amounts included in 2,217 (2) -
net income, net of tax of $1,208 and $0, respectively
- ---------------------------------------------------------------------------------------------------------------------------------
Total other comprehensive income (loss) (11,471) (11,250) (153)
- ---------------------------------------------------------------------------------------------------------------------------------
Comprehensive Income $619,106 $606,379 $610,182
=================================================================================================================================
The accompanying notes are an integral part of these financial statements.
II-133
NOTES TO FINANCIAL STATEMENTS
GEORGIA POWER COMPANY 2003 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 retail operating companies, Southern Power Company
(Southern Power), Southern Company Services (SCS), 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 retail operating companies -- Alabama Power, the Company, Gulf
Power, Mississippi Power, and Savannah Electric -- provide electric service in
four Southeastern states. The Company 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. 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 retail 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, the system service company, provides, at cost,
specialized services to Southern Company and subsidiary companies. Southern LINC
provides digital wireless communications services to the retail 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 is a competitive retail natural gas marketer serving customers in
Georgia. Southern Holdings is an intermediate holding subsidiary for Southern
Company's investments in synthetic fuels and leveraged leases and an energy
services business. Southern Nuclear operates and 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 its 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 $303 million in 2003, $318 million in 2002, and $286
million in 2001. 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 $289 million in 2003, $301 million in 2002, and $281
million in 2001.
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. Reimbursements under these agreements with Southern Power
amounted to $5.3 million in 2003, $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 7 under "Construction Program" for
additional information.
II-134
NOTES (continued)
Georgia Power Company 2003 Annual Report
Southern Company holds a 30 percent ownership in Alabama Fuel Products, LLC
(AFP), which produces synthetic fuel. The Company has an agreement with an
indirect subsidiary of Southern Company that provides services for AFP. Under
this agreement, the Company provides certain accounting functions, including
processing and paying fuel transportation invoices, and the Company is
reimbursed for its expenses. Amounts billed under this agreement totaled
approximately $38 million in 2003. In addition, the Company purchases synthetic
fuel from AFP for use at Plant Branch. Fuel purchases totaled $91 million in
2003.
Effective June 2002, the Company entered into purchased power agreements
(PPAs) with Southern Power for capacity and energy. Purchased power costs in
2003 and 2002 amounted to $203 million and $128 million, respectively.
Additionally, the Company recorded $7 million and $12 million of prepaid
capacity expenses included in Other Deferred Charges and Other Assets on the
Balance Sheets at December 31, 2003 and 2002, respectively. See Note 7 under
"Fuel and 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, the Company operates
Plant Scherer and Gulf Power reimburses the Company for its proportionate share
of the related expenses which were $5.6 million in 2003 and $4.5 million in
2002. The Company has an agreement with Savannah Electric under which the
Company jointly owns a portion of Plant McIntosh. Under this agreement, Savannah
Electric operates Plant McIntosh and the Company reimburses Savannah Electric
for its proportionate share of the related expenses which were $3.6 million in
2003 and $1.8 million in 2002. See Note 4 for additional information.
Also see Note 4 for information regarding the Company's ownership in and
purchased power agreement with Southern Electric Generating Company.
The retail operating companies, including the Company, Southern Power, and
Southern Company 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 7 under "Fuel and
Purchased Power Commitments" for additional information.
Revenues and Fuel Costs
Energy and 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 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 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 despite an
increase in customer bankruptcies.
Fuel expense includes the amortization of the cost of nuclear fuel and a
charge, based on nuclear generation, for the permanent disposal of spent nuclear
fuel. Total charges for nuclear fuel included in fuel expense amounted to $74
million in 2003, $71 million in 2002, and $75 million in 2001. The Company has
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 Company
is pursuing legal remedies against the government for breach of contract.
Sufficient pool storage capacity for spent fuel is available at Plant Vogtle to
maintain full-core discharge capability for both units into the year 2015. At
Plant Hatch, an on-site dry storage facility became operational in 2000 and can
be expanded to accommodate spent fuel through the life of the plant.
Construction of an on-site dry storage facility 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. The 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
II-135
NOTES (continued)
Georgia Power Company 2003 Annual Report
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
interest -- estimates its remaining liability at December 31, 2003 under this
law to be approximately $10 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.
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:
2003 2002 Note
----------------------------
(in millions)
Deferred income tax charges $ 510 $ 525 (a)
Loss on reacquired debt 178 179 (b)
Corporate building lease 54 54 (f)
Vacation pay 50 54 (d)
Postretirement benefits 23 25 (f)
DOE assessments 13 16 (c)
Generating plant outage costs 49 48 (f)
Other regulatory assets 1 7 (f)
Asset retirement obligation (16) - (a)
Other cost of removal obligations (412) (800) (a)
Accelerated cost recovery (111) (222) (e)
Deferred income tax credits (187) (208) (a)
Environmental remediation reserve (21) (21) (f)
Purchased power (77) (63) (f)
Other regulatory liabilities (3) (1) (f)
- ------------------------------------------------------------------
Total $ 51 $ (26)
==================================================================
Note: The recovery and amortization periods for these regulatory assets and
(liabilities) are as follows:
(a) Asset retirement and removal liabilities are recorded, deferred income
taxes are recovered, and deferred tax liabilities are amortized over the
related property lives, which may range up to 50 years. Asset retirement
and removal liabilities will be settled and trued up following completion
of the related activities.
(b) Recovered over either the remaining life of the original issue or, if
refinanced, over the life of the new issue which may range up to 50 years.
(c) Assessments for the decontamination and decommissioning of the DOE's
nuclear fuel enrichment facilities are recorded annually from 1993 through
2008.
(d) Recorded as earned by employees and recovered as paid, generally within
one year.
(e) Amortized over a three-year period ending in 2004. See Note
3 under "Retail Rate Orders".
(f) Recorded and recovered or amortized as approved by the GPSC.
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, including plant, exists and if
impaired, write down the assets to their fair value. All regulatory assets and
liabilities are to be reflected in rates.
II-136
NOTES (continued)
Georgia Power Company 2003 Annual Report
Depreciation and Amortization
Depreciation of the original cost of plant in service is provided primarily by
using composite straight-line rates, which approximated 2.7 percent in 2003, 2.9
percent in 2002 and 3.3 percent in 2001. 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.
The Company recorded accelerated depreciation and amortization amounting to
$91 million in 2001. Effective January 2002, the Company discontinued recording
accelerated depreciation and amortization in accordance with a new 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
amortization expense beginning January 2002. Additionally, effective January
2002 the Company was ordered to recognize new GPSC certified purchased power
costs in rates evenly over the three years covered by the current retail rate
order. As a result of the purchased power regulatory adjustment, the Company
recorded amortization expenses of $14 million and $63 million in 2003 and 2002,
respectively. The Company will record a credit to amortization expense of $77
million in 2004. See Note 3 under "Retail Rate Orders" for additional
information.
Asset Retirement Obligations
and Other Costs of Removal
In accordance with regulatory requirements, prior to 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 accordance with SEC requirements such amounts
are reflected on the Balance Sheet as regulatory liabilities. Effective January
1, 2003, the Company adopted FASB Statement No. 143, Accounting for Asset
Retirement Obligations. Statement No. 143 established 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 costs 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 the continued accrual of future retirement costs for
long-lived assets that the Company does not have a legal obligation to retire.
However, the Company has received guidance regarding accounting for the
financial statement impacts of Statement No. 143 from the GPSC and will continue
to recognize the accumulated removal costs for other obligations as a regulatory
liability. Therefore, the Company had no cumulative effect to net income
resulting from the adoption of Statement No. 143.
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. The fair value of assets legally
restricted for settling retirement obligations related to nuclear facilities as
of December 31, 2003 was $423 million. 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 the Company's 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 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
in the Balance Sheets. The Company also revised the estimated cost to retire
plants Hatch and Vogtle as a result of a new site-specific decommissioning
study. The effect of the revision is a decrease of $24 million for the Statement
No. 143 liability included in "Asset Retirement Obligations" with a
corresponding decrease in property, plant and equipment. See "Nuclear
Decommissioning" for further information on amounts included in rates.
II-137
NOTES (continued)
Georgia Power Company 2003 Annual Report
Details of the asset retirement obligations included in the Balance Sheets
are as follows:
2003
- --------------------------------------------------------
(in millions)
Balance beginning of year $469
Liabilities incurred -
Liabilities settled -
Accretion 31
Cash flow revisions (24)
- --------------------------------------------------------
Balance end of year $476
========================================================
If Statement No. 143 had been adopted on January 1, 2002, the pro-forma
asset retirement obligations would have been $440 million.
Nuclear Decommissioning
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. The funds set aside
for decommissioning are managed and invested in accordance with applicable
requirements of various regulatory bodies, including the NRC, the FERC and the
GPSC as well as the Internal Revenue Service (IRS). Funds are invested in a tax
efficient manner in a diversified mix of equity and fixed income securities.
Equity securities typically range from 50 to 75 percent of the funds and fixed
income securities from 25 to 50 percent. 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.
Site study cost is the estimate to decommission a specific facility as of
the site study year. The estimated costs of decommissioning are based on the
most current study as of December 31, 2003 and the Company's ownership
interests in plants Hatch and Vogtle were as follows:
Plant Plant
Hatch Vogtle
- ------------------------------------------------------------
Site study year 2003 2003
Decommissioning periods:
Beginning year 2034 2027
Completion year 2065 2048
- ------------------------------------------------------------
(in millions)
Site study costs:
Radiated structures $497 $452
Non-radiated structures 49 58
- ------------------------------------------------------------
Total $546 $510
============================================================
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 the estimates.
Annual provisions for nuclear decommissioning are based on an annuity
method as approved by the GPSC. The amounts expensed in 2003 and fund balances
were as follows:
Plant Plant
Hatch Vogtle
------------------------------------------------------------
(in millions)
Amount expensed in 2003 $ 7 $ 2
Accumulated provisions:
External trust funds, at fair $269 $154
value
Internal reserves 7 4
------------------------------------------------------------
Total $276 $158
============================================================
Effective January 1, 2002, the GPSC decreased the annual decommissioning
costs for ratemaking 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. Significant assumptions used to determine the costs for ratemaking
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
II-138
NOTES (continued)
Georgia Power Company 2003 Annual Report
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. The site study decommissioning costs
reflect the license extension; however, the updated costs will not be reflected
in rates until the GPSC issues a new rate order, which is not expected until
December 2004.
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. For the years 2003, 2002, and 2001, the
average AFUDC rates were 5.51 percent, 3.79 percent, and 6.33 percent,
respectively. AFUDC and interest capitalized, net of taxes, was less than 3.0
percent of net income after dividends on preferred stock for 2003, 2002, and
2001.
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 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 that exceeds the carrying value of the
assets. If an impairment has occurred, the amount of the impairment recognized
is determined by either the amount of regulatory disallowance or by estimating
the fair value of the assets and recording a 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 loss 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.
Materials and Supplies
Generally, materials and supplies include the average 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
II-139
NOTES (continued)
Georgia Power Company 2003 Annual Report
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 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 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
that meet the definition of a derivative are exempt from fair value accounting
requirements and are accounted for under the accrual method. Other derivative
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. Other
derivative contracts 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.
The Company's financial instruments for which the carrying amounts did not
equal fair value at December 31 were as follows:
Carrying Fair
Amount Value
--------------------------
Long-term debt: (in millions)
At December 31, 2003 $3,685 $3,739
At December 31, 2002 $3,350 $3,417
Preferred securities:
At December 31, 2003 $940 $976
At December 31, 2002 $940 $961
- -------------------------------------------------------------
The fair values for securities were based on either closing market prices
or closing prices of comparable instruments.
Comprehensive Income
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. Comprehensive
income consists 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.
2. RETIREMENT BENEFITS
The Company has a defined benefit, trusteed pension plan covering substantially
all employees. The plan is funded in accordance with Employee Retirement Income
Security Act (ERISA) requirements. No contributions to the plan are expected for
the year ending December 31, 2004. The Company also provides certain
non-qualified benefit plans for a selected group of management and highly
compensated employees. Benefits under these non-qualified plans are funded on a
cash basis. In addition, the Company provides certain medical care and life
insurance benefits for retired employees. The Company funds related trusts to
the extent required by the GPSC and the FERC. For the year ended December 31,
2004, such contributions are expected to total approximately $8.9 million.
The measurement date for plan assets and obligations is September 30 for
each year. In 2002, the Company adopted several plan changes that had the effect
of increasing benefits to both current and future retirees.
II-140
NOTES (continued)
Georgia Power Company 2003 Annual Report
Pension Plans
The accumulated benefit obligation for the pension plan was $1.6 billion and
$1.4 billion for 2003 and 2002, respectively. Changes during the year in the
projected benefit obligations and in the fair value of plan assets were as
follows:
Projected
Benefit Obligation
-------------------------
2003 2002
- --------------------------------------------------------------
(in millions)
Balance at beginning of year $1,564 $1,448
Service cost 38 36
Interest cost 100 107
Benefits paid (83) (74)
Amendments 6 33
Actuarial loss 102 14
- --------------------------------------------------------------
Balance at end of year $1,727 $1,564
==============================================================
Plan Assets
-------------------------
2003 2002
- --------------------------------------------------------------
(in millions)
Balance at beginning of year $1,838 $2,044
Actual return on plan assets 294 (137)
Benefits paid (77) (69)
- --------------------------------------------------------------
Balance at end of year $2,055 $1,838
==============================================================
Pension plan assets are managed and invested in accordance with all
applicable requirements including ERISA and the IRS revenue code. The Company's
investment policy covers a diversified mix of assets, including equity and fixed
income securities, real estate, and private equity, as described in the table
below. Derivative instruments are used primarily as hedging tools but may also
be used to gain efficient exposure to the various asset classes. The Company
primarily minimizes the risk of large losses through diversification but also
monitors and manages other aspects of risk.
Plan Assets
------------------------------
Target 2003 2002
- -------------------------------------------------------------
Domestic equity 37% 37% 35%
International equity 20 20 18
Global fixed income 26 24 25
Real estate 10 11 12
Private equity 7 8 10
- -------------------------------------------------------------
Total 100% 100% 100%
=============================================================
The accrued pension costs recognized in the Balance Sheets
were as follows:
2003 2002
- ---------------------------------------------------------------
(in millions)
Funded status $328 $274
Unrecognized transition amount (13) (17)
Unrecognized prior service cost 118 123
Unrecognized net actuarial gain
(loss) (66) (78)
- ---------------------------------------------------------------
Prepaid pension asset, net 367 302
Portion included in employee
benefit obligations 38 40
- ---------------------------------------------------------------
Total prepaid pension recognized in
the Balance Sheets $405 $342
===============================================================
In 2003 and 2002, amounts recognized in the Balance Sheets for accumulated
other comprehensive income and intangible assets to record the minimum pension
liability related to the nonqualified plans were $26 million and $15 million and
$13 and $10 million, respectively.
Components of the plans' net periodic cost were as follows:
2003 2002 2001
- ---------------------------------------------------------------
(in millions)
Service cost $ 38 $ 36 $ 35
Interest cost 100 107 101
Expected return on plan assets (179) (179) (168)
Recognized net gain (19) (27) (31)
Net amortization 6 4 3
- ---------------------------------------------------------------
Net pension (income) $ (54) $ (59) $ (60)
===============================================================
II-141
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
-------------------------
2003 2002
- -------------------------------------------------- -----------
(in millions)
Balance at beginning of year $627 $542
Service cost 9 8
Interest cost 40 40
Benefits paid (29) (27)
Actuarial loss 76 64
- --------------------------------------------------------------
Balance at end of year $723 $627
==============================================================
Plan Assets
-------------------------
2003 2002
- --------------------------------------------------------------
(in millions)
Balance at beginning of year $199 $195
Actual return on plan assets 36 (18)
Employer contributions 59 49
Benefits paid (29) (27)
- --------------------------------------------------------------
Balance at end of year $265 $199
==============================================================
Postretirement benefits plan assets are managed and invested in accordance
with all applicable requirements, including ERISA and the IRS revenue code. The
Company's investment policy covers a diversified mix of assets, including equity
and fixed income securities, real estate, and private equity, as described in
the table below. Derivative instruments are used primarily as hedging tools but
may also be used to gain efficient exposure to the various asset classes. The
Company minimizes the risk of large losses through the primary tool of
diversification but also monitors and manages other aspects of risk.
Plan Assets
--------------------------------
Target 2003 2002
- ----------------------------------------------------------------
Domestic equity 43% 42% 38%
International equity 20 21 21
Global fixed income 33 32 35
Real estate 2 3 3
Private equity 2 2 3
- ----------------------------------------------------------------
Total 100% 100% 100%
================================================================
The accrued postretirement costs recognized in the Balance Sheets
were as follows:
2003 2002
- --------------------------------------------------------------
(in millions)
Funded status $(458) $(427)
Unrecognized transition obligation 87 96
Unrecognized prior service cost 91 98
Unrecognized net loss 171 106
Fourth quarter contributions 9 37
- ---------------------------------------------------- ---------
Employee benefit obligations
recognized in the Balance Sheets $(100) $(90)
==============================================================
Components of the plans' net periodic cost were as follows:
2003 2002 2001
- --------------------------------------------------------------
(in millions)
Service cost $ 9 $ 8 $ 9
Interest cost 40 40 39
Expected return on
plan assets (24) (20) (19)
Net amortization 16 15 14
- --------------------------------------------------------------
Net postretirement cost $ 41 $ 43 $ 43
==============================================================
The weighted average rates assumed in the actuarial calculations used to
determine both the benefit obligations and net periodic costs for the pension
and postretirement benefit plans were:
2003 2002 2001
- ---------------------------------------------------------------
Discount 6.0% 6.5% 7.5%
Annual salary increase 3.8 4.0 5.0
Long-term return on plan
assets 8.5 8.5 8.5
- ---------------------------------------------------------------
The Company determined the long-term rate of return based on historical
asset class returns and current market conditions, taking into account the
diversification benefits of investing in multiple asset classes.
An additional assumption used in measuring the accumulated postretirement
benefit obligations was a weighted average medical care cost trend rate of 8.25
percent for 2003, decreasing gradually to 5.25 percent through the year 2010 and
remaining at that level thereafter. An annual increase or decrease in the
II-142
NOTES (continued)
Georgia Power Company 2003 Annual Report
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,
2003 as follows:
1 Percent 1 Percent
Increase Decrease
- ---------------------------------------------------------------
(in millions)
Benefit obligation $70 $61
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 2003, 2002, and 2001 were $18 million, $17 million, and $16
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. In addition, 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 against the Company cannot be predicted at this time;
however, management does not anticipate that the liabilities, if any, arising
from such current 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. Retail rates were decreased by $118 million
effective January 1, 2002. Under the terms of the order, earnings are 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 are applied to rate
refunds, with the remaining one-third retained by the Company. The Company's
earnings in 2003 and 2002 were within the common equity range.
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. 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 2001 rate order, the Company discontinued recording accelerated
depreciation and amortization and began amortizing the accumulated balance
equally over three years as a credit to expense beginning in 2002. Also, the
rate order required the Company to recognize capacity and operating and
maintenance costs related to new GPSC certified purchased power contracts evenly
in rates over a three -year period ending December 31, 2004.
The Company 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 the Company to implement a natural gas and oil procurement and hedging
program. This order allows the Company to use financial instruments to hedge
price and commodity risk associated with these fuels. 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
II-143
NOTES (continued)
Georgia Power Company 2003 Annual Report
hedging program will be shared with the retail customers receiving 75 percent
and the Company retaining 25 percent of the net gains.
Fuel Cost Recovery
In May 2003, the Company filed for a fuel cost recovery rate increase. On August
19, 2003, the GPSC issued an order approving a stipulation reached by the
Company, the Consumers' Utility Counsel Division, Georgia Textile Manufacturers
Association, Georgia Industrial Group and the staff of the GPSC. The stipulation
allows the Company to increase fuel rates to recover existing under-recovered
deferred fuel costs over the period of October 1, 2003 through March 31, 2005,
as well as future projected fuel costs. The new fuel rate represents an average
annual increase in rates paid by customers of approximately 1.6 percent.
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.
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 periods.
Open Access Transmission Tariff
In October 2003, the FERC approved a new Open Access Transmission Tariff for the
Company of $1.73 per kilowatt-month based on an 11.25 percent return on equity.
The Company had requested a rate increase effective January 2002 based on a 13
percent return on equity. Pending FERC approval, the Company collected from
customers based on the 13 percent return on equity, but recorded revenue subject
to refund for amounts above the previously approved rate of $1.37 per
kilowatt-month. As a result of the final settlement, a total of approximately
$2.3 million was refunded to the Company's transmission customers in October
2003 and $7.2 million was recorded as revenue.
New Source Review Actions
In November 1999, the Environmental Protection Agency (EPA) brought a civil
action against the Company alleging the Company had violated the New Source
Review (NSR) provisions of the Clean Air Act with respect to coal-fired
generating facilities at the Company's Bowen and Scherer plants and violations
of related state laws. 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
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 action against the Company was stayed in the spring of 2001 during the
appeal of a very similar NSR enforcement action against the Tennessee Valley
Authority (TVA) before the U.S. Court of Appeals for the Eleventh Circuit. The
TVA appeal involves many of the same legal issues raised by the actions against
the Company. Because the final resolution of the TVA appeal could have a
significant impact on the Company, the Company has been involved in that appeal.
On June 24, 2003, the court of appeals issued its ruling in the TVA case. It
found unconstitutional the statutory scheme set forth in the Clean Air Act that
allowed the EPA to impose penalties for failing to comply with an administrative
compliance order, like the one issued to TVA, without the EPA having to prove
the underlying violation. Thus, the court of appeals held that the compliance
order was of no legal consequence, and TVA was free to ignore it. The court did
not, however, rule directly on the substantive legal issues about the proper
interpretation and application of certain NSR provisions that had been raised in
the TVA appeal. On September 16, 2003, the court of appeals denied the EPA's
request for a rehearing of the decision and on February 13, 2004, the EPA
petitioned the U.S. Supreme Court to review the Eleventh Circuit's decision. At
this time, no party to the Company's action, which was administratively closed
two years ago, has asked the court to reopen that case.
Since the inception of the NSR proceedings against the Company, the EPA has
also been proceeding with similar NSR enforcement actions against other
II-144
NOTES (continued)
Georgia Power Company 2003 Annual Report
utilities, involving many of the same legal issues. In each case, the EPA
alleged that the utilities failed to comply with the NSR permitting requirements
when performing maintenance and construction activities at coal-burning plants,
which activities the Company considers to be routine or otherwise not subject to
NSR. In 2003, district courts addressing these cases issued opinions that
reached conflicting conclusions.
In October 2003, the EPA issued final revisions to its NSR regulations
under the Clean Air Act clarifying the scope of the existing Routine
Maintenance, Repair, and Replacement exclusion. On December 24, 2003, the U.S.
Court of Appeals for the District of Columbia Circuit stayed the effectiveness
of these revisions pending resolution of related litigation. In January 2004,
the Bush Administration announced that it would continue to enforce the existing
rules.
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 this case 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 Environmental 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 the Company for alleged violations of the Clean Air Act
at four of the generating units 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 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 June 19, 2003, the court granted the Company motion to dismiss the
allegations regarding hazardous air pollutants and denied the Company's motion
to dismiss the allegations regarding emission offsets. On August 29, 2003, the
Company filed a motion for partial summary judgment regarding emission offsets.
On January 20, 2004, the Company filed a motion for summary judgment on the
remaining three counts, and the plaintiffs have filed motions for partial
summary judgment. The case is currently scheduled for trial during the summer of
2004. While the Company 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.
Potentially Responsible Party Status
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. The
Company has recognized $34 million in cumulative expenses through December 31,
2003 for the assessment and anticipated cleanup of sites on the Georgia
Hazardous Sites Inventory. In addition, in 1995 the EPA designated the Company
and four other unrelated entities as potentially responsible parties at a site
in Brunswick, Georgia that is listed on the federal National Priorities List.
The Company 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, 2003, the
Company had recorded approximately $6 million in cumulative expenses associated
with the Company'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
the Company'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.
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Georgia Power Company 2003 Annual Report
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 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, Southern
Company Energy Solutions, a subsidiary of Southern Company, 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 plantiffs' claims. On March 31, 2003,
the U.S. District Court for the Northern District of Georgia granted summary
judgment in favor of the defendants on all claims raised by all seven
plaintiffs. On April 23, 2003 plaintiffs filed an appeal to the U.S. Court of
Appeals for the Eleventh Circuit challenging these adverse summary judgment
rulings, as well as the District Court's October 2001 ruling denying class
certification. Oral arguments occurred January 27, 2004, and the parties await
the court's decision. The final outcome of this matter cannot now be determined.
Right of Way Litigation
Southern Company and certain of its subsidiaries including the Company, Gulf
Power, Mississippi Power, and Southern Telecom (collectively defendants) have
been named as defendants in numerous lawsuits brought by landowners since 2001
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. Management believes that the Company
has complied with applicable laws and 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.
In addition, in late 2001, certain subsidiaries of Southern Company,
including Alabama Power, the Company, Gulf Power, Mississippi Power, Savannah
Electric and Southern Telecom (collectively, defendants) were named as
defendants in a lawsuit brought by a telecommunications company that uses
certain of the defendants' rights of way. This lawsuit alleges, among other
things, that the defendants are contractually obligated to indemnify, defend,
and hold harmless the telecommunications company from any liability that may be
assessed against the telecommunications company in pending and future right of
way litigation. The Company believes that the plaintiff's claims are without
merit. An adverse outcome in this matter, combined with an adverse outcome
against the telecommunications company in one or more of the right of way
lawsuits, could result in substantial judgments; however, the final outcome of
these matters cannot now be determined.
FERC Matters
The Company has obtained FERC approval to sell power to non-affiliates at
market-based prices under specific contracts. The Company also has FERC
authority to make short-term opportunity sales at market rates. Specific FERC
approval must be obtained with respect to a market-based contract with an
affiliate. In November 2001, the FERC modified the test it uses to consider
utilities' applications to charge market-based rates and adopted a new test
called the Supply Margin Assessment (SMA). The FERC applied the SMA to several
utilities, including Southern Company's retail operating companies, and found
them to be "pivotal suppliers" in their control area market and ordered the
implementation of certain mitigation measures. SCS, on behalf of the Company and
the other retail operating companies, sought rehearing of the FERC order and the
FERC delayed implementation of certain mitigation measures. SCS, on behalf of
II-146
NOTES (continued)
Georgia Power Company 2003 Annual Report
the Company and the other retail operating companies, submitted comments to the
FERC in 2002 regarding these issues. In December 2003, the FERC issued a staff
paper discussing alternatives and held a technical conference in January 2004.
The Company anticipates that the FERC will address the requests for rehearing in
the near future. Regardless of the outcome of the SMA proposal, the FERC retains
the ability to modify or withdraw the authorization for any seller to sell at
market-based rates, if it determines that the underlying conditions for having
such authority are no longer applicable. The final outcome of this matter will
depend on the form in which the SMA test and mitigation measures rules may be
ultimately adopted and cannot be determined at this time.
PPAs by the Company for Southern Power's Plant McIntosh capacity were
certified by the GPSC in December 2002 after a competitive bidding process. In
April 2003, Southern Power applied for FERC approval of these PPAs. Interveners
have made filings in opposition of the FERC's acceptance of the PPAs, alleging
that the PPAs do not meet the applicable standards for market-based rates
between affiliates. In July 2003, the FERC accepted the PPAs to become effective
June 1, 2005, subject to refund, and ordered that hearings be held to determine:
(a) whether, in the design and implementation of the GPSC competitive bidding
process, the Company unduly preferred Southern Power; (b) whether the analysis
of the competitive bids unduly favored Southern Power, particularly with respect
to evaluation of non-price factors; (c) whether the Company selected its
affiliate, Southern Power, based upon a reasonable combination of price and
non-price factors; (d) whether Southern Power received an undue preference or
competitive advantage in the competitive bidding process as a result of access
to its affiliate's transmission system; (e) whether and to what extent the PPAs
impact wholesale competition; and (f) whether the PPAs are just and reasonable
and not unduly discriminatory. Hearings are scheduled to begin in March 2004.
Management believes that the PPAs should be approved by the FERC; however, the
ultimate outcome of this matter cannot now be determined.
4. JOINT OWNERSHIP AGREEMENTS
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:
2003 2002 2001
----------------------------------
(in millions)
Energy $55 $53 $52
Capacity 34 32 30
- ---------------------------------------------------------
Total $89 $85 $82
=========================================================
The Company 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 (MEAG), the city of Dalton, Georgia,
Florida Power & Light Company, Jacksonville Electric Authority, 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.
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NOTES (continued)
Georgia Power Company 2003 Annual Report
At December 31, 2003, 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% $3,307 $1,706
Plant Hatch (nuclear) 50.1 908 469
Plant Wansley (coal) 53.5 390 160
Plant Scherer (coal)
Units 1 and 2 8.4 115 52
Unit 3 75.0 560 247
Plant McIntosh
Common Facilities 75.0 24 3
(combustion-turbine)
Rocky Mountain 25.4 169 85
(pumped storage)
Intercession City 33.3 12 1
(combustion-turbine)
- --------------------------------------------------------------------
The Company has contracted to operate and maintain the jointly owned
facilities as agent for their co-owners, except as noted above. The Company's
proportionate share of its plant operating expenses is included in the
corresponding operating expenses in the Statements of Income.
5. INCOME TAXES
Southern Company and its subsidiaries file a consolidated federal income tax
return. As a result of new State of Georgia Department of Revenue regulations
applicable to tax years beginning on or after January 1, 2002, Southern Company
and its subsidiaries were granted permission by the State of Georgia Department
of Revenue Commissioner to file a combined State of Georgia 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 both
IRS and State of Georgia Department of Revenue regulations, each company is
jointly and severally liable for the tax liability.
At December 31, 2003, tax-related regulatory assets were $510 million and
tax-related regulatory liabilities were $187 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:
2003 2002 2001
-----------------------------
Total provision for income taxes: (in millions)
Federal:
Current $143 $261 $352
Deferred 181 60 (46)
- ---------------------------------------------------------------
324 321 306
- ---------------------------------------------------------------
State:
Current 24 31 61
Deferred 16 5 (8)
Deferred investment tax
credits 2 - 5
- ---------------------------------------------------------------
Total $366 $357 $364
===============================================================
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:
2003 2002
-------------------
(in millions)
Deferred tax liabilities:
Accelerated depreciation $1,966 $1,779
Property basis differences 563 623
Other 329 309
- -----------------------------------------------------------------
Total 2,858 2,711
- -----------------------------------------------------------------
Deferred tax assets:
Federal effect of state deferred taxes 96 90
Other property basis differences 156 170
Other deferred costs 160 214
Other 75 64
- -----------------------------------------------------------------
Total 487 538
- -----------------------------------------------------------------
Net deferred tax liabilities 2,371 2,173
Portion included in prepaid expenses - 3
- -----------------------------------------------------------------
Accumulated deferred income taxes
in the Balance Sheets $2,371 $2,176
=================================================================
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 $15 million in 2003, $12 million in
II-148
NOTES (continued)
Georgia Power Company 2003 Annual Report
2002 and $15 million in 2001. At December 31, 2003, 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:
2003 2002 2001
------------------------------
Federal statutory rate 35% 35% 35%
State income tax, net of
federal deduction 3 2 4
Non-deductible book
depreciation 1 1 2
Other (2) (1) (4)
- --------------------------------------------------------------
Effective income tax rate 37% 37% 37%
==============================================================
6. CAPITALIZATION
Mandatorily Redeemable Preferred Securities
The Company has formed certain wholly-owned trust subsidiaries for the purpose
of issuing preferred securities. The proceeds of the related equity investments
and security sales were loaned back to the Company through the issuance of
junior subordinated notes totaling $969 million, which constitute substantially
all of the assets of the trusts. The Company considers that the mechanisms and
obligations relating to the preferred securities issued for its benefit, taken
together, constitute a full and unconditional guarantee by it of the respective
trusts' payment obligations with respect to these preferred securities. At
December 31, 2003, preferred securities of $940 million were outstanding and
recognized as liabilities in the Balance Sheets.
Long-Term Debt 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:
2003 2002
----------------------
(in millions)
Capital lease $2 $ 2
Senior notes - 320
- -------------------------------------------------------------
Total $2 $322
=============================================================
Serial maturities through 2008 applicable to total long-term debt are as
follows: $2 million in 2004; $453 million in 2005; $153 million in 2006;
$303 million in 2007; and $3 million in 2008.
First Mortgage Bond Indenture
In 2002, the first mortgage bond indenture of the Company 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.
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, 2003 was
$1.7 billion.
Capital Leases
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, 2003 and 2002, the Company had a capitalized
lease obligation for its corporate headquarters building of $79 million and $81
million, respectively, 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,
2003 and 2002, the interest and lease amortization deferred on the Balance
Sheets was $54 million.
Bank Credit Arrangements
At the beginning of 2004, the Company had an unused credit arrangement with
banks totaling $725 million expiring at June 11, 2004. Upon expiration, the $725
million 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 portion of the commitments or the maintenance of
compensating balances with the banks. Commitment fees are less than 1/8 of 1
II-149
NOTES (continued)
Georgia Power Company 2003 Annual Report
percent for the Company. Compensating balances are not legally restricted from
withdrawal. A fee is also paid to the agent bank.
The credit arrangements contain covenants that limit the level of
indebtedness to capitalization to 65 percent, as defined in the agreement.
Exceeding these limits would result in an event of default under the credit
arrangement. In addition, the credit arrangements contain cross default
provisions that would trigger an event of default if the Company defaulted on
other indebtedness above a specified threshold. The Company is currently in
compliance with all such covenants.
This $725 million 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, 2003 was $106 million. In addition, the Company borrows under a
commercial paper program and an extendible commercial note program. The amount
of commercial paper outstanding at December 31, 2003 was $137 million. There
were no outstanding extendible commercial notes at December 31, 2003. The amount
of commercial paper outstanding at December 31, 2002 was $358 million, which
included $19 million of extendible commercial notes. During 2003, the peak
amount of commercial paper outstanding was $531 million and the average amount
outstanding was $229 million. The average annual interest rate on commercial
paper in 2003 was 1.23 percent. Commercial paper is included in notes payable on
the Balance Sheets.
Financial Instruments
The Company enters into energy-related derivatives to hedge exposures to
electricity, gas, and other fuel price changes. However, due to cost-based rate
regulations, the Company has limited exposure to market volatility in commodity
fuel prices and prices of electricity. The Company has implemented fuel-hedging
programs at the instruction of the GPSC. The Company also enters into hedges of
forward electricity sales.
At December 31, 2003, the fair value of derivative energy contracts was
reflected in the financial statements as follows:
Amounts
------------
(in millions)
Regulatory liabilities, net $3.2
Other comprehensive income -
Net income -
- -------------------------------------------------------
Total fair value $3.2
=======================================================
The Company enters into derivatives to hedge exposure to interest rate
changes. Derivatives related to variable rate securities or forecasted
transactions are accounted for as cash flow hedges. The derivatives are
generally structured to mirror the critical terms of the hedged debt
instruments; therefore, no material ineffectiveness has been recorded in
earnings.
At December 31, 2003, the Company had interest rate swaps outstanding with
net deferred losses as follows:
Cash Flow Hedges
Weighted
Average
Fixed Fair
Rate Notional Value
Maturity Paid Amount (Loss)
- ----------------------------------------------------------
(in millions)
2004 1.39% $873 $(0.8)
2005 1.56 50 0
2005 1.96 250 (1.1)
The fair value gain or loss for cash flow hedges is recorded in other
comprehensive income and is reclassified into earnings at the same time the
hedged items affect earnings. In 2003, the Company recognized losses totaling
$11.3 million upon termination of certain interest derivatives at the same time
it issued debt. These losses have been deferred in other comprehensive income
and will be amortized to interest expense over the life of the related debt. For
2003, approximately $3.4 million of pre-tax losses were reclassified from other
comprehensive income to interest expense. For 2004, pre-tax losses of
approximately $3.2 million are expected to be reclassified from other
comprehensive income to interest expense.
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NOTES (continued)
Georgia Power Company 2003 Annual Report
7. COMMITMENTS
Construction Program
The Company currently estimates property additions to be approximately $747
million, $812 million, and $1,043 million in 2004, 2005, and 2006, respectively.
These amounts include $28.9 million, $19.7 million and $20.0 million in 2004,
2005, and 2006, respectively, for construction expenditures related to
contractual purchase commitments for uranium and nuclear fuel conversion,
enrichment, and fabrication services included under "Fuel and Purchased Power
Commitments." 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,
changes in FERC rules and transmission regulations, 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, 2003, significant
purchase commitments were outstanding in connection with the construction
program.
The Company has no generating plants under construction. However,
construction related to new transmission and distribution facilities and capital
improvements to existing generation, transmission and distribution facilities,
including those needed to meet the environmental standards previously discussed,
are ongoing.
The Company 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.
Southern Company has guaranteed Southern Power obligations totaling $10.7
million for the Company's construction of transmission interconnection
facilities to these plants.
Fuel and Purchased Power 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.
Natural gas purchase commitments contain fixed volumes with prices based on
various indices at the time of delivery. Amounts included in the chart below
represent estimates based on New York Mercantile future prices at December 31,
2003. Also the Company has entered into various long-term commitments for the
purchase of electricity. Total estimated minimum long-term obligations at
December 31, 2003 were as follows:
Coal and
Natural Nuclear
Year Gas Fuel
- ---- -------------------------
(in millions)
2004 $ 156 $1,321
2005 149 1,045
2006 148 895
2007 108 603
2008 172 372
2009 and thereafter 1,625 183
- -------------------------------------------------------
Total commitments $2,358 $4,419
=======================================================
Additional commitments for coal and for nuclear fuel will be required to
supply the Company's future needs.
SCS may enter into various types of wholesale energy and natural gas
contracts acting as an agent for the Company and all of the other Southern
Company retail operating companies, Southern Power, and Southern Company GAS.
Under these agreements, each of the retail operating companies, Southern Power,
and Southern Company Gas may be jointly and severally liable. The
creditworthiness of Southern Power and Southern Company GAS is currently
inferior to the creditworthiness of the retail operating companies. Accordingly,
Southern Company has entered into keep-well agreements with the Company and each
of the retail 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 Company GAS as a contracting party under
these agreements.
II-151
NOTES (continued)
Georgia Power Company 2003 Annual Report
The Company has commitments regarding a portion of a 5 percent interest in
Plant Vogtle owned by MEAG that are in effect until the latter of the retirement
of the plant or the latest stated maturity date of MEAG's bonds issued to
finance such ownership interest. The payments for capacity are required whether
or not any capacity is available. The energy cost is a function of each unit's
variable operating costs. Except as noted below, the cost of such capacity and
energy is included in purchased power from non-affiliates in the Company's
Statements of Income. Capacity payments totaled $57 million, $57 million, and
$59 million in 2003, 2002, and 2001, respectively. The current projected Plant
Vogtle capacity payments are:
Year Capacity Payments
- ---- -----------------
(in millions)
2004 $ 57
2005 56
2006 54
2007 54
2008 54
2009 and thereafter 369
- -------------------------------------------------------
Total $644
=======================================================
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 at the time of the disallowance was written off.
The Company has entered into other various long-term commitments for the
purchase of electricity. Estimated total long-term obligations at December 31,
2003 were as follows:
Non-
Year Affiliated Affiliated
- ---- ---------- ----------
(in millions)
2004 $ 191 $ 45
2005 268 79
2006 283 88
2007 283 89
2008 282 90
2009 and thereafter 1,722 482
- -----------------------------------------------------------
Total $3,029 $873
===========================================================
Operating Leases
The Company has entered into various operating leases with various terms and
expiration dates. Rental expenses related to these operating leases totaled $36
million for 2003, $35 million for 2002, and $14 million for 2001. At December
31, 2003, estimated minimum rental commitments for these noncancelable operating
leases were as follows:
------------------------------------
Minimum Obligations
------------------------------------
Year Rail Cars Other Total
- ---- -----------------------------------
(in millions)
2004 $ 12 $22 $ 34
2005 12 18 30
2006 12 14 26
2007 10 12 22
2008 11 11 22
2009 and thereafter 56 16 72
- -------------------------------------------------------------
Total $113 $93 $206
=============================================================
In addition to the rental commitments above, the Company has obligations
upon expiration of certain 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 rail car lease obligations is shared with the
joint owners of plants Scherer and Wansley. Rental expenses related to the rail
car 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, 2003, the outstanding loans guaranteed by the Company were $8.7
million and loan loss reserves of $1.8 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
II-152
NOTES (continued)
Georgia Power Company 2003 Annual Report
principal amount of pollution control revenue bonds are outstanding. The Company
has agreed to reimburse Alabama Power for the pro rata portion of such
obligation corresponding to the Company's then proportionate ownership of stock
of SEGCO if Alabama Power is called upon to make such payment under its
guaranty. In May 2003, SEGCO issued an additional $50 million in senior notes.
Alabama Power guaranteed the debt obligation and in October 2003, the Company
agreed to reimburse Alabama Power for the pro rata portion of such obligation
corresponding to its 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.
8. 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 $10.9 billion for
public liability claims that could arise from a single nuclear incident. Each
nuclear plant is insured against this liability to a maximum of $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 $101 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 $203 million per incident but not more than an aggregate of $20 million to
be paid for each incident in any one year. The Price-Anderson Amendments Act
expired in August 2002; however, the indemnity provisions of the Act remain in
place for commercial nuclear reactors.
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 up 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 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
NEIL policies would be $40 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. Both companies, however, revised their policy
terms on a prospective basis to include an industry aggregate for all
"non-certified" terrorist acts (i.e., acts that are not certified acts of
terrorism pursuant to the Terrorism Risk Insurance Act of 2002 (TRIA). The NEIL
aggregate -- applies to non-certified claims stemming from terrorism within a
12-month duration -- is $3.24 billion plus any amounts available through
reinsurance or indemnity from an outside source. The non-certified ANI cap is a
$300 million shared industry aggregate. Any act of terrorism that is certified
pursuant to the TRIA will not be subject to the foregoing NEIL and ANI
limitations but will be subject to the TRIA annual aggregate limitation of $100
billion of insured losses arising from certified acts of terrorism. The TRIA
will expire on December 31, 2005.
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
II-153
NOTES (continued)
Georgia Power Company 2003 Annual Report
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.
9. QUARTERLY FINANCIAL INFORMATION
(UNAUDITED)
Summarized quarterly financial information for 2003 and 2002 is as follows:
Net Income
After
Dividends on
Operating Operating Preferred Stock
Quarter Ended Revenues Income
- ---------------------------------------------------------------------
(in millions)
--------------------------------------------
March 2003 $1,126 $262 $133
June 2003 1,190 293 159
September 2003 1,487 490 265
December 2003 1,111 179 74
March 2002 $1,007 $260 $127
June 2002 1,204 320 171
September 2002 1,517 498 271
December 2002 1,095 126 49
- ---------------------------------------------------------------------
The Company's business is influenced by seasonal weather conditions.
II-154
SELECTED FINANCIAL AND OPERATING DATA 1999-2003
Georgia Power Company 2003 Annual Report
- ------------------------------------------------------------------------------------------------------------------------------
2003 2002 2001 2000 1999
- ------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands) $4,913,507 $4,822,460 $4,965,794 $4,870,618 $4,456,675
Net Income after Dividends
on Preferred Stock (in thousands) $630,577 $617,629 $610,335 $559,420 $541,383
Cash Dividends
on Common Stock (in thousands) $565,800 $542,900 $527,300 $549,600 $543,000
Return on Average Common Equity (percent) 14.05 13.99 14.12 13.66 14.02
Total Assets (in thousands) $14,782,028 $14,342,656 $14,447,973 $13,971,211 $13,148,049
Gross Property Additions (in thousands) $742,810 $883,968 $1,389,751 $1,078,163 $790,464
- ------------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $4,540,211 $4,434,447 $4,397,485 $4,249,544 $3,938,210
Preferred stock 14,569 14,569 14,569 14,569 14,952
Mandatorily redeemable preferred securities 940,000 940,000 789,250 789,250 789,250
Long-term debt 3,762,333 3,109,619 2,961,726 3,041,939 2,688,358
- ------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $9,257,113 $8,498,635 $8,163,030 $8,095,302 $7,430,770
==============================================================================================================================
Capitalization Ratios (percent):
Common stock equity 49.0 52.2 53.9 52.5 53.0
Preferred stock 0.2 0.2 0.2 0.2 0.2
Mandatorily redeemable preferred securities 10.2 11.1 9.6 9.7 10.6
Long-term debt 40.6 36.5 36.3 37.6 36.2
- ------------------------------------------------------------------------------------------------------------------------------
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 N/A A1 A1 A1
Standard and Poor's N/A N/A A A A+
Fitch N/A N/A AA- AA- AA-
Preferred Stock -
Moody's Baa1 Baa1 Baa1 a2 a2
Standard and Poor's BBB+ BBB+ BBB+ BBB+ 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 1,768,662 1,734,430 1,698,407 1,669,566 1,632,450
Commercial 258,276 250,993 244,674 237,977 229,524
Industrial 7,899 8,240 8,046 8,533 8,958
Other 3,434 3,328 3,239 3,159 3,060
- ------------------------------------------------------------------------------------------------------------------------------
Total 2,038,271 1,996,991 1,954,366 1,919,235 1,873,992
==============================================================================================================================
Employees (year-end): 8,714 8,837 9,048 8,860 8,961
- ------------------------------------------------------------------------------------------------------------------------------
N/A = Not Applicable.
II-155
SELECTED FINANCIAL AND OPERATING DATA 1999-2003 (continued)
Georgia Power Company 2003 Annual Report
- ------------------------------------------------------------------------------------------------------------------------------
2003 2002 2001 2000 1999
- ------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $ 1,583,082 $1,600,438 $ 1,507,031 $ 1,535,684 $ 1,410,099
Commercial 1,661,054 1,631,130 1,682,918 1,620,466 1,527,880
Industrial 1,012,267 1,004,288 1,106,420 1,154,789 1,143,001
Other 53,569 52,241 52,943 6,399 (30,892)
- ------------------------------------------------------------------------------------------------------------------------------
Total retail 4,309,972 4,288,097 4,349,312 4,317,338 4,050,088
Sales for resale - non-affiliates 259,376 270,678 366,085 297,643 210,104
Sales for resale - affiliates 174,855 98,323 99,411 96,150 76,426
- ------------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 4,744,203 4,657,098 4,814,808 4,711,131 4,336,618
Other revenues 169,304 165,362 150,986 159,487 120,057
- ------------------------------------------------------------------------------------------------------------------------------
Total $4,913,507 $4,822,460 $4,965,794 $4,870,618 $4,456,675
==============================================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 21,778,582 22,144,559 20,119,080 20,693,481 19,404,709
Commercial 26,940,572 26,954,922 26,493,255 25,628,402 23,715,485
Industrial 25,703,421 25,739,785 25,349,477 27,543,265 27,300,355
Other 595,742 593,202 583,007 568,906 551,451
- ------------------------------------------------------------------------------------------------------------------------------
Total retail 75,018,317 75,432,468 72,544,819 74,434,054 70,972,000
Sales for resale - non-affiliates 8,835,804 8,069,375 8,110,096 6,463,723 5,060,931
Sales for resale - affiliates 5,844,196 3,962,559 3,133,485 2,435,106 1,795,243
- ------------------------------------------------------------------------------------------------------------------------------
Total 89,698,317 87,464,402 83,788,400 83,332,883 77,828,174
==============================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 7.27 7.23 7.49 7.42 7.27
Commercial 6.17 6.05 6.35 6.32 6.44
Industrial 3.94 3.90 4.36 4.19 4.19
Total retail 5.75 5.68 6.00 5.80 5.71
Sales for resale 2.96 3.07 4.14 4.43 4.18
Total sales 5.29 5.32 5.75 5.65 5.57
Residential Average Annual
Kilowatt-Hour Use Per Customer 12,421 12,867 11,933 12,520 12,006
Residential Average Annual
Revenue Per Customer $902.70 $929.90 $893.84 $929.11 $872.48
Plant Nameplate Capacity
Ratings (year-end) (megawatts) 13,980 14,059 14,474 15,114 14,474
Maximum Peak-Hour Demand (megawatts):
Winter 13,153 11,873 11,977 12,014 11,568
Summer 14,826 14,597 14,294 14,930 14,575
Annual Load Factor (percent) 61.0 60.4 61.7 61.6 58.9
Plant Availability (percent):
Fossil-steam 87.6 80.9 88.5 86.1 84.3
Nuclear 94.2 88.8 94.4 91.5 89.3
- ------------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 58.6 59.5 58.5 62.3 63.0
Nuclear 16.8 16.2 18.1 17.4 18.0
Hydro 2.1 0.9 1.1 0.7 0.9
Oil and gas 0.3 0.3 0.4 1.8 1.6
Purchased power -
From non-affiliates 7.5 6.3 7.8 8.1 6.6
From affiliates 14.7 16.8 14.1 9.7 9.9
- ------------------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0 100.0 100.0
==============================================================================================================================
II-156
GULF POWER COMPANY
FINANCIAL SECTION
II-157
MANAGEMENT'S REPORT
Gulf Power Company 2003 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 internal accounting controls are 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 Southern Company's board of directors, composed of
four independent directors, provides a broad overview of management's financial
reporting and control functions. Additionally, the Company's Controls and
Compliance Committee, comprised 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/Susan N. Story
Susan N. Story
President
and Chief Executive Officer
/s/Ronnie R. Labrato
Ronnie R. Labrato
Vice President, Chief Financial Officer,
and Comptroller
March 1, 2004
II-158
INDEPENDENT AUDITORS' REPORT
Gulf Power Company 2003 Annual Report
Gulf Power Company:
We have audited the accompanying balance sheets and statements of capitalization
of Gulf Power Company (a wholly owned subsidiary of Southern Company) as of
December 31, 2003 and 2002, and the related statements of income, comprehensive
income, common stockholder's equity, and cash flows for the years 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 audits. The financial statements of Gulf Power Company
for the year ended December 31, 2001 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 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, the financial statements (pages II-175 to II-195) present
fairly, in all material respects, the financial position of Gulf Power Company
at December 31, 2003 and 2002, and the results of its operations and its cash
flows for the years then ended in conformity with accounting principles
generally accepted in the United States of America.
As discussed in Note 1 to the financial statements, in 2003 Gulf Power
Company changed its method of accounting for asset retirement obligations.
/s/Deloitte & Touche LLP
Atlanta, Georgia
March 1, 2004
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(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 Com-pany'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 to 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.
Atlanta, Georgia
February 13, 2002
II-159
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Gulf Power Company 2003 Annual Report
OVERVIEW OF EARNINGS AND
- ------------------------
BUSINESS ACTIVITIES
- -------------------
Earnings
Gulf Power Company's 2003 net income after dividends on preferred stock was
$69.0 million, an increase of $2.0 million from the previous year. In 2002,
earnings were $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 the prior
year. The improvement in earnings in 2003 is due primarily to higher operating
revenues related to an increase in base rates effective in May 2002, offset
somewhat by higher operating expenses and increases in depreciation expense
primarily related to the commercial operation of Plant Smith Unit 3 beginning in
April 2002. The improvement in earnings in 2002 is due primarily to higher
operating revenues related to the increase in base rates, offset somewhat by
higher operating expenses and higher financing costs primarily related to the
commercial operation of the new unit. The increase in 2001 earnings was
primarily a result of an increase in Allowance for Funds Used During
Construction (AFUDC) and lower interest expense during construction of the unit.
Business Activities
The Company operates as a vertically integrated utility providing
electricity to customers within its traditional service area located in
northwest Florida and to wholesale customers in the Southeast. Prices for
electricity provided by the Company to retail customers are set by the Florida
Public Service Commission (FPSC).
Several factors affect the opportunities, challenges, and risks of selling
electricity. These factors include the Company's ability to maintain a stable
regulatory environment, to achieve energy sales growth while containing costs,
and to recover costs related to growing demand and increasingly stricter
environmental standards. 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, new energy contracts with neighboring
utilities, energy conservation practiced by customers, the price of electricity,
the price elasticity of demand, and the rate of economic growth in the Company's
service area.
RESULTS OF OPERATIONS
- ---------------------
A condensed income statement follows:
Increase (Decrease)
Amount From Prior Year
- -----------------------------------------------------------------
2003 2003 2002 2001
- -----------------------------------------------------------------
(in millions)
Operating revenues $878 $ 58 $ 95 $ 11
- -----------------------------------------------------------------
Fuel 317 42 73 (15)
Purchased power 50 (12) (44) 24
Other operation
and maintenance 211 11 23 5
Depreciation
and amortization 82 5 9 1
Taxes other than
income taxes 66 5 6 (1)
- -----------------------------------------------------------------
Total operating
expenses 726 51 67 14
- -----------------------------------------------------------------
Operating income 152 7 28 (3)
Interest Expenses
and other, net (42) (1) (13) 10
Income taxes (41) (4) (6) -
- -----------------------------------------------------------------
Net income $ 69 $ 2 $ 9 $ 7
=================================================================
Revenues
Operating revenues increased in 2003 when compared to 2002 and 2001. The
following table summarizes the changes in operating revenues for the past three
years:
2003 2002 2001
---------------------------------------
(in thousands)
Retail - Prior Year $665,836 $584,591 $548,640
Change in -
Base Revenues 22,000 31,200 -
Sales Growth 7,040 16,557 10,254
Weather (6,757) 9,497 (5,699)
Fuel and other
cost recovery 11,055 23,991 31,396
- --------------------------------------------------------------------
Retail--Current Year 699,174 665,836 584,591
- --------------------------------------------------------------------
Sales for resale--
Non-affiliates 76,767 77,171 82,252
Affiliates 63,268 40,391 27,256
- --------------------------------------------------------------------
Total sales for resale 140,035 117,562 109,508
Other operating
revenues 38,488 37,069 31,104
- --------------------------------------------------------------------
Total operating
revenues $877,697 $820,467 $725,203
====================================================================
Percent change 7.0% 13.1% 1.5%
- --------------------------------------------------------------------
II-160
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2003 Annual Report
Retail revenues increased $33.3 million, or 5.0 percent in 2003, $81.2
million, or 13.9 percent, in 2002, and $36.0 million, or 6.6 percent, in 2001.
The significant factors driving these changes are shown in the table above. 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 including 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 $140.0 million in 2003, an increase of $22.5 million,
or 19.1 percent, primarily due to increased energy sales for resale to
affiliates reflecting greater availability of generation when compared to 2002.
Sales for resale were $117.6 million in 2002, an increase of $8.1 million, or
7.4 percent, due to increased energy sales for resale to affiliates reflecting
the commercial operation of Plant Smith Unit 3. Sales for resale were $109.5
million in 2001, a decrease of $24.4 million, or 18.2 percent, from 2000. 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, since they are generally sold at marginal cost.
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:
2003 2002 2001
-----------------------------------
(in thousands)
Unit Power --
Capacity $18,598 $19,898 $19,472
Energy 30,894 28,565 27,579
- -------------------------------------------------------------
Total $49,492 $48,463 $47,051
=============================================================
Capacity revenues remained relatively unchanged during 2003, 2002, and
2001. Unit power from specific generating plants is currently being sold to
Progress Energy FL, Florida Power & Light Company, and Jacksonville Electric
Authority. Under these agreements, 211 megawatts of net dependable capacity were
sold by the Company during 2003. No significant declines in the amount of
capacity are scheduled until the termination of the contracts in 2010.
Other operating revenues for 2003 increased $1.4 million due primarily to
an increase in franchise fees. Other operating revenues for 2002 increased $6.0
million primarily due to a $3.3 million increase in franchise fees, a $1.7
million settlement related to a purchased power agreement, and a $0.9 million
increase in revenues from the transmission of electricity to others.
Energy Sales
Kilowatt-hour (KWH) sales for 2003 and the percent changes by year were as
follows:
KWH Percent Change
-----------------------------------------------
2003 2003 2002 2001
-----------------------------------------------
(millions)
Residential 5,101 (0.8)% 9.1% (1.5)%
Commercial 3,614 1.7 4.0 1.2
Industrial 2,147 4.5 1.8 4.8
Other 23 4.7 - 10.5
-----------------------------------------------
Total retail 10,885 1.0 5.9 0.6
Sales for resale
Non-affiliates 2,504 16.1 3.1 22.8
Affiliates 2,439 41.8 78.4 (49.8)
-----------------------------------------------
Total 15,828 8.0 10.7 (3.7)
====================================================================
Residential sales decreased 0.8 percent in 2003 primarily due to milder
summer weather, when compared to 2002. In 2002, residential sales increased 9.1
percent over 2001 primarily due to more extreme summer and winter weather
combined with increased summer sales along the coastal regions. Residential
sales decreased 1.5 percent in 2001 primarily due to milder summer and winter
weather, when compared to 2000. Residential sales are expected to increase just
under 1 percent annually over the next five years, given normal weather
conditions.
Commercial sales increased 1.7 percent in 2003, when compared to 2002,
primarily due to increased sales along the coastal regions, in spite of milder
summer weather. In 2002, commercial sales increased 4.0 percent primarily due to
more extreme weather when compared to 2001. Commercial sales increased 1.2
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2003 Annual Report
percent in 2001, when compared to 2000, primarily due to increased sales along
the coastal regions, in spite of milder summer weather. Commercial sales are
expected to increase just under 1 percent annually over the next five years,
given normal weather conditions.
Industrial sales increased 4.5 percent in 2003, when compared to 2002,
primarily due to additional sales resulting from high natural gas prices. In
2002, industrial sales increased 1.8 percent, when compared to 2001, primarily
due to normal customer growth. Industrial sales increased 4.8 percent in 2001,
when compared to 2000, primarily due to increased sales to Real Time Pricing
customers. Industrial sales are expected to increase approximately 1 percent
annually over the next five years.
An increase in energy sales for resale to non-affiliates of 16.1 percent in
2003, 3.1 percent in 2002 and 22.8 percent in 2001 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. Fluctuations
in oil and natural gas prices, which are the primary fuel sources for the unit
power sales customers, influence changes in sales. However, these fluctuations
in energy sales under long-term contracts have minimal effects on earnings
because the energy is generally sold at variable cost. 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 2003 increased $51.4 million, or 7.6 percent, over
the amount recorded in 2002 due primarily to higher fuel and operating costs. In
2002 total operating expenses increased $67.0 million, or 11 percent, compared
to 2001 due primarily to higher fuel and maintenance costs. In 2001, total
operating expenses increased $13.5 million, or 2.3 percent, from the prior year
due primarily to higher purchased power expenses and maintenance expenses.
In 2003, other operation and maintenance expense increased $11 million, or
5.3 percent, primarily due to an increase of $1.6 million of customer accounts
expense and an increase of $7.1 million in the accumulated provision for
property damage. See Note 1 to the financial statements under "Provision for
Property Damage" for additional information. In 2002, other operation and
maintenance expense increased $23 million, or 12.7 percent, mainly due to
scheduled generating plant maintenance. In 2001, other operation and maintenance
increased by $5 million, or 2.4 percent, primarily due to increased scheduled
maintenance for generating plant and transmission and distribution facilities.
Fuel costs constitute the single largest expense for the Company. The mix
of fuel sources for generation of electricity is determined primarily by demand,
the unit cost of fuel consumed, and the availability of generation resources.
In 2003, fuel expense increased $42.6 million, or 15.6 percent, when
compared to 2002 due primarily to increased generation to meet the demand for
energy and higher average cost of fuel. 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.
The amount and sources of generation, the average cost of fuel per net
kilowatt-hour generated, and the average costs of purchased power were as
follows:
2003 2002 2001
----------------------------------
Total generation
(millions of kilowatt-hours) 14,988 13,142 11,423
Sources of generation
(percent)
Coal 86.9 81.8 99.0
Gas 13.1 18.2 1.0
Average cost of fuel per net
kilowatt-hour generated
(cents)-- 2.11 2.08 1.76
Average cost of purchase
power per net kilowatt-hour 3.07 2.71 4.29
- ------------------------------------------------------------------------
Purchased power expense decreased in 2003 $12.3 million, or 19.5 percent,
primarily due to a decrease in the volume of energy needed to meet the Company's
load requirements. Purchased power expense decreased in 2002 by $43.2 million,
or 40.7 percent, due primarily to the additional generating capacity from the
Company's Plant Smith Unit 3. Purchased power expense for 2001 increased by
$23.8 million, or 28.8 percent, due primarily to an increase in purchased power
from affiliate companies.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2003 Annual Report
Fuel costs and purchases of energy will vary from year to year depending on
demand and the availability and cost of generating resources. These costs do not
have a significant impact on earnings, since they are generally offset by
revenues through the Company's fuel cost recovery mechanism.
Depreciation and amortization expense increased $5.3 million, or 6.9
percent, in 2003 primarily due to the commercial operation of Plant Smith Unit 3
beginning in April 2002 and the amortization of a regulatory asset. 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 beginning in
April 2002. Depreciation and amortization expense increased $1.3 million, or 2.0
percent, in 2001 due to an increase in depreciable property and the amortization
of a regulatory asset.
Allowance for equity funds used during construction decreased $2.3 million,
or 76.1 percent, in 2003 and $2.4 million, or 44.5 percent, in 2002 primarily
due to the completion of Plant Smith Unit 3 beginning in April 2002. See Note 1
to the financial statements under "Allowance for Funds Used During Construction
and Interest Capitalized" for further information.
Interest expense decreased $0.4 million, or 1.2 percent, in 2003 due
primarily to the refinancing of $173 million of senior notes and pollution
control bonds at more favorable interest rates. Interest expense increased $6.4
million, or 25.6 percent, in 2002 due primarily to the issuance of $180 million
of senior notes in 2001 and 2002 that 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.
Effects of Inflation
The Company is subject to rate regulation 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 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 in the Company's approved
electric rates.
Future Earnings Potential
General
The results of 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. These factors include the ability of the
Company to maintain a stable regulatory environment, to achieve energy sales
growth while containing costs, and to recover costs related to growing demand
and increasingly stricter environmental standards. 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, new energy
contracts with neighboring utilities, energy conservation practiced by
customers, the price of electricity, the price elasticity of demand, and the
rate of economic growth in the Company's service area.
Industry Restructuring
The Company operates as a vertically integrated utility providing electricity to
customers within its traditional service area located in northwest Florida and
to wholesale customers in the Southeast. Prices for electricity provided by the
Company to retail customers are set by the FPSC under cost-based regulatory
principles. Retail rates and earnings are reviewed and adjusted periodically
within certain limitations based on earned return on equity.
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
allowed independent power producers to access a utility's transmission network
and sell electricity to other utilities.
Although the Energy Act does not provide for retail customer access, it was
a major catalyst for restructuring and consolidations that took place within the
utility industry. Numerous federal and state initiatives that promote wholesale
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2003 Annual Report
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, as well as the August 2003 power outage in
the Northeast.
In 2000, Florida's Governor appointed a study commission to look at the
state's electric industry, studying issues including 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, legislation will have to be drafted and voted into law by the Florida
Legislature. No legislation of this type has been voted on to date. 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.
Since 2001, merchant energy companies and traditional electric utilities
with significant energy marketing and trading activities have come 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 adverse financial impact regarding its limited energy trading
operations through Southern Company Services (SCS) and its recent generating
capacity additions.
Continuing to be a low-cost producer could provide opportunities to
increase the size and profitability of the electricity sales business in markets
that evolve with changing regulation and competition. Conversely, future
regulatory changes could adversely affect the Company's growth, and 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.
Environmental Matters
New Source Review 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 alleged violations of the New Source Review (NSR)
provisions of the Clean Air Act with respect to five coal-fired generating
facilities in Alabama and Georgia. The civil action requested 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 retail operating companies notices of violation relating to ten
generating facilities, which included the five facilities mentioned previously
and the Company's Plants Crist and Scherer. In early 2000, the EPA filed a
motion to amend its complaint to add the violations alleged in its notices of
violation and to add the Company, Mississippi Power, and Savannah Electric as
defendants. However, in March 2001, the court denied the motion with respect to
the Company and Mississippi Power based on lack of jurisdiction, and the EPA has
not refiled. See Note 3 to the financial statements under "New Source Review
Actions" for additional information.
In December 2002 and October 2003, the EPA issued final revisions to its
NSR regulations under the Clean Air Act. The December 2002 revisions included
changes to the regulatory exclusions and the methods of calculating emissions
increases. The October 2003 regulations clarified the scope of the existing
Routine Maintenance, Repair, and Replacement exclusion. A coalition of states
and environmental organizations filed petitions for review of these revisions
with the U.S. Court of Appeals for the District of Columbia Circuit. On December
24, 2003, the Court of Appeals granted a stay of the October 2003 revisions
pending its review of the rules and ordered that its review be conducted on an
expedited basis. In January 2004, the Bush Administration announced that it
II-164
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2003 Annual Report
would continue to enforce the existing rules until the courts resolve legal
challenges to the EPA's revised NSR regulations. In any event, the final
regulations must be adopted by the state of Florida in order to apply to the
Company's facilities. The effect of these final regulations and the related
legal challenges cannot be determined 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
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
- -- both capital and operating -- a major portion of which is expected to be
recovered through existing ratemaking provisions. Environmental costs that are
known and estimable at this time are included in capital expenditures discussed
under "Capital Requirements and Contractual Obligations." The Florida
Legislature has 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. 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. 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. Title IV compliance
was effective in 2000 and associated construction expenditures totaled
approximately $42 million for the Company.
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
eight-hour ozone standard unlawful and remanded it to the EPA for further
rulemaking. During 2003, the EPA proposed implementation rules designed to
address the court's concerns.
Based on recommendations from the State, the EPA is expected to designate
areas of Florida as attainment or nonattainment with the new eight-hour ozone
and particulate standards in April 2004 and with the new fine particulate matter
standard by the end of 2004. In August 2002, the Company entered into an
agreement with the Florida Department of Environmental Protection (FDEP) calling
for nitrogen oxide (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 Plant Crist Unit 7 by 2005. In addition, the Company agreed to
retire Plant Crist Unit 1 in 2003 and Units 2 and 3 by 2006. The conditions of
the agreement will be fully implemented by 2006 at a cost of approximately $133
million, of which $99 million remains to be spent. Costs for implementation of
the agreement have been approved for recovery through the Environmental Cost
Recovery Clause.
In January 2004, the EPA issued a proposed Interstate Air Quality Rule to
address interstate transport of ozone and fine particles. This proposed rule
would require additional year-round sulfur dioxide and nitrogen oxide emission
reductions from power plants in the eastern United States in two phases - in
2010 and 2015. The EPA currently plans to finalize this rule by 2005. If
finalized, the rule could modify or supplant other State Implementation Plan
(SIP) requirements for attainment of the fine particulate matter standard and
the eight-hour ozone standard. The impact of this rule on the Company will
depend upon the specific requirements of the final rule and cannot be determined
at this time.
Further reductions in sulfur dioxide and nitrogen oxides 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
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2003 Annual Report
calls for states to submit SIPs in 2007. The SIPs must contain emission
reduction strategies for implementing BART and achieving progress toward the
Clean Air Act's 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.
The EPA has entered into an agreement that requires proposed revised rules in
April 2004 and final rules in 2005. Because new BART rules have not been
developed and state visibility assessments for progress 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. In 2004 and 2005, a number of
the Company's plants will likely become subject to CAM requirements for at least
one pollutant, in most cases, particulate matter. The Company is in the process
of developing CAM plans. Because the plans are still under development, the
Company cannot determine the costs associated with implementation of the CAM
regulations at this time. Actual ongoing monitoring costs are expensed as
incurred and are not material for any year presented.
In January 2004, the EPA issued proposed rules regulating mercury emissions
from electric utility boilers. The proposal solicits comments on two possible
approaches for the new regulations - a Maximum Achievable Control Technology
approach and a cap-and-trade approach. Either approach would require significant
reductions in mercury emissions from company facilities. The regulations are
scheduled to be finalized by the end of 2004, and compliance could be required
as early as 2007. Because the regulations have not been finalized, the impact on
the Company cannot be determined at this time.
Several major bills to amend the Clean Air Act to impose more stringent
emissions limitations on power plants have been proposed by Congress. Three of
these, the Bush Administration's Clear Skies Act, the Clean Power Act of 2003,
and the Clean Air Planning Act of 2003, propose to further limit power plant
emissions of sulfur dioxide, nitrogen oxides, and mercury. The latter two bills
also propose to limit emissions of carbon dioxide. The cost impacts of such
legislation would depend upon the specific requirements enacted and cannot be
determined at this time.
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, known
as Climate VISION, 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.
Through Southern Company, the Company is involved in a voluntary electric
utility industry sector climate change initiative in partnership with the
government. The electric utility sector has pledged to reduce its greenhouse gas
intensity 3 to 5 percent over the next decade and is in the process of
developing a memorandum of understanding with the Department of Energy (DOE) to
cover this voluntary program.
The Company must comply with other environmental laws and regulations that
cover the handling and disposal of 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 for clean up and ongoing monitoring of known sites. Amounts for clean
up and ongoing monitoring costs were not material for any year presented. The
Company may be liable for some or all required cleanup costs for additional
sites that may require environmental remediation.
Under the Clean Water Act, the EPA has been developing new rules aimed at
reducing impingement and entrainment of fish and fish larvae at power plants
cooling water intake structures. On February 16, 2004, the EPA finalized these
rules. These rules will require biological studies and, perhaps, retrofits to
some intake structures at existing power plants. The impact of these new rules
will depend on the results of studies and analyses performed as part of the
rules' implementation.
In addition, 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 that
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2003 Annual Report
discharge 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.
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 or
regulations related to global climate change, electromagnetic fields or other
environmental and health concerns could also significantly affect the Company.
The impact of any new legislation, changes to existing legislation, or
environmental regulations could affect many areas of the Company's operations.
The full impact of any such changes cannot, however, be determined at this time.
FERC Matters
Transmission
In December 1999, the Federal Energy Regulatory Commission (FERC) issued its
final rule (Order 2000) on Regional Transmission Organizations (RTOs). Order
2000 encouraged utilities owning transmission systems to form RTOs on a
voluntary basis. Southern Company and its retail operating companies, including
the Company, worked with a number of utilities in the Southeast to develop a
for-profit RTO known as SeTrans. In 2002, the sponsors of SeTrans established a
Stakeholder Advisory Committee to provide input into the development of the RTO
from other sectors of the electric industry, as well as consumers. During the
development of SeTrans, state regulatory authorities expressed concern over
certain aspects of the FERC's policies regarding RTOs. In December 2003, the
SeTrans sponsors announced that they would suspend work on SeTrans because the
regulated utility participants, including the Company, had determined that they
were highly unlikely to obtain support of both federal and state regulatory
authorities. Any impact of the FERC's rule on the Company will depend on the
regulatory reaction to the suspension of SeTrans and future developments, which
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 day ahead and spot energy markets;
and (7) revise the FERC policy on the pricing of transmission expansions.
Comments on the proposal were submitted by many interested parties, including
Southern Company, and the FERC has indicated that it has revised certain aspects
of the proposal in response to public comments. Proposed energy legislation
would prohibit the FERC from issuing the final rule before October 31, 2006, and
from making any final rule effective before December 31, 2006. That legislation
has been approved by the House of Representatives but remains pending before the
Senate. Passage of the legislation now appears in doubt. It is uncertain whether
in the absence of legislation the FERC will move forward with any part or all of
the proposed rule. Any impact of this proposal on the Company will depend on the
form in which the final rule may be ultimately adopted. However, the Company's
financial statements could be adversely affected by changes in the transmission
regulatory structure in its regional power market.
Market-Based Rate Authority
The Company has obtained FERC approval to sell power to nonaffiliates at
market-based prices under specific contracts. Through SCS, as agent, the Company
also has the FERC authority to make short-term opportunity sales at market
rates. Specific FERC approval must be obtained with respect to a market-based
contract with an affiliate. In November 2001, the FERC modified the test it uses
to consider utilities' applications to charge market-based rates and adopted a
new test called the Supply Margin Assessment (SMA). The FERC applied the SMA to
several utilities, including Southern Company's retail operating companies, and
found them to be "pivotal suppliers" in their service areas. SCS, on behalf of
the Company and the other retail operating companies, sought rehearing of the
FERC order, and the FERC delayed the implementation of certain mitigation
measures. SCS, on behalf of the Company and the other retail operating
companies, submitted comments to the FERC in 2002 regarding these issues. In
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2003 Annual Report
December 2003, the FERC issued a staff paper discussing alternatives and held a
technical conference in January 2004. The Company anticipates that the FERC will
address the requests for rehearing in the near future. Regardless of the outcome
of the SMA proposal, the FERC retains the ability to modify or withdraw the
authorization for any seller to sell at market-based rates if it determines that
the underlying conditions for having such authority are no longer applicable.
The final outcome of this matter will depend on the form in which the SMA test
and mitigation measures rules may be ultimately adopted and cannot be determined
at this time.
Other Matters
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 $4.9 million, $5.6 million, and $5.9
million in 2003, 2002, and 2001, respectively. Future pension income is
dependent on several factors including trust earnings and changes to the plan.
The decline in pension income is expected to continue and become an expense as
early as 2006. Postretirement benefit costs for the Company were $4.9 million,
$4.5 million, and $4.5 million in 2003, 2002, and 2001, respectively, 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. Pension income or expense and postretirement benefit costs are
components of the regulated rates and generally do not have a long-term effect
on net income. For more information regarding pension and postretirement
benefits, see Note 2 to the financial statements.
On December 8, 2003, President Bush signed into law the Medicare
Prescription Drug, Improvement and Modernization Act of 2003 (Medicare Act). The
Medicare Act introduces a prescription drug benefit for Medicare-eligible
retirees starting in 2006, as well as a federal subsidy to plan sponsors like
the Company that provide prescription drug benefits. In accordance with FASB
Staff Position No. 106-1, the Company has elected to defer recognizing the
effects of the Medicare Act for its postretirement plans under FASB Statement
No. 106, Employers' Accounting for Postretirement Benefits Other than Pension
until authoritative guidance on accounting for the federal subsidy is issued or
until a significant event occurs that would require remeasurement of the plans'
assets and obligations. The Company anticipates that the benefits it pays after
2006 will be lower as a result of the Medicare Act; however, the retiree medical
obligations and costs reported in Note 2 to the financial statements do not
reflect these changes. The final accounting guidance could require changes to
previously reported information.
In May 2002, the FPSC approved a retail base rate increase of $53.2 million
effective June 7, 2002, the majority of which was related to Plant Smith Unit 3,
which was placed in service beginning in April 2002. See Note 3 to the financial
statements for additional information about these and other regulatory matters.
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 new rule was made effective June 17, 2003.
The FPSC, in collaboration with the FDEP, was directed by the Florida
Legislature to prepare a report on renewable energy. A final report was prepared
by the FPSC and the FDEP in January 2003. This report describes various
renewable and green energy options. The report provided the FPSC, the FDEP, and
the Florida 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
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2003 Annual Report
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 a benefits charge that could not be
passed on to customers by the state could add additional costs to the Company's
operations and affect the Company's competitive position.
The Company is involved in various matters being litigated and regulatory
matters that could affect future earnings. See Note 3 to the financial
statements for information regarding material issues.
ACCOUNTING POLICIES
- -------------------
Application of Critical Accounting Policies and
Estimates
The Company prepares its financial statements in accordance with accounting
principles generally accepted in the United States. Significant accounting
policies are described in Note 1 to the financial statements. In the application
of these policies, certain estimates are made that may have a material impact on
the Company's results of operations and related disclosures. Different
assumptions and measurements could produce estimates that are significantly
different from those recorded in the financial statements. Senior management has
discussed the development and selection of the critical accounting policies and
estimates described below with the Controls and Compliance Committee of the
Company's Board of Directors and the Audit Committee of Southern Company's Board
of Directors.
Electric Utility Regulation
The Company is subject to retail regulation by the FPSC and wholesale regulation
by the FERC. These regulatory agencies set the rates the Company is permitted to
charge customers based on allowable costs. As a result, the Company applies FASB
Statement No. 71, Accounting for the Effects of Certain Types of Regulation.
Through the ratemaking process, the regulators may require the inclusion of
costs or revenues in periods different than when they would be recognized by a
non-regulated company. This treatment may result in the deferral of expenses and
the recording of related regulatory assets based on anticipated future recovery
through rates or the deferral of gains or creation of liabilities and the
recording of related regulatory liabilities. The application of Statement No. 71
has a further effect on the Company's financial statements as a result of the
estimates of allowable costs used in the ratemaking process. These estimates may
differ from those actually incurred by the Company; therefore, the accounting
estimates inherent in specific costs such as depreciation and pension and
post-retirement benefits have less of a direct impact on the Company's results
of operations than they would on a non-regulated company.
As reflected in Note 1 to the financial statements, significant regulatory
assets and liabilities have been recorded. Management reviews the ultimate
recoverability of these regulatory assets and liabilities based on applicable
regulatory guidelines. However, adverse legislation and judicial or regulatory
actions could materially impact the amounts of such regulatory assets and
liabilities and could adversely impact the Company's financial statements.
Contingent Obligations
The Company is subject to a number of federal and state laws and regulations, as
well as other factors and conditions that potentially subject it to
environmental, litigation, income tax, and other risks. See "Future Earnings
Potential" and Note 3 to the financial statements for more information regarding
certain of these contingencies. The Company periodically evaluates its exposure
to such risks and records reserves for those matters where a loss is considered
probable and reasonably estimable in accordance with generally accepted
accounting principles. The adequacy of reserves can be significantly affected by
external events or conditions that can be unpredictable; thus, the ultimate
outcome of such matters could materially affect the Company's financial
statements. These events or conditions include the following:
o Changes in existing state or federal regulation by governmental authorities
having jurisdiction over air quality, water quality, control of toxic
substances, hazardous and solid wastes, and other environmental matters.
o Changes in existing income tax regulations or changes in Internal Revenue
Service interpretations of existing regulations.
o Identification of additional sites that require environmental remediation or
the filing of other complaints in which the Company may be asserted to be a
potentially responsible party.
o Identification and evaluation of other potential lawsuits or complaints in
which the Company may be named as a defendant.
o Resolution or progression of existing matters through the legislative
process, the court systems, or the EPA.
II-169
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2003 Annual Report
New Accounting Standards
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,
established 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 is recorded in the
period in which the liability is incurred. The cost is capitalized as part of
the related long-lived asset and depreciated over the asset's useful life. For
more information regarding the impact of adopting this standard effective
January 1, 2003, see Note 1 to the financial statements under "Asset Retirement
Obligations and Other Costs of Removal."
FASB Statement No. 149, Amendment of Statement 133 on Derivative
Instruments and Hedging Activities, which further amends and clarifies the
accounting and reporting for derivative instruments, became effective generally
for financial instruments entered into or modified after June 30, 2003. Current
interpretations of Statement No. 149 indicate that certain electricity forward
transactions subject to unplanned netting -- including those typically referred
to as "book outs" -- may only qualify as cash flow hedges if an entity can
demonstrate that physical delivery or receipt of power occurred. The Company's
forward electricity contracts continue to be exempt from fair value accounting
requirements or to qualify as cash flow hedges. The implementation of Statement
No. 149 did not have a material effect on the Company's financial statements.
In July 2003, the Emerging Issues Task Force (EITF) of FASB issued EITF No.
03-11, which became effective on October 1, 2003. The standard addresses the
reporting of realized gains and losses on derivative instruments and is being
interpreted to require book outs to be recorded on a net basis in operating
revenues. Adoption of this standard did not have a material impact on the
Company's financial statements.
FASB Interpretation No. 46, Consolidation of Variable Interest Entities,
which was originally issued in January 2003, requires the primary beneficiary of
a variable interest entity to consolidate the related assets and liabilities. In
December 2003, the FASB revised Interpretation No. 46 and deferred the effective
date until March 31, 2004 for interests held in variable interest entities other
than special purpose entities.
Current analysis indicates that the trusts established by the Company to
issue preferred securities are variable interest entities under Interpretation
No. 46, and that the Company is not the primary beneficiary of these trusts. If
this conclusion is finalized, effective March 31, 2004, the trust assets and
liabilities-- including the preferred securities issued by the trusts-- will be
deconsolidated. The investments in the trusts and the loans from the trusts to
the Company will be reflected as equity method investments and as long-term
notes payable to affiliates, respectively, on the Balance Sheets. Based on
December 31, 2003 values, this treatment would result in an increase of
approximately $2.2 million to both total assets and total liabilities. See Note
6 to the financial statements under "Mandatorily Redeemable Preferred
Securities" for additional information.
In May 2003, the FASB issued Statement No. 150, Accounting for Certain
Financial Instruments with Characteristics of Both Liabilities and Equity, which
requires classification of certain financial instruments within its scope,
including shares that are mandatorily redeemable, as liabilities. Statement No.
150 was effective for financial instruments entered into or modified after May
31, 2003, and otherwise on July 1, 2003. In accordance with Statement No. 150,
mandatorily redeemable preferred securities are reflected on the Balance Sheets
as liabilities. The adoption of Statement No. 150 had no impact on the
Statements of Income and Cash Flows.
FINANCIAL CONDITION AND LIQUIDITY
- ---------------------------------
Overview
The Company's financial condition continues to be strong. The Company operated
at high levels of reliability while achieving industry-leading customer
satisfaction levels and continuing to have retail prices below the national
average.
The Company's ratio of common equity to total capitalization -- including
short-term debt -- was 45.3 percent in 2003, 44.0 percent in 2002, and 42.8
percent in 2001. See Note 6 to the financial statements for additional
information.
II-170
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2003 Annual Report
During 2003, gross property additions were $99 million. Funds for the
Company's property additions were provided by operating activities, capital
contributions, and other financing activities. See the Statements of Cash Flows
for additional information.
Sources of Capital
The Company plans to obtain the funds required for construction and other
purposes, including compliance with environmental regulations, from sources
similar to those used in the past. These sources include operating cash flow,
the issuance of unsecured debt and preferred securities, in addition to
pollution control revenue bonds issued for the Company's benefit by public
authorities. However, the type and timing of any future financings--if
needed--will depend on market conditions and regulatory approval.
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.
The Company obtains financing separately without credit support from any
affiliate. The Southern Company system does not maintain a centralized cash or
money pool. Therefore, funds of the Company are not commingled with funds of any
other company. In accordance with the Public Utility Holding Company Act, most
loans between affiliated companies must be approved in advance by the Securities
and Exchange Commission (SEC).
To meet short-term cash needs and contingencies, the Company has various
internal and external sources of liquidity. At the beginning of 2004, the
Company had approximately $2.5 million of cash and cash equivalents, along with
$56.0 million of unused committed lines of credit with banks to meet its
short-term cash needs. In addition, the Company has substantial cash flow from
operating activities.
At the beginning of 2004, the Company had used none of its available credit
arrangements. Bank credit arrangements are as follows:
Expires
Total Unused 2004 2005 & beyond
- ----------------------------------------------------------------
(in millions)
$56.0 $56.0 $56.0 $-
- ----------------------------------------------------------------
See Note 6 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 retail operating companies. Proceeds from such issuances for
the benefit of the Company are loaned directly to the Company and are not
commingled with proceeds from such issuances for the benefit of any other
operating company. There is no cross affiliate credit support. At December 31,
2003, the Company had outstanding $37.7 million of commercial paper.
Financing Activities
During 2003, the Company issued $286.6 million of long-term debt. The
issuances were used to refund $173.3 million of long-term debt and $45 million
of mandatorily redeemable preferred securities and to pay at maturity $60
million of senior notes due August 1, 2003. The remainder was used to reduce
short-term debt.
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.
Market Price Risk
Due to cost-based rate regulation, the Company has limited exposure to market
volatility in interest rates, commodity fuel prices, and prices of electricity.
To 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.
II-171
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2003 Annual Report
To mitigate exposure to interest rates, the Company has entered into an
interest rate swap that was designated as a hedge. The weighted average interest
rate on $145 million variable long-term debt that has not been hedged
outstanding at December 31, 2003 was 1.2 percent. If the Company sustained a 100
basis point change in interest rates for all unhedged variable rate long-term
debt, the change would affect annualized interest expense by approximately $1.4
million at December 31, 2003. 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 6 to the financial statements under
"Financial Instruments."
The fair value of changes in energy-related derivative contracts and
year-end valuations were as follows at December 31:
Changes in Fair Value
- ----------------------------------------------------------------
2003 2002
- ----------------------------------------------------------------
(in thousands)
Contracts beginning of year $ 2,326 $ (110)
Contracts realized or settled (5,098) 150
New contracts at inception - -
Changes in valuation techniques - -
Current period changes 5,265 2,296
- ----------------------------------------------------------------
Contracts end of year $ 2,493 $2,336
================================================================
Source of 2003 Year-End Valuation Prices
- ----------------------------------------------------------------
Total Maturity
Fair Value 2004 2005-2006
- ----------------------------------------------------------------
(in thousands)
Actively quoted $2,503 $2,671 $(168)
External source - - -
Models and other
methods - - -
- ----------------------------------------------------------------
Contracts end of year $2,503 $2,671 $(168)
================================================================
Unrealized gains and losses from mark to market adjustments on derivative
contracts related to the Company's 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 derivative contracts that are not
designated as hedges are recognized in the Income Statement as incurred. For the
years ended December 31, 2003, 2002, and 2001, these amounts were not material.
At December 31, 2003, the fair value of derivative energy contracts was
reflected in the financial statements as follows:
Amounts
- ----------------------------------------------------------------
(in thousands)
Regulatory liabilities, net $2,501
Other comprehensive income -
Net income 2
- ----------------------------------------------------------------
Total fair value $2,503
================================================================
Unrealized gains (losses) recognized in income in 2003 and 2002 were not
material. The Company is exposed to market price risk in the event of
nonperformance by counterparties 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 6 to the financial statements under "Financial Instruments."
Capital Requirements and Contractual Obligations
The construction program of the Company is currently estimated to be $166
million in 2004, $149 million in 2005, and $108 million in 2006. These amounts
include $64 million, $31 million, and $4 million in 2004, 2005, and 2006,
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. 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. In
addition, there can be no assurance that costs related to capital expenditures
will be fully recovered.
The Company does not have any new generating capacity scheduled to be
placed in service through 2006. Construction of new transmission and
distribution facilities and capital improvements, including those needed to meet
environmental standards for the Company's existing generation, transmission and
distribution facilities are ongoing.
As discussed in Note 2 to the financial statements, the Company provides
post retirement benefits to substantially all employees and funds trusts to the
extent required by the FERC.
II-172
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2003 Annual Report
Other funding requirements related to obligations associated with scheduled
maturities of long-term debt and preferred securities, as well as the related
interest and distributions, preferred stock dividends, leases, and other
purchase commitments are as follows. See Notes 1, 6, and 7 to the financial
statements for additional information.
2005- 2007- After
2004 2006 2008 2008 Total
- ---------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Long-term debt and preferred securities(a) --
Principal $ 50,000 $ 37,075 $ - $ 557,555 $ 644,630
Interest and distributions 30,903 54,756 50,238 508,841 644,738
Preferred stock dividends(b) 217 434 434 - 1,085
Operating leases 1,995 4,142 4,075 8,153 18,365
Purchase commitments(c) --
Capital(d) 166,020 257,173 256,391 947,638 1,627,222
Coal 132,117 155,224 96,433 - 383,774
Natural gas(e) 103,952 124,185 64,240 259,155 551,532
Purchased power 744 310 - - 1,054
Long-term service agreements 7,031 14,834 15,789 46,538 84,192
Postretirement benefit trusts(f) 80 160 - - 240
- ---------------------------------------------------------------------------------------------------------------------------------
Total $493,059 $648,293 $487,600 $2,327,880 $3,956,832
=================================================================================================================================
(a) All amounts are reflected based on final maturity dates. The Company will continue to retire higher-cost securities and
replace these obligations with lower-cost capital if market conditions permit. Variable rate interest obligations are
estimated based on rates as of January 1, 2004, as reflected in the Statements of Capitalization.
(b) Preferred stock does not mature; therefore, amounts are provided for the next five years only.
(c) The Company generally does not enter into non-cancelable commitments for other operation and maintenance expenditures.
Total other operation and maintenance expenses for the last three years were $211 million, $200 million, and $177 million,
respectively.
(d) The Company forecasts capital expenditures over a three-year period. Amounts represent current estimates of total
expenditures. At December 31, 2003, significant purchase commitments were outstanding in connection with the construction
program.
(e) Natural gas purchase commitments are based on various indices at the time of delivery. Amounts reflected have been estimated
based on New York Mercantile future prices at December 31, 2003.
(f) The Company forecasts trust postretirement contributions over a three-year period. No contributions related to the Company's
pension trust are currently expected during this period. See Note 2 to the financial statements for additional information
related to the pension plans.
II-173
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2003 Annual Report
Cautionary Statement Regarding Forward-Looking Information
The Company's 2003 Annual Report includes forward-looking statements in addition
to historical information. Forward-looking information includes, among other
things, statements concerning the estimated construction and other expenditures
and the Company's projections for energy sales. 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:
o 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, tax, and other laws and regulations to which the
Company are subject, as well as changes in application of existing laws and
regulations;
o current and future litigation, regulatory investigations, proceedings, or
inquiries, including current IRS audits;
o the effects, extent, and timing of the entry of additional competition in
the markets in which the Company operates;
o the impact of fluctuations in commodity prices, interest rates, and customer
demand;
o available sources and costs of fuels;
o ability to control costs;
o investment performance of the Company's employee benefit plans;
o advances in technology;
o state and federal rate regulations and pending and
future rate cases and negotiations;
o effects of and changes in political, legal, and economic conditions and
developments in the United States, including the current soft economy;
o potential business strategies, including acquisitions or dispositions of
assets, which cannot be assured to be completed or beneficial to the
Company;
o the ability of counterparties of the Company to make payments as and when
due;
o the ability to obtain new short- and long-term contracts with neighboring
utilities:
o the direct or indirect effects on the Company's business resulting from the
terrorist incidents on September 11, 2001, or any similar incidents or
responses to such incidents;
o financial market conditions and the results of financing efforts, including
the Company's credit ratings;
o the ability of the Company to obtain additional generating capacity at
competitive prices;
o weather and other natural phenomena;
o the direct or indirect effects on the Company's business resulting
from the August 2003 power outage in the Northeast, or any similar incidents;
o the effect of accounting pronouncements issued periodically by
standard-setting bodies; and
o other factors discussed elsewhere herein and in other reports (including
the Form 10-K) filed from time to time by the Company with the SEC.
II-174
STATEMENTS OF INCOME
For the Years Ended December 31, 2003, 2002, and 2001
Gulf Power Company 2003 Annual Report
- -------------------------------------------------------------------------------------------------------------------------
2003 2002 2001
- -------------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Revenues:
Retail sales $699,174 $665,836 $584,591
Sales for resale --
Non-affiliates 76,767 77,171 82,252
Affiliates 63,268 40,391 27,256
Other revenues 38,488 37,069 31,104
- -------------------------------------------------------------------------------------------------------------------------
Total operating revenues 877,697 820,467 725,203
- -------------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Fuel 316,503 273,860 200,633
Purchased power --
Non-affiliates 17,137 23,797 65,585
Affiliates 33,020 39,201 40,660
Other operations 140,166 124,654 117,394
Maintenance 70,534 75,421 60,193
Depreciation and amortization 82,322 77,014 68,218
Taxes other than income taxes 66,115 61,033 55,261
- -------------------------------------------------------------------------------------------------------------------------
Total operating expenses 725,797 674,980 607,944
- -------------------------------------------------------------------------------------------------------------------------
Operating Income 151,900 145,487 117,259
Other Income and (Expense):
Allowance for equity funds used during construction 712 2,980 5,373
Interest income 888 572 1,258
Interest expense, net of amounts capitalized (31,069) (31,452) (25,034)
Distributions on mandatorily redeemable preferred securities (7,085) (8,524) (6,477)
Other income (expense), net (5,242) (4,666) (2,663)
- -------------------------------------------------------------------------------------------------------------------------
Total other income and (expense) (41,796) (41,090) (27,543)
- ------------------------------------------------------------------------------------------------------------------------
Earnings Before Income Taxes 110,104 104,397 89,716
Income taxes 40,877 37,144 31,260
- -------------------------------------------------------------------------------------------------------------------------
Earnings Before Cumulative Effect of 69,227 67,253 58,456
Accounting Change
Cumulative effect of accounting change--
less income taxes of $42 thousand - - 68
- -------------------------------------------------------------------------------------------------------------------------
Net Income 69,227 67,253 58,524
Dividends on Preferred Stock 217 217 217
- -------------------------------------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred Stock $ 69,010 $ 67,036 $ 58,307
=========================================================================================================================
The accompanying notes are an integral part of these financial statements.
II-175
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2003, 2002, and 2001
Gulf Power Company 2003 Annual Report
- ------------------------------------------------------------------------------------------------------------------------------
2003 2002 2001
- ------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Activities:
Net income $ 69,227 $ 67,253 $ 58,524
Adjustments to reconcile net income
to net cash provided from operating activities --
Depreciation and amortization 87,949 82,230 72,320
Deferred income taxes 2,303 9,619 3,394
Pension, postretirement, and other employee benefits (717) (8,170) 511
Tax benefit of stock options 1,768 1,043 -
Settlement of interest rate hedge (3,266) - -
Other, net 6,829 5,756 (2,315)
Changes in certain current assets and liabilities --
Receivables, net 8,223 (28,173) 15,991
Fossil fuel stock 1,837 10,464 (30,887)
Materials and supplies (1,091) (5,982) 176
Other current assets 12,207 (14,178) (29,735)
Accounts payable (1,105) 19,168 (7,289)
Accrued taxes (549) 1,117 (4,560)
Other current liabilities 7,576 (4,251) (2,627)
- ------------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities 191,191 135,896 73,503
- ------------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (99,284) (106,624) (274,668)
Cost of removal net of salvage (7,881) (7,978) (5,620)
Other (4,440) (9,745) 10,910
- ------------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities (111,605) (124,347) (269,378)
- ------------------------------------------------------------------------------------------------------------------------------
Financing Activities:
Increase (decrease) in notes payable, net 9,187 (58,831) 44,311
Proceeds --
Pollution control bonds 61,625 55,000 -
Senior notes 225,000 45,000 135,000
Mandatorily redeemable preferred securities - 40,000 30,000
Capital contributions from parent company 13,315 42,766 72,484
Redemptions --
First mortgage bonds - - (30,000)
Pollution control bonds (61,625) (55,000) -
Senior notes (151,757) (454) (862)
Other long-term debt (20,000) - -
Mandatorily redeemable preferred securities (85,000) - -
Payment of preferred stock dividends (217) (217) (217)
Payment of common stock dividends (70,200) (65,500) (53,275)
Other (10,644) (3,279) (3,703)
- ------------------------------------------------------------------------------------------------------------------------------
Net cash provided from (used for) financing activities (90,316) (515) 193,738
- ------------------------------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents (10,730) 11,034 (2,137)
Cash and Cash Equivalents at Beginning of Period 13,278 2,244 4,381
- ------------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ 2,548 $ 13,278 $ 2,244
==============================================================================================================================
Supplemental Cash Flow Information:
Cash paid during the period for --
Interest (net of $314, $1,392, and $2,510 capitalized,
respectively) $37,468 $39,604 $30,813
Income taxes (net of refunds) 23,777 34,048 33,349
- ------------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
II-176
BALANCE SHEETS
At December 31, 2003 and 2002
Gulf Power Company 2003 Annual Report
- ------------------------------------------------------------------------------------------------------------------------------
Assets 2003 2002
- ------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Current Assets:
Cash and cash equivalents $ 2,548 $ 13,278
Receivables --
Customer accounts receivable 44,001 48,609
Unbilled revenues 31,548 28,077
Under recovered regulatory clause revenues 21,812 29,549
Other accounts and notes receivable 6,179 6,618
Affiliated companies 9,826 8,678
Accumulated provision for uncollectible accounts (947) (889)
Fossil fuel stock, at average cost 35,354 37,191
Materials and supplies, at average cost 35,930 34,840
Prepaid income taxes 4 12,704
Prepaid expenses 6,310 5,858
Vacation pay 5,254 5,044
Other 4,981 4,278
- ------------------------------------------------------------------------------------------------------------------------------
Total current assets 202,800 233,835
- ------------------------------------------------------------------------------------------------------------------------------
Property, Plant, and Equipment:
In service 2,306,959 2,248,156
Less accumulated provision for depreciation 847,519 803,348
- ------------------------------------------------------------------------------------------------------------------------------
1,459,440 1,444,808
Construction work in progress 49,438 35,708
- ------------------------------------------------------------------------------------------------------------------------------
Total property, plant, and equipment 1,508,878 1,480,516
- ------------------------------------------------------------------------------------------------------------------------------
Other property and investments 12,597 10,157
- ------------------------------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets:
Deferred charges related to income taxes 18,263 18,798
Prepaid pension costs 42,014 36,298
Unamortized debt issuance expense 6,877 3,900
Unamortized loss on reacquired debt 19,389 14,052
Other 28,235 19,333
- ------------------------------------------------------------------------------------------------------------------------------
Total deferred charges and other assets 114,778 92,381
- ------------------------------------------------------------------------------------------------------------------------------
Total Assets $1,839,053 $1,816,889
==============================================================================================================================
The accompanying notes are an integral part of these financial statements.
II-177
BALANCE SHEETS
At December 31, 2003 and 2002
Gulf Power Company 2003 Annual Report
- -------------------------------------------------------------------------------------------------------------------------------
Liabilities and Stockholder's Equity 2003 2002
- -------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Current Liabilities:
Securities due within one year $ 50,000 $100,000
Notes payable 37,666 28,479
Accounts payable --
Affiliated 26,945 26,395
Other 21,952 26,333
Customer deposits 18,271 16,047
Accrued taxes --
Income taxes 6,405 10,718
Other 8,621 9,170
Accrued interest 8,077 7,875
Accrued vacation pay 5,254 5,044
Accrued compensation 13,456 13,352
Other 9,694 6,044
- -------------------------------------------------------------------------------------------------------------------------------
Total current liabilities 206,341 249,457
- -------------------------------------------------------------------------------------------------------------------------------
Long-term debt (See accompanying statements) 515,827 452,040
- -------------------------------------------------------------------------------------------------------------------------------
Mandatorily redeemable preferred securities (See accompanying statements) 70,000 115,000
- -------------------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 175,685 167,689
Deferred credits related to income taxes 26,545 29,692
Accumulated deferred investment tax credits 20,451 22,289
Employee benefit obligations 52,395 47,395
Other cost of removal obligations 151,229 143,060
Miscellaneous regulatory liabilities 27,903 18,278
Other 27,083 18,248
- -------------------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 481,291 446,651
- -------------------------------------------------------------------------------------------------------------------------------
Total liabilities 1,273,459 1,263,148
- -------------------------------------------------------------------------------------------------------------------------------
Preferred stock (See accompanying statements) 4,236 4,236
- -------------------------------------------------------------------------------------------------------------------------------
Common stockholder's equity (See accompanying statements) 561,358 549,505
- -------------------------------------------------------------------------------------------------------------------------------
Total Liabilities and Stockholder's Equity $1,839,053 $1,816,889
===============================================================================================================================
Commitments and Contingent Matters (See notes)
- -------------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
II-178
STATEMENTS OF CAPITALIZATION
At December 31, 2003 and 2002
Gulf Power Company 2003 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------
2003 2002 2003 2002
- -----------------------------------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
Long Term Debt:
First mortgage bonds --
6.50% due November 1, 2006 $ 25,000 $ 25,000
6.88% due January 1, 2026 30,000 30,000
- -----------------------------------------------------------------------------------------------------------------------------
Total first mortgage bonds 55,000 55,000
- -----------------------------------------------------------------------------------------------------------------------------
Long-term notes payable --
4.69% due August 1, 2003 - 60,000
7.05% due August 15, 2004 50,000 50,000
4.35% to 7.50% due 2012-2038 300,000 186,757
- -----------------------------------------------------------------------------------------------------------------------------
Total long-term notes payable 350,000 296,757
- -----------------------------------------------------------------------------------------------------------------------------
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
Non-collateralized:
4.80% due September 1, 2028 13,000 13,000
Variable rates (1.10% to 1.36% at 1/1/04)
due 2022-2037 144,555 82,930
- -----------------------------------------------------------------------------------------------------------------------------
Total other long-term debt 169,630 169,630
- -----------------------------------------------------------------------------------------------------------------------------
Unamortized debt premium (discount), net (8,803) (9,347)
- -----------------------------------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
requirement -- $26.5 million) 565,827 512,040
Less amount due within one year 50,000 60,000
- -----------------------------------------------------------------------------------------------------------------------------
Long-term debt excluding amount due within one year 515,827 452,040 44.7% 40.3%
- -----------------------------------------------------------------------------------------------------------------------------
Mandatorily Redeemable Preferred Securities:
$25 liquidation value --
7.625% due 2036 - 40,000
7.00% due 2037 - 45,000
7.375% due 2041 30,000 30,000
$1,000 liquidation value --
5.60% due 2042* 40,000 40,000
- -----------------------------------------------------------------------------------------------------------------------------
Total (annual distribution requirement -- $4.5 million) 70,000 155,000
Less amount due within one year - 40,000
- -----------------------------------------------------------------------------------------------------------------------------
Mandatorily redeemable preferred securities
excluding amount due within one year 70,000 115,000 6.1 10.3
- -----------------------------------------------------------------------------------------------------------------------------
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
- -----------------------------------------------------------------------------------------------------------------------------
Common Stockholder's Equity:
Common stock, without par value --
Authorized and outstanding -
992,717 shares in 2003 and 2002 38,060 38,060
Paid-in capital 364,852 349,769
Premium on preferred stock 12 12
Retained earnings 161,208 162,398
Accumulated other comprehensive income (loss) (2,774) (734)
- -----------------------------------------------------------------------------------------------------------------------------
Total common stockholder's equity 561,358 549,505 48.8 49.0
- -----------------------------------------------------------------------------------------------------------------------------
Total Capitalization $1,151,421 $1,120,781 100.0% 100.0%
=============================================================================================================================
*Issued to redeem the 7.625% Trust I preferred securities in January 2003 at a five year initial fixed rate of 5.60% 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%.
The accompanying notes are an integral part of these financial statements.
II-179
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
For the Years Ended December 31, 2003, 2002, and 2001
Gulf Power Company 2003 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------
Premium on Other
Common Paid-In Preferred Retained Comprehensive
Stock Capital Stock Earnings Income (loss) Total
- ------------------------------------------------------------------------------------------------------------------------------
(in thousands)
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
Net income after dividends on preferred stock - - - 69,010 - 69,010
Capital contributions from parent company - 15,083 - - - 15,083
Other comprehensive income (loss) - - - - (2,040) (2,040)
Cash dividends on common stock - - - (70,200) - (70,200)
- ------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2003 $38,060 $364,852 $12 $161,208 ($2,774) $561,358
==============================================================================================================================
The accompanying notes are an integral part of these financial statements.
STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2003, 2002, and 2001
Gulf Power Company 2003 Annual Report
- ------------------------------------------------------------------------------------------------------------------
2003 2002 2001
- ------------------------------------------------------------------------------------------------------------------
(in thousands)
Net income after dividends on preferred stock $69,010 $67,036 $58,307
- ------------------------------------------------------------------------------------------------------------------
Other comprehensive income (loss):
Changes in additional minimum pension liability,
net of tax of $(84) and $(461), respectively (134) (734) -
Changes in fair value of qualifying hedges,
net of tax of $(1,260) (2,006) - -
Less: Reclassification adjustment for amounts included in net
income, net of tax of $63 100 - -
- ------------------------------------------------------------------------------------------------------------------
Total other comprehensive income (loss) (2,040) (734) -
- ------------------------------------------------------------------------------------------------------------------
Comprehensive Income $66,970 $66,302 $58,307
==================================================================================================================
The accompanying notes are an integral part of these financial statements.
II-180
NOTES TO FINANCIAL STATEMENTS
Gulf Power Company 2003 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 retail
operating companies, Southern Power Company (Southern Power), Southern Company
Services (SCS), 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 retail operating
companies - Alabama Power, Georgia Power, the Company, Mississippi Power, and
Savannah Electric - provide electric service in four Southeastern states. The
Company operates as a vertically integrated utility providing service to
customers in northwest Florida and to wholesale customers in the Southeast.
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 retail 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, the system service company, provides, at cost, specialized services
to Southern Company and subsidiary companies. Southern LINC provides digital
wireless communications services to the retail 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 is a
competitive retail natural gas marketer serving customers in Georgia. Southern
Holdings is an intermediate holding subsidiary for Southern Company's
investments in synthetic fuels and leveraged leases, and an energy services
business. Southern Nuclear operates and 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, including the Company, 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 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 $56 million, $49 million, and $45 million during 2003,
2002, and 2001, respectively. Cost allocation methodologies used by SCS are
approved by the SEC and management believes they are reasonable.
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 $5.6 million and $4.5 million and Mississippi
Power $17.7 million and $16.6 million in 2003 and 2002, respectively, for its
proportionate share of related expenses. See Note 7 under "Operating Leases" for
additional information.
The retail operating companies (including the Company), Southern Power, and
Southern Company 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.
II-181
NOTES (continued)
Gulf Power Company 2003 Annual Report
Revenues and Regulatory Cost Recovery Clauses
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.
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.
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:
2003 2002 Note
- ----------------------------------------------------------------
(in thousands)
Asset retirement obligations $ 1,019 $ - (a)
Other cost of removal obligations (151,229) (143,060) (a)
Deferred income tax charges 18,263 18,798 (a)
Loss on reacquired debt 19,389 14,052 (b)
Vacation pay 5,254 5,044 (c)
Deferred income tax credits (26,545) (29,692) (a)
Accumulated provision for
property damage (26,244) (15,418) (d)
Environmental remediation 12,878 14,429 (f)
Fuel-hedging liabilities (2,501) (2,322) (e)
Other assets 8,198 2,859 (d)
Other liabilities (3,177) (3,351) (d)
- -------------------------------------------------------
Total $(144,695) $(138,661)
=======================================================
Note: The recovery and amortization periods for these regulatory assets and
(liabilities) are as follows:
(a) Asset retirement and removal liabilities are recorded, deferred income
tax assets are recovered, and deferred tax liabilities are amortized
over the related property lives, which may range up to 50 years. Asset
retirement and removal liabilities will be settled and trued up
following completion of the related activities.
(b) Recovered over the remaining life of the original issue, which may range
up to 50 years.
(c) Recorded as earned by employees and recovered as
paid, generally within one year.
(d) Recorded and recovered or amortized
as approved by the FPSC.
(e) Fuel-hedging liabilities are recorded over the life of the underlying
hedged purchase contracts, which generally do not exceed two years. Upon
final settlement, costs are recovered through the fuel cost recovery
clause.
(f) Recovered through the Environmental Cost Recovery Clause (ECRC) when the
expense is incurred. The estimated completion date for this project is
currently 2012.
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.
Depreciation and Amortization
Depreciation of the original cost of plant in service is provided primarily by
using composite straight-line rates, which approximated 3.8 percent in 2003, 3.9
percent in 2002, and 3.7 percent in 2001. When property subject to depreciation
is retired or otherwise disposed of in the normal course of business, its cost -
II-182
NOTES (continued)
Gulf Power Company 2003 Annual Report
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.
Asset Retirement Obligations
and Other Costs of Removal
In accordance with regulatory requirements, prior to 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 accordance with SEC requirements, such
amounts are reflected on the balance sheet as regulatory liabilities.
Effective January 1, 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 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 the continued accrual of future retirement costs for long-lived
assets that the Company does not have a legal obligation to retire. At the time
of adoption, the Company had received guidance regarding accounting for the
financial statement impacts of Statement No. 143 from the FPSC and in accordance
with that guidance had no cumulative effect to net income resulting from the
adoption of Statement No. 143. The Company will continue to recognize the
accumulated removal costs for other obligations as a regulatory liability.
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, liabilities for the removal
of these transmission and distribution assets have not been recorded because no
reasonable estimate can be made regarding the timing of the obligations. The
Company will continue to recognize in the Income Statement allowed removal costs
in accordance with its regulatory treatment. Any difference between costs
recognized under Statement No. 143 and those reflected in rates are recognized
as either a regulatory asset or liability and are reflected in the Balance
Sheets.
Details of the asset retirement obligations included in the Balance Sheets
are as follows:
2003
- -------------------------------------------------------------------
(in millions)
Balance beginning of year $ -
Liabilities incurred 4.0
Liabilities settled -
Accretion 0.3
Cash flow revisions -
- -------------------------------------------------------------------
Balance end of year $4.3
===================================================================
If Statement No. 143 had been adopted on January 1, 2002, the pro-forma
asset retirement obligations would have been $3.7 million.
Allowance for Funds Used During Construction
(AFUDC) and Interest Capitalized
In accordance with regulatory treatment, the Company records 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, 2003, 2002, and
2001 the average AFUDC rates were 7.48 percent, 7.35 percent, and 7.35 percent,
respectively. AFUDC, net of taxes, as a percentage of net income after dividends
on preferred stock was 1.31 percent, 5.72 percent, and 11.86 percent,
respectively for, 2003, 2002, and 2001.
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
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.
II-183
NOTES (continued)
Gulf Power Company 2003 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 to the carrying value of the
assets. If an impairment has occurred, the amount of the impairment recognized
is determined by either the amount of regulatory disallowance or 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 with 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.
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.
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
that meet the definition of a derivative are exempt from fair value accounting
requirements and are accounted for under the accrual method. Other derivative
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. Other
derivative contracts 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 does not equal
fair value at December 31 were as follows:
Carrying Fair
Amount Value
- -------------------------------------------------------------------
(in thousands)
Long-term debt:
At December 31, 2003 $565,827 $572,899
At December 31, 2002 512,040 531,133
Preferred Securities
At December 31, 2003 $ 70,000 $ 73,376
At December 31, 2002 155,000 156,853
- -------------------------------------------------------------------
The fair values were based on either closing market price or closing price
of comparable instruments.
II-184
NOTES (continued)
Gulf Power Company 2003 Annual Report
Comprehensive Income
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. Comprehensive
income consists 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.
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 cost of settling claims is charged to a provision account.
The accumulated provision of $0.1 million and $0.7 million at December 31, 2003
and 2002, respectively, is included in other current liabilities in the
accompanying Balance Sheets. For further information, see Note 3 under "Personal
Injury Litigation." In addition to the provision, at December 31, 2003, the
Company recorded a liability with a corresponding regulatory asset of $6.9
million for estimated liabilities related to outstanding claims and suits.
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, 2003 and
2002, the accumulated provision for property damage was $26.2 million and $15.5
million, respectively, and is included in miscellaneous regulatory liabilities
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 million 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 $10.6 million in 2003, $3.5 million in 2002, and $4.5 million in 2001 to
the accumulated provision for property damage.
2. RETIREMENT BENEFITS
The Company has a defined benefit, trusteed, pension plan covering substantially
all employees. The plan is funded in accordance with Employee Retirement Income
Security Act (ERISA) requirements. No contributions to the plan are expected for
the year ending December 31, 2004. The Company also provides certain
non-qualified benefit plans for a selected group of management and highly
compensated employees. Benefits under these non-qualified plans are funded on a
cash basis. The Company provides certain medical care and life insurance
benefits for retired employees. In addition, trusts are funded to the extent
required by the FPSC and the FERC. For the year ended December 31, 2004,
postretirement benefit contributions are expected to total approximately $80
thousand.
The measurement date for plan assets and obligations is September 30 of
each year. In 2002, the Company adopted plan changes that had the effect of
increasing benefits to both current and future retirees.
Pension Plans
The accumulated benefit obligation for the pension plans was $186 million in
2003 and $162 million in 2002. Changes during the year in the projected benefit
obligations, accumulated benefit obligations, and fair value of plan assets were
as follows:
Projected
Benefit Obligations
---------------------------
2003 2002
- ---------------------------------------------------------------
(in thousands)
Balance at beginning of year $184,987 $169,251
Service cost 5,225 4,910
Interest cost 11,733 12,394
Benefits paid (8,785) (8,395)
Actuarial (gain)/loss and
employee transfers, net 13,326 2,672
Other - 4,155
- ---------------------------------------------------------------
Balance at end of year $206,486 $184,987
===============================================================
II-185
NOTES (continued)
Gulf Power Company 2003 Annual Report
Plan Assets
2003 2002
- ---------------------------------------------------------------
(in thousands)
Balance at beginning of year $211,166 $233,706
Actual return on plan assets 33,672 (15,694)
Benefits paid (8,293) (7,934)
Employee transfers (199) 1,088
- ----------------------------------------------------------------
Balance at end of year $236,346 $211,166
===============================================================
Pension plan assets are managed and invested in accordance with all
applicable requirements, including ERISA and the Internal Revenue Service (IRS)
revenue code. The Company's investment policy covers a diversified mix of
assets, including equity and fixed income securities, real estate, and private
equity, as described in the table below. Derivative instruments are used
primarily as hedging tools but may also be used to gain efficient exposure to
the various asset classes. The Company primarily minimizes the risk of large
losses through diversification but also monitors and manages other aspects of
risk.
Plan Assets
---------------------------------
Target 2003 2002
- -----------------------------------------------------------------
Domestic equity 37% 37% 35%
International equity 20 20 18
Global fixed income 26 24 25
Real estate 10 11 12
Private equity 7 8 10
- -----------------------------------------------------------------
Total 100% 100% 100%
=================================================================
The accrued pension costs recognized in the Balance Sheets
were as follows:
Accrued Pension Costs
----------------------
2003 2002
- -------------------------------------------------------------
(in thousands)
Funded status $29,859 $26,179
Unrecognized transition
obligation (1,440) (2,161)
Unrecognized prior
service cost 13,471 14,874
Unrecognized net gain (4,155) (6,589)
4th quarter cash flow
adjustment 169 85
- -------------------------------------------------------------
Prepaid pension asset, net 37,904 32,388
Portion included in
benefit obligations 4,110 3,910
- -------------------------------------------------------------
Total Prepaid asset recognized
in the Balance Sheets $42,014 $36,298
=============================================================
In 2003 and 2002, amounts recognized in the Balance Sheets for accumulated
other comprehensive income and intangible assets to record the minimum pension
liability related to the non-qualified plans were $1.4 million and $0.7 million
and $1.2 million and $0.9 million, respectively.
Components of the pension plans' net periodic cost were as follows:
2003 2002 2001
- -------------------------------------------------------------------
(in thousands)
Service cost $ 5,225 $ 4,910 $ 4,703
Interest cost 11,733 12,394 11,644
Expected return on
plan assets (20,564) (20,431) (19,312)
Recognized net gain (1,819) (2,746) (3,072)
Net amortization 486 298 165
- -------------------------------------------------------------------
Net pension income $ (4,939) $ (5,575) $ (5,872)
===================================================================
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
---------------------------
2003 2002
- ---------------------------------------------------------------
(in thousands)
Balance at beginning of year $63,675 $54,337
Service cost 1,128 948
Interest cost 4,059 3,992
Benefits paid (2,332) (1,984)
Actuarial (gain)/loss 6,373 6,382
- ---------------------------------------------------------------
Balance at end of year $72,903 $63,675
===============================================================
Plan Assets
---------------------------
2003 2002
- ---------------------------------------------------------------
(in thousands)
Balance at beginning of year $10,893 $11,632
Actual return on plan assets 1,616 (793)
Employer contributions 2,465 2,038
Benefits paid (2,332) (1,984)
- ---------------------------------------------------------------
Balance at end of year $12,642 $10,893
===============================================================
II-186
Postretirement benefits plan assets are managed and invested in accordance
with all applicable requirements, including ERISA and the IRS revenue code. The
Company's investment policy covers a diversified mix of assets, including equity
and fixed income securities, real estate, and private equity, as described in
the table below. Derivative instruments are used primarily as hedging tools but
may also be used to gain efficient exposure to the various asset classes. The
Company primarily minimizes the risk of large losses through diversification but
also monitors and manages other aspects of risk.
Plan Assets
-------------------------------
Target 2003 2002
- ----------------------------------------------------------------
Domestic equity 35% 35% 32%
International equity 19 19 18
Global fixed income 31 29 30
Real estate 9 10 11
Private equity 6 7 9
- ----------------------------------------------------------------
Total 100% 100% 100%
================================================================
The accrued postretirement costs recognized in the Balance Sheets
were as follows:
2003 2002
- --------------------------------------------------------------
(in thousands)
Funded status $(60,261) $(52,782)
Unrecognized transition
obligation 3,301 3,656
Unrecognized prior
service cost 5,003 5,349
Unrecognized net loss 15,313 9,530
Fourth quarter contributions 195 581
- --------------------------------------------------------------
Accrued liability recognized
in the Balance Sheets $(36,449) $(33,666)
==============================================================
Components of the postretirement plan's net periodic cost
were as follows:
2003 2002 2001
- -----------------------------------------------------------------
Service cost $ 1,128 $ 948 $ 983
Interest cost 4,058 3,991 3,886
Expected return on
plan assets (1,139) (1,100) (1,037)
Transition obligation 356 356 356
Prior service cost 346 346 299
Recognized net (gain)/loss 113 (19) (18)
- -----------------------------------------------------------------
Net post-retirement cost $ 4,862 $ 4,522 $ 4,469
=================================================================
The weighted average rates assumed in the actuarial calculations used to
determine both the benefit obligations and the net period costs for the pension
and postretirement benefit plans were as folows:
2003 2002 2001
- ------------------------------------------------------------------
Discount 6.00% 6.50% 7.50%
Annual salary increase 3.75% 4.00% 5.00%
Long-term return on
plan assets 8.50% 8.50% 8.50%
- ------------------------------------------------------------------
The Company determined the long-term rate of return based on historical
asset class returns and current market conditions, taking into account the
diversification benefits of investing in multiple asset classes.
An additional assumption used in measuring the accumulated postretirement
benefit obligation was a weighted average medical care cost trend rate of 8.25
percent for 2003, 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,
2003 as follows:
1 Percent
---------------------------
Increase Decrease
- ---------------------------------------------------------------
(in thousands)
Benefit obligation $5,601 $4,949
Service and interest costs $ 364 $ 320
===============================================================
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 2003, 2002, and 2001, were $2.6
million, $2.5 million, and $2.3 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. In addition, the Company's business activities are
II-187
NOTES (continued)
Gulf Power Company 2003 Annual Report
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 against the Company cannot be predicted at this time;
however, management does not anticipate that the liabilities, if any, arising
from such current 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 the Florida Department of
Environmental Protection (FDEP) for the purpose of ensuring compliance with
ozone ambient air quality standards adopted by the Environmental Protection
Agency (EPA). During 2003, 2002, and 2001, the Company recorded ECRC revenues of
$10.7 million, $10.8 million, and $10.0 million, respectively.
At December 31, 2003, the Company's liability for the estimated costs of
environmental remediation projects for known sites was $12.9 million. These
estimated costs are expected to be expended from 2004 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 $11.6 million in deferred assets and deferred
liabilities representing the future recoverability of these costs.
New Source Review Actions
In November 1999, the EPA brought a civil action in the U.S. District Court for
the Northern District of Georgia against Alabama Power, Georgia Power, and SCS.
The complaint alleged violations of the New Source Review (NSR) provisions of
the Clean Air Act with respect to five coal-fired generating facilities in
Alabama and Georgia and violations of related state laws. The civil action
requested 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 retail operating companies notices of violation
relating to 10 generating facilities, which included the five facilities
mentioned previously and the Company's Plants Crist and Scherer. See Note 4 for
information on the Company's ownership interest in Plant Scherer Unit 3. In
early 2000, the EPA filed a motion to amend its complaint to add the violations
alleged in its notices of violation and to add the Company, Mississippi Power,
and Savannah Electric as defendants.
In August 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. In March 2001, the court granted the EPA's
motion to add Savannah Electric as a defendant, but it denied the motion to add
the Company and Mississippi Power based on lack of jurisdiction in Georgia 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. In
addition, the EPA refiled its claims against Alabama Power in the U.S. District
Court for the Northern District of Alabama. These complaints allege violations
with respect to eight coal-fired generating facilities in Alabama and Georgia,
and they request the same kinds of relief as was requested in the original
complaint, i.e. penalties and injunctive relief, including installation of the
best available control technology. The EPA has not refiled against the Company,
Mississippi Power, or SCS.
The actions against Alabama Power, Georgia Power, and Savannah Electric
were stayed in the spring of 2001 during the appeal of a very similar NSR
enforcement action against the Tennessee Valley Authority (TVA) before the U.S.
Court of Appeals for the Eleventh Circuit. The TVA appeal involves many of the
same legal issues raised by the actions against Alabama Power, Georgia Power,
and Savannah Electric. Because the final resolution of the TVA appeal could have
II-188
NOTES (continued)
Gulf Power Company 2003 Annual Report
a significant impact on Alabama Power and Georgia Power, both companies have
been involved in that appeal. On June 24, 2003, the Court of Appeals issued its
ruling in the TVA case. It found unconstitutional the statutory scheme set forth
in the Clean Air Act that allowed the EPA to impose penalties for failing to
comply with an administrative compliance order, like the one issued to TVA,
without the EPA having to prove the underlying violation. Thus, the Court of
Appeals held that the compliance order was of no legal consequence, and TVA was
free to ignore it. The court did not however, rule directly on the substantive
legal issues about the proper interpretation and application of certain NSR
provisions that had been raised in the TVA appeal. On September 16, 2003, the
Court of Appeals denied the EPA's request for a rehearing of the decision and on
February 13, 2004, the EPA petitioned the U.S. Supreme Court to review the
Eleventh Circuit's decision. The actions against Alabama Power, Georgia Power,
and Savannah Electric could remain stayed pending this appeal. The EPA also
filed a motion to lift the stay in the action against Alabama Power. At this
time, no party to the Georgia Power and Savannah Electric action, which was
administratively closed two years ago, has asked the court to reopen that case.
Since the inception of the NSR proceedings against Georgia Power, Alabama
Power, and Savannah Electric, the EPA has also been proceeding with similar NSR
enforcement actions against other utilities, involving many of the same legal
issues. In each case, the EPA alleged that the utilities failed to comply with
the NSR permitting requirements when performing maintenance and construction
activities at coal-burning plants, which activities the utilities considered to
be routine or otherwise not subject to NSR. In 2003, district courts addressing
these cases issued opinions that reached conflicting conclusions.
In October 2003, the EPA issued final revisions to its NSR regulations
under the Clean Air Act clarifying the scope of the existing Routine
Maintenance, Repair, and Replacement exclusion. On December 24, 2003, the U.S.
Court of Appeals for the District of Columbia Circuit stayed the effectiveness
of these revisions pending resolution of related litigation. In January 2004,
the Bush Administration announced that it would continue to enforce the existing
rules.
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 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 the Company's 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. This
matter is on appeal to Florida's First District Court of Appeal. If this verdict
is upheld, there is insurance coverage available to offset a substantial portion
of this amount. 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
Southern Company and certain of its subsidiaries, including the Company, Georgia
Power, Mississippi Power, and Southern Telecom (collectively, defendants), have
been named as defendants in numerous lawsuits brought by landowners since 2001
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. With respect to one such lawsuit
brought by landowners regarding the installation and use of fiber optic cable
over Company rights of way located on the landowners' property, on November 7,
2003, the Second Circuit Court in Gadsden County, Florida, ruled in favor of the
plaintiffs on their motion for partial summary judgment concerning liability.
II-189
NOTES (continued)
Gulf Power Company 2003 Annual Report
The question of damages, if any, will be decided at a future trial. In the event
of an adverse verdict on damages, the Company could appeal the verdicts on both
liability and damages. The Company believes that it has complied with applicable
laws and 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.
In addition, in late 2001, certain subsidiaries of Southern Company,
including the Company, Alabama Power, Georgia Power, Mississippi Power, Savannah
Electric, and Southern Telecom (collectively, defendants), were named as
defendants in a lawsuit brought by a telecommunications company that uses
certain of the defendants' rights of way. This lawsuit alleges, among other
things, that the defendants are contractually obligated to indemnify, defend,
and hold harmless the telecommunications company from any liability that may be
assessed against the telecommunications company in pending and future right of
way litigation. The Company believes that the plaintiff's claims are without
merit. An adverse outcome in this matter, combined with an adverse outcome
against the telecommunications company in one or more of the right of way
lawsuits, could result in substantial judgments; however, the final outcome of
these matters cannot now be determined.
Retail Rate Matters
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. The Company recorded revenues subject to refund (with
interest) of $1.5 million in 2001. No refund was required in 2002. The sharing
plan expired on April 21, 2002.
In May 2002, the FPSC approved a retail base rate increase of $53.2 million
effective June 7, 2002 primarily related to the commercial operation of Plant
Smith Unit 3.
FERC Matters
The Company has obtained FERC approval to sell power to nonaffiliates at
market-based prices under specific contracts. Through SCS, as agent, the Company
also has FERC authority to make short-term opportunity sales at market rates.
Specific FERC approval must be obtained with respect to a market-based contract
with an affiliate. In November 2001, the FERC modified the test it uses to
consider utilities' applications to charge market-based rates and adopted a new
test called the Supply Margin Assessment (SMA). The FERC applied the SMA to
several utilities, including Southern Company's retail operating companies, and
found them to be "pivotal suppliers" in their service areas and ordered the
implementation of several mitigation measures. SCS, on behalf of the Company and
the other retail operating companies, sought rehearing of the FERC order, and
the FERC delayed the implementation of certain mitigation measures. SCS, on
behalf of the Company and the other retail operating companies, submitted
comments to the FERC in 2002 regarding these issues. In December 2003, the FERC
issued a staff paper discussing alternatives and held a technical conference in
January 2004. The Company anticipates that the FERC will address the requests
for rehearing in the near future. Regardless of the outcome of the SMA proposal,
the FERC retains the ability to modify or withdraw the authorization for any
seller to sell at market-based rates, if it determines that the underlying
conditions for having such authority are no longer applicable. The final outcome
of this matter will depend on the form in which the SMA test and mitigation
measures rules may be ultimately adopted and cannot be determined at this time.
4. 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 MW. 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.
II-190
NOTES (continued)
Gulf Power Company 2003 Annual Report
At December 31, 2003, 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 $189,502(1) $234,914
Accumulated Depreciation $ 80,631 $122,904
Construction Work in Progress $ 91 $ 815
Ownership 25% 50%
- ------------------------------------------------------------------
(1) Includes net plant acquisition adjustment.
5. INCOME TAXES
The Company and the other subsidiaries of Southern Company file a consolidated
federal income tax return. In 2002, Southern Company began filing a combined
State of Georgia 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 IRS regulations, each company is jointly
and severally liable for the tax liability.
At December 31, 2003, the tax-related regulatory assets to be recovered
from customers were $18.3 million. These assets are attributable to tax benefits
flowed through to customers in prior years and to taxes applicable to
capitalized allowance for funds used during construction. At December 31, 2003,
the tax-related regulatory liabilities to be credited to customers were $26.5
million. These liabilities are attributable to deferred taxes previously
recognized at rates higher than current enacted tax law and to unamortized
investment tax credits.
Details of income tax provisions are as follows:
2003 2002 2001
-----------------------------------------
(in thousands)
Total provision for income taxes:
Federal--
Current $33,085 $24,474 $24,207
Deferred 2,488 7,936 2,568
- --------------------------------------------------------------------
35,573 32,410 26,775
- --------------------------------------------------------------------
State--
Current 4,585 3,051 3,701
Deferred 719 1,683 826
- --------------------------------------------------------------------
5,304 4,734 4,527
- --------------------------------------------------------------------
Total $40,877 $37,144 $31,302
====================================================================
Net cash payments for income taxes related to continuing operations in
2003, 2002, and 2001 were $23.8 million, $34.0 million, and $36.8 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:
2003 2002
-------------------------
(in thousands)
Deferred tax liabilities:
Accelerated depreciation $200,129 $188,879
Other 27,669 28,377
- ------------------------------------------------------------------
Total 227,798 217,256
- ------------------------------------------------------------------
Deferred tax assets:
Federal effect of state
deferred taxes 9,568 9,421
Postretirement benefits 11,793 10,826
Other 24,347 18,396
- ------------------------------------------------------------------
Total 45,708 38,643
- ------------------------------------------------------------------
Net deferred tax liabilities 182,090 178,613
Less prepaid expense
(accrued income taxes), net (6,405) (10,924)
- ------------------------------------------------------------------
Accumulated deferred income taxes in
the Balance Sheets $175,685 $167,689
==================================================================
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 2003, $1.8 million in 2002, and $1.7
II-191
NOTES (continued)
Gulf Power Company 2003 Annual Report
million in 2001. At December 31, 2003, 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:
2003 2002 2001
----------------------------
Federal statutory rate 35% 35% 35%
State income tax,
net of federal deduction 3 3 4
Non-deductible book
depreciation 1 1 1
Difference in prior years'
deferred and current tax rate (1) (2) (2)
Other, net (1) (1) (3)
- ----------------------------------------------------------------
Effective income tax rate 37% 36% 35%
================================================================
6. FINANCING
Mandatorily Redeemable Preferred Securities
The Company has formed certain wholly owned trust subsidiaries for the purpose
of issuing preferred securities. The proceeds of the related equity investments
and preferred security sales were loaned back to the Company through the
issuance of junior subordinated notes totaling $72.2 million, which constitute
substantially all of the assets of these trusts. The Company considers that the
mechanisms and obligations relating to the preferred securities issued for its
benefit, taken together, constitute a full and unconditional guarantee by it of
the respective trusts' payment obligations with respect to these securities. At
December 31, 2003, preferred securities of $70 million were outstanding and
recognized as liabilities in the Balance Sheets.
Long-Term Debt Due Within One Year
At December 31, 2003, 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 mortgage
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 2003 and 2002. It is anticipated that the 2004
requirement will be satisfied by certifying property additions. Sinking fund
requirements and/or maturities through 2008 applicable to long-term debt are as
follows: $50.6 million in 2004; $0.6 million in 2005; $37.6 million in 2006;
$0.3 million in 2007; and $0.3 million in 2008.
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, 2003, retained earnings of $127 million were
restricted against the payment of cash dividends on common stock under the terms
of the mortgage indenture.
In accordance with the PUHCA, the Company is also restricted from paying
common dividends to the Southern Company from paid-in capital without SEC
approval.
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.
There are no agreements or other arrangements among the affiliated
companies under which the assets of one company have been pledged or otherwise
made available to satify obligations of Southern Company or any of its
subsidiaries.
Bank Credit Arrangements
At the beginning of 2004, the Company had $56 million of lines of credit with
banks subject to renewal each year, all of which remained unused. The $56
million in committed lines of credit provide liquidity support for the Company's
commercial paper program and for $4 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.
II-192
NOTES (continued)
Gulf Power Company 2003 Annual Report
Certain credit arrangements contain covenants that limit the level of
indebtedness to capitalization to 65 percent, as defined in the agreements. 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, 2003 was $37.7 million. During 2003, the peak amount outstanding
for commercial paper was $39.1 million and the average amount outstanding was
$12.8 million. The average annual interest rate on commercial paper was 1.2%.
In addition, the Company has bid-loan facilities with five major money
center banks that total $50 million, with none committed at December 31, 2003.
Financial Instruments
The Company enters into energy-related derivatives to hedge exposures to
electricity, gas, and other fuel price changes. However, due to cost-based rate
regulations, the Company has limited exposure to market volatility in commodity
fuel prices and prices of electricity. The Company has implemented fuel-hedging
programs with the approval of the FPSC. The Company enters into hedges of
forward electricity sales.
At December 31, 2003, the fair value of derivative energy contracts was
reflected in the financial statements as follows:
Amounts
- --------------------------------------------------------------
(in thousands)
Regulatory liabilities, net $2,501
Other comprehensive income -
Net income 2
- --------------------------------------------------------------
Total fair value $2,503
==============================================================
The fair value gains or losses for cash flow hedges that are recoverable
through the regulatory fuel clauses are recorded as regulatory assets and
liabilities and are recognized in earnings at the same time the hedged items
affect earnings.
The Company also enters into derivatives to hedge exposure to interest rate
changes. Derivatives related to fixed rate securities are accounted for as fair
value hedges. The derivatives are generally structured to match the critical
terms of the hedged debt instruments; therefore, no material ineffectiveness has
been recorded in earnings.
During 2003, the Company settled interest derivatives at the same time it
issued debt and recognized losses totaling $3.3 million. These losses have been
deferred in other comprehensive income and will be reclassified to interest
expense over the life of the related debt. The fair value gain or loss for cash
flow hedges is recorded in other comprehensive income and is reclassified into
earnings at the same time the hedged items affect earnings. For the year 2003,
approximately $0.2 million of pre-tax losses were reclassified from other
comprehensive income to interest expense. For the year 2004, pre-tax losses of
approximately $0.3 million are expected to be reclassified from other
comprehensive income to interest expense.
7. COMMITMENTS
Construction Program
The Company is engaged in a continuous construction program, the cost of which
is currently estimated to total $166 million in 2004, $149 million in 2005, and
$108 million in 2006. 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;
changes in FERC rules and transmission regulations; increasing costs of labor,
equipment, and materials; and cost of capital. At December 31, 2003, significant
purchase commitments were outstanding in connection with the construction
program.
Included in the amounts above, the Company has budgeted $64 million, $31
million, and $4 million in 2004, 2005, and 2006, respectively, for capital
II-193
NOTES (continued)
Gulf Power Company 2003 Annual Report
expenditures related to environmental controls at Plant Crist as part of an
agreement with the FDEP to reduce nitrogen oxide emissions. The FPSC authorized
the Company to recover the costs related to these environmental projects through
the ECRC. Construction of new transmission and distribution facilities and
capital improvements, including those needed to meet environmental standards for
the Company's existing generation, transmission and distribution facilities are
ongoing.
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 $84.2 million over approximately 11
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 prepayments. These amounts are included in prepaid expenses and
other assets in the 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, the
Company has entered into various long-term commitments for the procurement of
fossil fuel. In most cases, these contracts contain provisions for price
escalations, minimum purchase levels, and other financial commitments. Natural
gas purchase commitments contain given volumes with prices based on various
indices at the time of delivery. Amounts included in the chart below represent
estimates based on New York Mercantile future prices at December 31, 2003. Also,
the Company has a long-term commitment for the purchase of electricity. Total
estimated minimum long-term obligations at December 31, 2003 were as follows:
Natural Purchased
Year Gas Fuel Power
- ----------------------------------------------------------------
(in millions)
2004 $104 $132 $1
2005 65 77 -
2006 59 78 -
2007 45 78 -
2008 19 18 -
2009 and thereafter 259 - -
- ----------------------------------------------------------------
Total commitments $551 $383 $1
================================================================
Additional commitments for fuel will be required to supply the Company's
future needs.
SCS may enter into various types of wholesale energy and natural gas
contracts acting as an agent for the Company, the other retail operating
companies, Southern Power, and Southern Company GAS. Under these agreements,
each of the retail operating companies, Southern Power, and Southern Company GAS
may be jointly and severally liable. The creditworthiness of Southern Power and
Southern Company GAS is currently inferior to the creditworthiness of the retail
operating companies. Accordingly, Southern Company has entered into keep-well
agreements with the Company and each of the other retail 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 Company GAS as a contracting party under these agreements.
Operating Leases
The Company has operating lease agreements with various terms and expiration
dates. Total operating lease expenses were $2.2 million, $2.1 million, and $1.9
million for 2003, 2002, and 2001, respectively.
At December 31, 2003, estimated minimum rental commitments for
noncancelable operating leases were as follows:
II-194
NOTES (continued)
Gulf Power Company 2003 Annual Report
Year Amounts
----- ------------------
(in thousands)
2004 $ 1,995
2005 2,100
2006 2,042
2007 2,038
2008 2,037
2009 and thereafter 8,153
------------------------------------------------------------
Total commitments $18,365
============================================================
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 were entered into for twenty-two years. Both of these leases are for
the transportation of coal to Plant Daniel. 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 each lease term.
The Company, as a joint owner of Plant Daniel Units 1 and 2, 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 2003, $1.9 million in 2002, and $1.9 million in 2001. The annual
amounts for 2004 through 2008 are expected to be $1.9 million, $2.0 million,
$2.0 million, $2.0 million, and $2.0 million, respectively, and after 2008 are
expected to total $8.2 million.
8. QUARTERLY FINANCIAL INFORMATION
(UNAUDITED)
Summarized quarterly financial data for 2003 and 2002 are as follows:
Net Income
Operating Operating After Dividends
Quarter Ended Revenues Income on Preferred Stock
- ----------------------------------------------------------------------
(in thousands)
March 2003 $197,838 $32,797 $13,972
June 2003 215,209 40,668 18,785
September 2003 252,889 61,545 32,798
December 2003 211,761 16,890 3,455
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
- ----------------------------------------------------------------------
The Company's business is influenced by seasonal weather conditions and the
timing of rate changes, among other factors.
II-195
SELECTED FINANCIAL AND OPERATING DATA 1999-2003
Gulf Power Company 2003 Annual Report
- ---------------------------------------------------------------------------------------------------------------------------------
2003 2002 2001 2000 1999
- ---------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands) $877,697 $820,467 $725,203 $714,319 $674,099
Net Income after Dividends
on Preferred Stock (in thousands) $69,010 $67,036 $58,307 $51,843 $53,667
Cash Dividends
on Common Stock (in thousands) $70,200 $65,500 $53,275 $59,000 $61,300
Return on Average Common Equity (percent) 12.42 12.72 12.51 12.20 12.63
Total Assets (in thousands) $1,839,053 $1,816,889 $1,713,436 $1,448,977 $1,433,756
Gross Property Additions (in thousands) $99,284 $106,624 $274,668 $95,807 $69,798
- ---------------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $561,358 $549,505 $504,894 $427,378 $422,313
Preferred stock 4,236 4,236 4,236 4,236 4,236
Mandatorily redeemable preferred securities 70,000 115,000 115,000 85,000 85,000
Long-term debt 515,827 452,040 467,784 365,993 367,449
- ---------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $1,151,421 $1,120,781 $1,091,914 $882,607 $878,998
=================================================================================================================================
Capitalization Ratios (percent):
Common stock equity 48.8 49.0 46.2 48.4 48.0
Preferred stock 0.4 0.4 0.4 0.5 0.5
Mandatorily redeemable preferred securities 6.1 10.3 10.5 9.6 9.7
Long-term debt 44.7 40.3 42.9 41.5 41.8
- ---------------------------------------------------------------------------------------------------------------------------------
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+ AA-
Fitch A+ A+ A+ AA- AA-
Preferred Stock -
Moody's Baa1 Baa1 Baa1 a2 a2
Standard and Poor's BBB+ BBB+ BBB+ BBB+ 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 341,935 333,757 327,128 321,731 315,240
Commercial 51,169 49,411 48,654 47,666 47,728
Industrial 285 281 270 280 267
Other 473 474 468 442 316
- ---------------------------------------------------------------------------------------------------------------------------------
Total 393,862 383,923 376,520 370,119 363,551
=================================================================================================================================
Employees (year-end): 1,337 1,339 1,309 1,327 1,339
- ---------------------------------------------------------------------------------------------------------------------------------
II-196
SELECTED FINANCIAL AND OPERATING DATA 1999-2003 (continued)
Gulf Power Company 2003 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------------
2003 2002 2001 2000 1999
- ----------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $381,464 $365,693 $313,165 $302,210 $279,238
Commercial 218,928 207,960 188,759 177,047 167,305
Industrial 95,702 89,385 81,719 74,095 68,222
Other 3,080 2,798 948 (4,712) 2,184
- ----------------------------------------------------------------------------------------------------------------------------------
Total retail 699,174 665,836 584,591 548,640 516,949
Sales for resale - non-affiliates 76,767 77,171 82,252 66,890 62,354
Sales for resale - affiliates 63,268 40,391 27,256 66,995 66,110
- ----------------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 839,209 783,398 694,099 682,525 645,413
Other revenues 38,488 37,069 31,104 31,794 28,686
- ----------------------------------------------------------------------------------------------------------------------------------
Total $877,697 $820,467 $725,203 $714,319 $674,099
==================================================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 5,101,099 5,143,802 4,716,404 4,790,038 4,471,118
Commercial 3,614,255 3,552,931 3,417,427 3,379,449 3,222,532
Industrial 2,146,956 2,053,668 2,018,206 1,924,749 1,846,237
Other 22,479 21,496 21,208 18,730 19,296
- ----------------------------------------------------------------------------------------------------------------------------------
Total retail 10,884,789 10,771,897 10,173,245 10,112,966 9,559,183
Sales for resale - non-affiliates 2,504,211 2,156,741 2,093,203 1,705,486 1,561,972
Sales for resale - affiliates 2,438,874 1,720,240 962,892 1,916,526 2,511,983
- ----------------------------------------------------------------------------------------------------------------------------------
Total 15,827,874 14,648,878 13,229,340 13,734,978 13,633,138
==================================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 7.48 7.11 6.64 6.31 6.25
Commercial 6.06 5.85 5.52 5.24 5.19
Industrial 4.46 4.35 4.05 3.85 3.70
Total retail 6.42 6.18 5.75 5.43 5.41
Sales for resale 2.83 3.03 3.58 3.70 3.15
Total sales 5.30 5.35 5.25 4.97 4.73
Residential Average Annual
Kilowatt-Hour Use Per Customer 15,064 15,510 14,497 14,992 14,318
Residential Average Annual
Revenue Per Customer $1,126.49 $1,100.35 $962.57 $945.87 $894.18
Plant Nameplate Capacity
Ratings (year-end) (megawatts) 2,786 2,809 2,188 2,188 2,188
Maximum Peak-Hour Demand (megawatts):
Winter 2,494 2,182 2,106 2,154 2,085
Summer 2,269 2,454 2,223 2,285 2,161
Annual Load Factor (percent) 54.6 55.3 57.5 55.4 55.2
Plant Availability Fossil-Steam (percent): 90.7 90.6 90.1 85.2 87.2
- ----------------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 78.7 69.8 81.2 87.8 89.8
Gas 11.9 15.5 1.0 1.6 2.5
Purchased power -
From non-affiliates 3.2 4.6 6.5 7.6 5.9
From affiliates 6.2 10.1 11.3 3.0 1.8
- ----------------------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0 100.0 100.0
==================================================================================================================================
II-197
MISSISSIPPI POWER COMPANY
FINANCIAL SECTION
II-198
MANAGEMENT'S REPORT
Mississippi Power Company 2003 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 internal accounting controls are 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
four 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/Anthony J. Topazi
Anthony J. Topazi
President and Chief Executive Officer
/s/Michael W. Southern
Michael W. Southern
Vice President, Treasurer and,
Chief Financial Officer
March 1, 2004
II-199
INDEPENDENT AUDITORS' REPORT
Mississippi Power Company:
We have audited the accompanying balance sheets and statements of capitalization
of Mississippi Power Company (a wholly owned subsidiary of Southern Company) as
of December 31, 2003 and 2002, and the related statements of income,
comprehensive income, common stockholder's equity, and cash flows for the years
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 audits. The financial statements of
Mississippi Power Company for the year ended December 31, 2001 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 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, the financial statements (pages II-218 to II-239) present
fairly, in all material respects, the financial position of Mississippi Power
Company at December 31, 2003 and 2002, and the results of its operations and its
cash flows for the years then ended in conformity with accounting principles
generally accepted in the United States of America.
As discussed in Note 1 to the financial statements, in 2003 Mississippi
Power Company changed its method of accounting for asset retirement obligations.
/s/Deloitte & Touche LLP
Atlanta, Georgia
March 1, 2004
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-200
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Mississippi Power Company 2003 Annual Report
OVERVIEW OF EARNINGS AND BUSINESS
- ---------------------------------
ACTIVITIES
- ----------
Earnings
Mississippi Power Company's net income after dividends on preferred stock of
$73.5 million in 2003 remained relatively flat from $73.0 million in 2002.
However, operating revenues and expenses recorded by the Company in 2003 were
unusually high as compared to 2002. An increase of $62 million in other electric
revenues resulted from the termination of a contract with a subsidiary of
Dynegy, Inc. (Dynegy), the income effect of which was offset by the recording of
a $60 million expense related to the establishment of a regulatory liability in
connection with an interim accounting order issued by the Mississippi Public
Service Commission (MPSC) related to the Plant Daniel capacity expense. See Note
3 to the financial statements under "Contract Termination" and "Retail
Regulatory Filing" for additional information. Excluding these two items,
operating revenues and operating expense were lower in 2003 than in 2002
primarily due to decreased fuel revenues and lower fuel and purchased power
costs. Also, milder weather in 2003 caused kilowatt-hour sales to be slightly
lower than in 2002. The 2002 increase of $9.1 million in net income as compared
to the prior year 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 of $8.9 million for 2001 was due primarily to the
commercial operation of Plant Daniel Units 3 and 4 and lower interest costs.
Business Activities
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.
Several factors affect the opportunities, challenges, and risk of selling
electricity. These factors include the Company's ability to maintain a stable
regulatory environment, to achieve energy sales growth while containing costs,
and to recover costs related to growing demand and increasingly stricter
environmental standards. 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, new energy contracts with neighboring
utilities, energy conservation practiced by customers, the price of electricity,
the price elasticity of demand, and the rate of economic growth in the service
area.
RESULTS OF OPERATIONS
- ---------------------
A condensed income statement is as follows:
Increase (Decrease)
Amount From Prior Year
------------------------------------------
2003 2003 2002 2001
- -------------------------------------------------------------------
(in thousands)
Operating revenues $869,924 $ 45,759 $ 28,100 $108,463
- -------------------------------------------------------------------
Fuel 229,251 (53,142) 4,447 86,819
Purchased power 93,197 41,864 (43,911) (11,895)
Other operation
and maintenance 300,118 68,105 41,015 23,193
Depreciation
and amortization 55,700 (1,938) 3,561 3,802
Taxes other than
income taxes 53,991 (1,527) 10,552 (3,720)
- -------------------------------------------------------------------
Total operating
expenses 732,257 53,362 15,664 98,199
- ------------------------------------------------------------------
Operating income 137,667 (7,603) 12,436 10,264
Other income
(expense), net (18,853) 7,525 2,036 4,828
Less --
Income taxes 45,315 (564) 5,346 6,177
- -------------------------------------------------------------------
Net Income $ 73,499 $ 486 $ 9,126 $ 8,915
===================================================================
II-201
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2003 Annual Report
Revenues
Details of the Company's operating revenues in 2003 and the prior
two years are as follows:
Amount
- --------------------------------------------------------------
2003 2002 2001
(in thousands)
Retail -- prior year $536,827 $489,153 $498,551
Change in --
Base rates - 38,143 -
Sales growth 1,175 566 (1,048)
Weather (1,542) 3,533 (1,953)
Fuel cost recovery (20,159) 5,432 (6,397)
and other
- --------------------------------------------------------------
Retail -- current year 516,301 536,827 489,153
- --------------------------------------------------------------
Sales for resale --
Non-affiliates 249,986 224,275 204,623
Affiliates 26,723 46,314 85,652
- --------------------------------------------------------------
Total sales for resale 276,709 270,589 290,275
- --------------------------------------------------------------
Contract termination 62,111 - -
Other electric
operating revenues 14,803 16,749 16,637
- --------------------------------------------------------------
Total electric
operating revenues $869,924 $824,165 $796,065
=============================================================
Percent change 5.6% 3.5% 15.8%
- -------------------------------------------------------------
Total retail revenues for 2003 decreased approximately 3.8 percent when
compared to 2002 as a result of decreased fuel revenues and to the lesser extent
decreases in kilowatt-hour energy sales due to milder than normal weather in the
Company's service area and the sluggish economy. 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.
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. During 2003, the fuel cost recovery and other revenues decreased $20
million compared to 2002 due to a reduction in rates that became effective in
2003.
Sales for resale to non-affiliates are influenced by the non-affiliate
utilities' own customer demand, plant availability, and cost of predominant
fuels. Included in sales for resale to non-affiliates are revenues from rural
electric cooperative associations and municipalities located in southeastern
Mississippi. Sales to these utilities remained relatively flat in 2003 compared
to 2002, increased 8.0 percent in 2002, and decreased 3.7 percent in 2001, with
the related revenues increasing 1.6 percent, increasing 19.8 percent, and
decreasing 2.4 percent, respectively. The customer demand experienced by these
utilities is determined by factors very similar to those of the Company. Total
revenues from sales for resale to non-affiliates increased in 2003 as a result
of increases in average sales price per kilowatt-hour and increased
kilowatt-hour sales to wholesale non-affiliate customers. Revenues from sales
for resale to non-affiliates increased in 2002 and 2001, primarily as the result
of a new power sales contract that began in June 2001, as well as colder winter
months during 2002.
In May 2003, the Company entered into an agreement with Dynegy that
resolved and terminated in 2003 all outstanding matters related to capacity
sales contracts with subsidiaries of Dynegy. The termination payment from Dynegy
resulted in an increase in other electric revenues of $62 million for the year
2003. See Note 3 to the financial statements under "Contract Termination" for
additional information.
Energy Sales
Energy sales to affiliated companies within the Southern Company electric system
vary from year to year depending on demand and the availability and cost of
generating resources at each company. These sales do not have a significant
impact on earnings since the energy is generally sold at marginal cost.
II-202
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2003 Annual Report
Kilowatt-hour (KWH) sales for 2003 and percent change by year were as
follows:
Percent Change
KWH -----------------------------
2003 2003 2002 2001
--------------------------------------------------------------
(in millions)
Residential 2,256 (1.9)% 6.3% (5.4)%
Commercial 2,914 0.4 2.1 (1.5)
Industrial 4,111 (1.2) (2.7) (2.3)
Other 40 - - (0.3)
-----------
Total retail 9,321 (0.9) 0.1 (2.8)
Sales for Resale
Non-Affiliated 5,875 9.2 7.4 36.4
Affiliated 709 (55.3) (46.3) 552.3
-----------
Total 15,905 (2.8) (5.3) 26.0
==============================================================
Total retail kilowatt-hour sales decreased in 2003 as the result of milder
weather in 2003 when compared to 2002. Total retail kilowatt-hour sales
increased slightly in 2002 due to colder than average winter weather, which
primarily affected residential sales. In addition, commercial sales increased
2.1 percent in 2001 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 in the Company's service
area. 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.
The Company anticipates relatively slow growth over the next five years due
to a slow recovery from the national and area economic downturn and a maturing
of the gaming and tourism industry. Retail sales are expected to grow at an
annual average rate of approximately 1% through 2008, with increases expected in
the local, state, and federal government sectors, as well as increases in
shipbuilding, education, and health care.
Expenses
Total operating expenses were $732 million in 2003, which reflects an increase
of 7.9 percent over 2002. The increase in 2003 is due primarily to $60 million
in Plant Daniel capacity expense recorded in connection with an interim
accounting order from the MPSC. See Note 3 to the financial statements under
"Retail Regulatory Filing" for further information. In 2002, total operating
expenses were $679 million, reflecting an increase of 2.4 percent over the prior
year. The increase was due primarily to increases 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, as well as a slight increase in fuel
expense. 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 7 to the financial
statements under "Operating Leases -- Plant Daniel Combined Cycle Generating
Units" for additional information.
Fuel costs are the single largest expense for the Company. The mix of fuel
sources for generation of electricity is determined primarily by demand, the
unit cost of fuel consumed, and the availability of fossil generating units. The
amount and sources of generation and the average cost of fuel per net
kilowatt-hour generated and the average cost of purchased power were as follows:
2003 2002 2001
- ---------------------------------------------------------------
Total generation
(millions of kilowatt hours) 12,850 15,079 15,770
Sources of generation
(percent) --
Coal 74 57 59
Gas 26 43 41
Average cost of fuel per net
kilowatt-hour generated
(cents) -- 1.95 2.03 1.89
Average cost of purchased
power per kilowatt-hour
(cents) -- 2.55 2.61 4.27
- ---------------------------------------------------------------
Fuel expense for 2003 decreased 18.8 percent due to decreased generation
and lower average cost of fuel. Fuel expense for 2002 and 2001 increased 1.6
percent and 45.4 percent, respectively. The increase for 2002 was due to a fuel
hedging loss, which is approved for recovery through the Energy Cost Management
Plan (ECM), authorized by the MPSC. The 2001 increase was due to increased
II-203
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2003 Annual Report
generation in conjunction with the initial operation of Plant Daniel Units 3 and
4 and a higher average cost of fuel.
In 2003, purchased power expense increased $41.9 million or 81.6 percent.
The increase is primarily due to an increase in purchased power expense from
affiliate companies. Those purchases were more economical than self generation
due to the increase in the cost of natural gas in 2003. Energy purchases vary
from year to year depending on demand and the availability and cost of
generating resources at the Company. These expenses do not have a significant
impact on earnings since the energy purchases are generally offset by energy
revenues through the Company's retail and wholesale fuel cost recovery clauses.
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 expense 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.
Other operation expense increased $71.7 million or 45.3 percent in 2003,
primarily due to approximately $11 million incurred to restructure the lease
agreement for the combined cycle generating units at Plant Daniel and $60
million in expense recorded in connection with the recognition of a regulatory
liability following an interim accounting order from the MPSC related to Plant
Daniel capacity expense. See Notes 3 and 7 to the financial statements under
"Retail Regulatory Filing" for further information regarding the Plant Daniel
capacity. Also, see "Financial Condition and Liquidity -- Off-Balance Sheet
Financing Arrangements" herein and Note 7 to the financial statements under
"Operating Leases -- Plant Daniel Combined Cycle Generating Units" for further
information regarding the Plant Daniel lease. In 2002, other operation expense
increased 17.4 percent 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.
Maintenance expense decreased 4.9 percent in 2003 primarily due to a
decrease in the long term service agreement expense of $5 million. The decrease
was attributable to the decrease in fired operating hours at Plant Daniel Units
3 and 4 of approximately 50 percent. In 2002, maintenance expense 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.
In 2003, depreciation and amortization expense decreased $1.9 million
compared to 2002 primarily due to a reduction in the amortization of
environmental expenses based on the Company's Environmental Compliance Overview
Plan (ECO Plan) filing with the MPSC. In 2002 and 2001, depreciation and
amortization expense increased 6.6 percent and 7.6 percent, 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.
Taxes other than income taxes decreased 2.8 percent in 2003 primarily due
to lower property taxes in 2003. Taxes other than income taxes increased 23.5
percent in 2002 due to additional property taxes related to 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. The decrease in total
other income and expense is due to interest on long-term debt decreasing in
2003, 2002, and 2001 as a result of lower interest rates on debt outstanding and
lower principal amount of debt outstanding.
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
II-204
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2003 Annual Report
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 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. These factors affect the opportunities,
challenges, and risk of the Company's business of selling electricity. These
factors include the Company's ability to maintain a stable regulatory
environment, to achieve energy sales growth while containing costs, and to
recover costs related to growing demand and increasingly stricter environmental
standards. 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 energy contracts with
neighboring utilities, energy conservation practiced by customers, the price of
electricity, the price elasticity of demand, and the rate of economic growth in
the service area.
Industry Restructuring
The Company operates as a vertically integrated utility providing electricity to
retail customers within its traditional service area located in southeastern
Mississippi and wholesale customers in the Southeast. 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.
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
allowed independent power producers to access a utility's transmission network
and sell electricity to other utilities.
Although the Energy Act does not provide for retail customer access, it was
a major catalyst for the 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 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
Mississippi, none have been enacted.
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 the 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, as well as the August
2003 power outage in the Northeast.
Since 2001, merchant energy companies and traditional electric utilities
with significant energy marketing and trading activities have come 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 adverse financial impact regarding its limited energy trading
operations through Southern Company Services (SCS).
II-205
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2003 Annual Report
Continuing to be a low-cost producer could provide significant
opportunities to increase the size and profitability in markets that evolve with
changing regulation and competition. Conversely, future regulatory changes could
adversely affect the Company's growth, and if the Company does not remain a
low-cost producer and provide quality service, then the Company's energy sales
growth could be limited, and this could significantly erode earnings.
Environmental Matters
New Source Review Actions
In November 1999, the Environmental Protection Agency (EPA) brought a civil
action against Alabama Power, Georgia Power, and SCS. The complaint alleged
violations of the New Source Review (NSR) provisions of the Clean Air Act with
respect to five coal-fired generating facilities in Alabama and Georgia. The
civil action requested 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 retail operating companies
notices of violation relating to 10 generating facilities, which include 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 notices of violation and to add Gulf Power, the
Company, and Savannah Electric as defendants. However, in March 2001, the court
denied the motion with respect to the Company and Gulf Power based on lack of
jurisdiction and the EPA has not refiled. See Note 3 to the financial statements
under "New Source Review Actions" for additional information.
In December 2002 and October 2003, the EPA issued final revisions to its
NSR regulations under the Clean Air Act. The December 2002 revisions included
changes to the regulatory exclusions and the methods of calculating emissions
increases. The October 2003 regulations clarified the scope of the existing
Routine Maintenance, Repair, and Replacement exclusion. A coalition of states
and environmental organizations filed petitions for review of these revisions
with the U.S. Court of Appeals for the District of Columbia Circuit. On December
24, 2003, the court of appeals granted a stay of the October 2003 revisions
pending its review of the rules and ordered that its review be conducted on an
expedited basis. In January 2004, the Bush Administration announced that it
would continue to enforce the existing rules until the courts resolve legal
challenges to the EPA's revised NSR regulations. In any event, the final
regulations must be adopted by the State of Mississippi in order to apply to the
Company's facilities. The effect of these final regulations and the related
legal challenges cannot be determined 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. 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 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
- -- both capital and operating -- a major portion of which is expected to be
recovered through existing ratemaking provisions, including the Company's ECO
Plan. The 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 two 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
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2003 Annual Report
Plan" for additional information. Environmental costs that are known and
estimable at this time are included in capital expenditures discussed under
"Capital Requirements and Contractual Obligations."
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. Title IV compliance
was effective in 2000 and associated construction expenditures totaled
approximately $65 million.
In September 1998, the EPA issued regional nitrogen oxide reduction rules
to the states for implementation. The final rules require compliance by May 31,
2003 for 19 states, not including Mississippi. However, the Company is affected
by this rule through its forty percent ownership interest in Greene County Steam
Plant in Alabama.
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
eight-hour ozone standard unlawful and remanded it to the EPA for further
rulemaking. During 2003, the EPA proposed implementation rules designed to
address the court's concerns. The EPA plans to designate areas as attainment or
nonattainment with the new eight-hour ozone standard in April 2004 and with the
new fine particulate matter standard by the end of 2004. These designations will
be based on air quality data for 2001 through 2003. Based on the most recent air
monitoring data, it is anticipated that all counties in the Company's service
area will initially be in attainment with both of these standards. However, the
impact of any new standards will depend on the development and implementation of
applicable regulations and cannot be determined at this time.
In January 2004, the EPA issued a proposed Interstate Air Quality Rule to
address interstate transport of ozone and fine particles. This proposed rule
would require additional year-round sulfur dioxide and nitrogen oxide emission
reductions from power plants in the eastern United States in two phases - in
2010 and 2015. The EPA currently plans to finalize this rule by 2005. If
finalized, the rule could modify or supplant other state implementation plan
(SIP) requirements for attainment of the fine particulate matter standard and
the eight-hour ozone standard. The impact of this rule on the Company will
depend upon the specific requirements of the final rule and cannot be determined
at this time.
Further reductions in sulfur dioxide and nitrogen oxides 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 SIPs 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. The
SIPs must contain emission reduction strategies for implementing BART and
achieving progress toward the Clean Air Act's 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. The EPA has entered into an agreement that
requires proposed revised rules in April 2004 and final rules in 2005. Because
new BART rules have not been developed and state visibility assessments for
progress 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. In 2004 and 2005, the Plant
Watson and Plant Daniel coal fired units will likely become subject to CAM
requirements. The Company is in the process of developing CAM plans for Plant
Daniel. The Company's CAM plans for Plant Watson are awaiting approval by the
Mississippi Department of Environmental Quality (MDEQ). Due to the CAM plans not
yet being approved, the Company cannot determine the ultimate costs associated
with implementation of the CAM regulations. Actual ongoing monitoring costs are
expensed as incurred and are not material for any year presented.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2003 Annual Report
In January 2004, the EPA issued proposed rules regulating mercury emissions
from electric utility boilers. The proposal solicits comments on two possible
approaches for the new regulations - a Maximum Achievable Control Technology
approach and a cap-and-trade approach. Either approach would require significant
reductions in mercury emissions from company facilities. The regulations are
scheduled to be finalized by the end of 2004, and compliance could be required
as early as 2007. Because the regulations have not been finalized, the impact on
the Company cannot be determined at this time.
Several major bills to amend the Clean Air Act to impose more stringent
emissions limitations on power plants have been proposed by Congress. Three of
these, the Bush Administration's Clear Skies Act, the Clean Power Act of 2003,
and the Clean Air Planning Act of 2003, propose to further limit power plant
emissions of sulfur dioxide, nitrogen oxides, and mercury. The latter two bills
also propose to limit emissions of carbon dioxide. The cost impacts of such
legislation would depend upon the specific requirements enacted and cannot be
determined at this time.
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, known
as Climate VISION, 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. The electric utility
sector has pledged to reduce its greenhouse gas intensity 3 percent to 5 percent
over the next decade and is in the process of developing a memorandum of
understanding with the Department of Energy (DOE) to cover this voluntary
program.
The Company must comply with other environmental laws and regulations that
cover the handling and disposal of waste and releases 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 has recognized in the financial statements the costs for clean up of
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 has been developing new rules aimed at
reducing impingement and entrainment of fish and fish larvae at power plant's
cooling water intake structures. On February 16, 2004, the EPA finalized these
rules. These rules will require biological studies, and perhaps, retrofits to
some intake structures at existing power plants. The impact of these new rules
will depend on the results of studies and analyses performed as part of the
rules' implementation.
In addition, under the Clean Water Act, the EPA and the 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. 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.
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 or
regulations related to global climate change, electromagnetic fields, or other
environmental and health concerns could also significantly affect the Company.
The impact of any new legislation, changes to existing legislation, or
environmental regulations could affect many areas of the Company's operations.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2003 Annual Report
The full impact of any such changes, however, cannot be determined at this time.
FERC Matters
Transmission
In December 1999, the FERC issued its final rule (Order 2000) on Regional
Transmission Organizations (RTOs). Order 2000 encouraged utilities owning
transmission systems to form RTOs on a voluntary basis. Southern Company and its
retail operating companies, including the Company, worked with a number of
utilities in the Southeast to develop a for-profit RTO known as SeTrans. In
2002, the sponsors of SeTrans established a Stakeholder Advisory Committee to
provide input into the development of the RTO from other sectors of the electric
industry, as well as consumers. During the development of SeTrans, state
regulatory authorities expressed concern over certain aspects of the FERC's
policies regarding RTOs. In December 2003, the SeTrans sponsors announced that
they would suspend work on SeTrans because the regulated utility participants,
including Southern Company's retail operating companies, had determined that it
was highly unlikely to obtain support of both federal and state regulatory
authorities. Any impact of the FERC's rule on the Company will depend on the
regulatory reaction to the suspension of SeTrans and future developments, which
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 day ahead and spot energy markets;
and (7) revise the FERC policy on the pricing of transmission expansions.
Comments on the proposal were submitted by many interested parties, including
Southern Company, and the FERC has indicated that it has revised certain aspects
of the proposal in response to public comments. Proposed energy legislation
would prohibit the FERC from issuing the final rule before October 31, 2006, and
from making any final rule effective before December 31, 2006. That legislation
has been approved by the House of Representatives but remains pending before the
Senate. Passage of the legislation now appears in doubt. It is uncertain whether
in the absence of legislation the FERC will move forward with any part or all of
the proposed rule. Any impact of this proposal on the Company will depend on the
form in which the final rule may be ultimately adopted. However, the Company's
financial statements could be adversely affected by changes in the transmission
regulatory structure in its regional power market.
Market-Based Rate Authority
The Company has obtained FERC approval to sell power to nonaffiliates at
market-based prices under specific contracts. Through SCS, as agent, the Company
also has FERC authority to make short-term opportunity sales at market rates.
Specific FERC approval must be obtained with respect to a market-based contract
with an affiliate. In November 2001, the FERC modified the test it uses to
consider utilities' applications to charge market-based rates and adopted a new
test called the Supply Margin Assessment (SMA). The FERC applied the SMA to
several utilities, including Southern Company's retail operating companies, and
found them and others to be "pivotal suppliers" in their service areas and
ordered the implementation of several mitigation measures. SCS, on behalf of the
Company and the other retail operating companies, sought rehearing of the FERC
order, and the FERC delayed the implementation of certain mitigation measures.
SCS, on behalf of the Company and the other retail operating companies,
submitted comments to the FERC in 2002 regarding these issues. In December 2003,
the FERC issued a staff paper discussing alternatives and held a technical
conference in January 2004. The Company anticipates that the FERC will address
the requests for rehearing in the near future. Regardless of the outcome of the
SMA proposal, the FERC retains the ability to modify or withdraw the
authorization for any seller to sell at market-based rates if it determines that
the underlying conditions for having such authority are no longer applicable.
The final outcome of this matter will depend on the form in which the SMA test
and mitigation measures rules may be ultimately adopted and cannot be determined
at this time.
Wholesale Customer Settlement Agreement
In February 2002, the Company reached a settlement agreement with certain of its
wholesale customers to increase its wholesale tariff rates effective June 1,
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2003 Annual Report
2002. The FERC accepted the settlement agreement and placed the new tariff rates
in effect without modification. The settlement agreement resulted 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.
Other Matters
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 $1.7 million, $2.5 million, and $3.2
million in 2003, 2002, and 2001, respectively. Future pension income is
dependent on several factors including trust earnings and changes to the plan.
The decline in pension income is expected to continue and become an expense as
early as 2006. Postretirement benefit costs for the Company were $4 million,
$3.7 million, and $3.3 million in 2003, 2002, and 2001, respectively 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. Pension income or expense and postretirement benefit costs are a
component of regulated rates and generally do not have a long-term effect on net
income. For more information regarding pension and postretirement benefits, see
Note 2 to the financial statements.
On December 8, 2003, President Bush signed into law the Medicare
Prescription Drug, Improvement and Modernization Act of 2003 (Medicare Act). The
Medicare Act introduces a prescription drug benefit for Medicare-eligible
retirees starting in 2006, as well as a federal subsidy to plan sponsors like
the Company that provide prescription drug benefits. In accordance with FASB
Staff Position No. 106-1, the Company has elected to defer recognizing the
effects of the Medicare Act for its postretirement plans under FASB Statement
No. 106, Employers' Accounting for Postretirement Benefits Other than Pension,
until authoritative guidance on accounting for the federal subsidy is issued or
until a significant event occurs that would require remeasurement of the plans'
assets and obligations. The Company anticipates that the benefits it pays after
2006 will be lower as a result of the Medicare Act; however, the retiree medical
obligations and costs reported in Note 2 to the financial statements do not
reflect these changes. The final accounting guidance could require changes to
previously reported information.
On May 21, 2003, the Company entered into an agreement with Dynegy that
resolved and terminated in 2003 all outstanding matters related to a capacity
sales contract with a subsidiary of Dynegy. The termination payments from Dynegy
resulted in a one-time gain to the Company of approximately $38 million after
tax.
On December 5, 2003, the Company filed a request with the MPSC to include
266 megawatts of Plant Daniel Units 3 and 4 generating capacity in
jurisdictional cost of service. In addition, the Company proposed to modify
certain provisions of its Performance Evaluation Plan (PEP), the mechanism used
for evaluating the Company's retail rate levels. The proposed changes include
(1) the use of a forward-looking, rather than a historical, test year, (2)
adjustments to the performance indicator mechanism, and, (3) an annual, rather
than semi-annual, evaluation period. The Company expects the MPSC to make a
decision on its proposal during the second quarter of 2004. See Note 3 to the
financial statements under "Retail Regulatory Filing" and "2001 Retail Rate
Case" for additional information.
In December 2001, the MPSC approved an increase in the Company's annual
retail rate revenues of approximately $39 million, effective January 2002.
Additionally, the MPSC ordered the Company to reactivate semi-annual evaluations
under the PEP, beginning with the 12-month period ending December 31, 2002. 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 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 Regulatory Filing" for additional
information.
The Company is involved in various matters being litigated and regulatory
matters that could affect future earnings. See Note 3 to the financial
statements for information regarding material issues.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2003 Annual Report
ACCOUNTING POLICIES
- -------------------
Application of Critical Accounting Policies and Estimates
The Company prepares its financial statements in accordance with accounting
principles generally accepted in the United States. Significant accounting
policies are described in Note 1 to the financial statements. In the application
of these policies, certain estimates are made that may have a material impact on
the Company's results of operations and related disclosures. Different
assumptions and measurements could produce estimates that are significantly
different from those recorded in the financial statements. Senior management has
discussed the development and selection of the critical accounting policies and
estimates described below with the Controls and Compliance Committee of the
Company's Board of Directors and the Audit Committee of Southern Company's Board
of Directors.
Electric Utility Regulation
The Company is subject to retail regulation by the MSPC and wholesale regulation
by the FERC. These regulatory agencies set the rates the Company is permitted to
charge customers based on allowable costs. As a result, the Company applies FASB
Statement No. 71, Accounting for the Effects of Certain Types of Regulation.
Through the ratemaking process, the regulators may require the inclusion of
costs or revenues in periods different than when they would be recognized by a
non-regulated company. This treatment may result in the deferral of expenses and
the recording of related regulatory assets based on anticipated future recovery
through rates or the deferral of gains or creation of liabilities and the
recording of related regulatory liabilities. The application of Statement No. 71
has a further effect on the Company's financial statements as a result of the
estimates of allowable costs used in the ratemaking process. These estimates may
differ from those actually incurred by the Company; therefore, the accounting
estimates inherent in specific costs such as depreciation and pension and
post-retirement benefits have less of a direct impact on the Company's results
of operations than they would on a non-regulated company.
As reflected in Note 1 to the financial statements, significant regulatory
assets and liabilities have been recorded. Management reviews the ultimate
recoverability of these regulatory assets and liabilities based on applicable
regulatory guidelines. However, adverse legislation and judicial or regulatory
actions could materially impact the amounts of such regulatory assets and
liabilities and could adversely impact the Company's financial statements.
Contingent Obligations
The Company is subject to a number of federal and state laws and regulations, as
well as other factors and conditions that potentially subject it to
environmental, litigation, income tax, and other risks. See "Future Earnings
Potential" and Note 3 to the financial statements for more information regarding
certain of these contingencies. The Company periodically evaluates its exposure
to such risks and records reserves for those matters where a loss is considered
probable and reasonably estimable in accordance with generally accepted
accounting principles. The adequacy of reserves can be significantly affected by
external events or conditions that can be unpredictable; thus, the ultimate
outcome of such matters could materially affect the Company's financial
statements. These events or conditions include the following:
o Changes in existing state or federal regulation by governmental authorities
having jurisdiction over air quality, water quality, control of toxic
substances, hazardous and solid wastes, and other environmental matters.
o Changes in existing income tax regulations or changes in Internal Revenue
Service interpretations of existing regulations.
o Identification of additional sites that require environmental remediation or
the filing of other complaints in which the Company may be asserted to be a
potentially responsible party.
o Identification and evaluation of other potential lawsuits or complaints in
which the Company may be named as a defendant.
o Resolution or progression of existing matters through the legislative
process, through the court systems, or through the EPA.
Plant Daniel Capacity
As discussed in Note 3 to the financial statements under "Retail Regulatory
Filing," the Company requested and received an interim accounting order from the
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2003 Annual Report
MPSC on December 16, 2003. The order directed the Company to expense and record
in 2003 a regulatory liability of $60.3 million pending the conclusion of the
MPSC's evaluation of the Company's request to include an additional 266
megawatts of Plant Daniel Units 3 and 4 generating capacity in jurisdictional
cost of service. The MPSC is not expected to complete its evaluation and issue a
final order until the second quarter of 2004. Management believes that the
interim accounting order represents a probable liability and that recognition of
the expense in 2003 is appropriate. However, if the MPSC ultimately refuses the
Company's request, the regulatory liability will be required to be reversed.
Plant Daniel Operating Lease
As discussed in Note 7 to the financial statements under "Operating Leases," the
Company entered into a lease for a 1,064 megawatt natural gas combined cycle
facility at Plant Daniel (Facility) with Juniper Capital L.P. (Juniper). For
both accounting and rate recovery purposes, this transaction is treated as an
operating lease, which means that the related obligations under this agreement
are not reflected on the Company's Balance Sheets, See "Financial Condition and
Liquidity - Off-Balance Sheet Financing Arrangements" herein for further
information. The operating lease determination was based on assumptions and
estimates related to the following:
o Fair market value of the Facility at lease inception.
o The Company's incremental borrowing rate.
o Timing of debt payments and the related amortization of the initial
acquisition cost during the initial lease term.
o Residual value of the Facility at the end of the lease term.
o Estimated economic life of the Facility.
o Juniper's status as a voting interest entity.
The determination of operating lease treatment is made at the inception of
the lease agreement and is not subject to change unless subsequent changes are
made to the agreement. However, in accordance with FASB Interpretation No. 46,
Consolidation of Variable Interest Entities, the Company also is required to
monitor Juniper's ongoing status as a voting interest entity. Changes in that
status could require the Company to consolidate the Facility's assets and the
related debt and to record interest and depreciation expense of approximately
$34 million annually, rather than annual lease expense of approximately $26
million.
New Accounting Standards
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,
established 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 is recorded in the
period in which the liability is incurred. The costs are capitalized as part of
the related long-lived asset and depreciated over the asset's useful life.
Additionally, non-regulated companies are no longer permitted 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 "Asset Retirement Obligations and Other Costs of Removal."
Derivative Instruments
FASB Statement No. 149, Amendment of Statement 133 on Derivative Instruments and
Hedging Activities, which further amends and clarifies the accounting and
reporting for derivative instruments, became effective generally for financial
instruments entered into or modified after June 30, 2003. Current
interpretations of Statement No. 149 indicate that certain electricity forward
transactions subject to unplanned netting -- including those typically referred
to as "book outs" -- may only qualify as cash flow hedges if an entity can
demonstrate that physical delivery or receipt of power occurred. The Company's
forward electricity contracts continue to be exempt from fair value accounting
requirements or to qualify as cash flow hedges, with the related gains and
losses deferred in other comprehensive income. The implementation of Statement
No. 149 did not have a material effect on the Company's financial statements.
In July 2003, the Emerging Issues Task Force (EITF) of FASB issued EITF No.
03-11, which became effective on October 1, 2003. The standard addresses the
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2003 Annual Report
reporting of realized gains and losses on derivative instruments and is being
interpreted to require book outs to be recorded on a net basis in operating
revenues. Adoption of this standard did not have a material impact on the
Company's financial statements.
Variable Interest Entities
FASB Interpretation No. 46, Consolidation of Variable Interest Entities, which
was originally issued in January 2003, requires the primary beneficiary of a
variable interest entity to consolidate the related assets and liabilities. The
Company's previous interest in a variable interest entity related to the lease
arrangement for certain facilities at Plant Daniel was restructured prior to the
original effective date of July 1, 2003, and is no longer subject to
Interpretation No. 46. See Note 7 to the financial statements under "Operating
Leases -- Plant Daniel Combined Cycle Generating Units" for additional
information. In December 2003, the FASB revised Interpretation No. 46 and
deferred the effective date until March 31, 2004, for interests held in variable
interest entities other than special purpose entities.
Current analysis indicates that the trust established by the Company to
issue preferred securities is a variable interest entity under Interpretation
No. 46, and that the Company is not the primary beneficiary of this trust. If
this conclusion is finalized, effective March 31, 2004, the trust assets and
liabilities -- including the preferred securities issued by the trust -- will be
deconsolidated. The investments in the trust and the loans from the trust to the
Company will be reflected as equity method investments and as long-term notes
payable to affiliates, respectively, on the Balance Sheets. Based on December
31, 2003 values, this treatment would result in an increase of approximately $1
million to both total assets and total liabilities. See Note 6 to the financial
statements under "Mandatorily Redeemable Preferred Securities" for additional
information.
Liabilities and Equity
In May 2003, the FASB issued Statement No. 150, Accounting or Certain
Financial Instruments with Characteristics of Both Liabilities and Equity, which
requires classification of certain financial instruments within its scope,
including shares that are mandatorily redeemable, as liabilities. Statement No.
150 was effective for financial instruments entered into or modified after May
31, 2003, and otherwise on July 1, 2003. In accordance with Statement No. 150,
mandatorily redeemable preferred securities are reflected on the Balance Sheets
as liabilities. The adoption of Statement No. 150 had no impact on the
Statements of Income and Cash Flows.
FINANCIAL CONDITION AND LIQUIDITY
- ---------------------------------
Overview
During 2003, the Company operated at high levels of reliability while achieving
industry-leading customer satisfaction levels and continuing to have retail
prices below the national average.
The Company's ratio of common equity to total capitalization, excluding
long-term debt due within one year, increased from 62.5 percent in 2002 to 66.4
percent at December 31, 2003.
The principal changes in the Company's financial condition during 2003 were
the addition of approximately $69.3 million to utility plant and the reduction
of long-term debt. See the Statements of Cash Flows for additional information.
Sources of Capital
The Company plans to obtain the funds required for construction and other
purposes, including compliance with environmental regulations, 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. However,
the type and timing of any future financings--if needed--will depend on market
conditions and regulatory approval.
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
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2003 Annual Report
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.
The Company obtains financing separately without credit support from any
affiliate. The Southern Company system does not maintain a centralized cash or
money pool. Therefore, funds of the Company are not commingled with funds of any
other company. In accordance with the Public Utility Holding Company Act, most
loans between affiliated companies must be approved in advance by the Securities
and Exchange Commission (SEC).
At December 31, 2003, the Company's current liabilities exceed current
assets because of the scheduled maturity of $80 million of adjustable rate
long-term notes payable in 2004.
To meet short-term cash needs and contingencies, the Company has various
internal and external sources of liquidity. At the beginning of 2004, the
Company had approximately $69 million of cash and cash equivalents and $100
million of unused credit arrangements with banks, as shown in the following
table. 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 retail operating companies. Proceeds from such issuances for
the benefit of the Company are loaned directly to the Company and are not
commingled with proceeds from such issuances for the benefit of any other
operating company. The obligations of each company under these arrangements are
several; there is no cross affiliate credit support. At December 31, 2003, the
Company had no outstanding commercial paper or extendible commercial notes.
At the beginning of 2004, the bank credit arrangements are as follows:
Expires
----------------------------------
Total Unused 2004 2005 & Beyond
----------------------------------------------------------
(in millions)
$100 $100 $100 -
----------------------------------------------------------
See the Statement of Cash Flows and Note 6 to the financial statements
under "Bank Credit Arrangements" for additional information.
Financing Activities
During 2003, 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:
2003 2002 2001
------------------------------------------------------------
Composite interest rate on
long-term debt 3.26% 4.10% 4.60%
Composite preferred stock
dividend rate 6.33% 6.33% 6.33%
Composite distribution rate
on preferred securities 7.20% 7.20% 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 revenue
bonds, originally due in 2007.
In April 2003, the Company issued $90 million of Series E 5-5/8% Senior
Notes due May 1, 2033. The proceeds from this sale were used to repay at
maturity $35 million of the Company's Series B 6.05% Senior Notes due May 1,
2003, to redeem the $51.6 million outstanding principal amount of the Company's
Series A 6.75% Senior Insured Quarterly Notes due June 30, 2038, and to repay a
portion of the Company's outstanding short-term indebtedness.
Off-Balance Sheet Financing Arrangements
In June 2003 the Company entered into a restructured lease agreement for the
Facility with Juniper, as discussed in Note 7 to the financial statements under
"Operating Leases." Juniper has also entered into leases with other parties
unrelated to the Company. The assets leased by the Company comprise less than 50
percent of Juniper's assets. In accordance with FASB Interpretation No. 46, the
Company does not consolidate the leased assets and related liabilities, and the
lease with Juniper is considered an operating lease under FASB Statement No. 13.
Accordingly, the lease is not reflected on the Company's Balance Sheets.
The initial lease term ends in 2011, and the lease includes a purchase and
II-214
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2003 Annual Report
renewal option based on the cost of the Facility at the inception of the lease,
which was $369 million. The Company is required to amortize approximately four
percent of the initial acquisition cost over the initial lease term. Eighteen
months prior to the end of the initial lease, the Company may elect to renew for
10 years. If the lease is renewed, 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, it may
either exercise its purchase option or the Facility can be sold to a third
party.
The lease also provides for a residual value guarantee -- approximately 73
percent of the acquisition cost -- by the Company that is due upon termination
of the lease in the event that the Company does not renew the lease or purchase
the Facility and that the fair market value is less than the unamortized cost of
the Facility.
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, 2003,
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.
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, 2003 was 1.3 percent. Based on the Company's overall variable
rate long-term debt exposure at December 31, 2003, a near-term 100 basis point
change in interest rates would affect annualized interest expense by
approximately $1.6 million. 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, 2003,
exposure from these activities was not material to the Company's financial
statements.
In addition, at the instruction of the MPSC, the Company has implemented a
fuel-hedging program. At December 31, 2003, 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
-----------------------------
2003 2002
- --------------------------------------------------------------
(in thousands)
Contracts beginning of
year $ 12,864 $ (3,830)
Contracts realized or
settled (17,210) (1,562)
Current period changes 6,816 18,256
- --------------------------------------------------------------
Contracts end of year $ 2,470 $ 12,864
==============================================================
At December 31, 2003, 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 clause. 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, 2003, 2002, and 2001, these amounts were not material.
II-215
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2003 Annual Report
At December 31, 2003, the fair value of derivative energy contracts was
reflected in the financial statements as follows:
Amounts
------------------------------------------------------------
(in thousands)
Regulatory liabilities, net $2,468
Net income 2
------------------------------------------------------------
Total fair value $2,470
The Company is exposed to market price risk in the event of
nonperformance by counterparties 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 further information see Notes 1 and 6
to the financial statements under "Financial Instruments."
Capital Requirements and Contractual Obligations
The construction program of the Company is currently
estimated to be $80 million for 2004, $70 million for 2005, and $98 million for
2006. Environmental expenditures included in these amounts are $2.7 million,
$5.3 million, and $12.6 million for 2004, 2005, and 2006, 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; load projections; the cost and efficiency of
construction labor, equipment, and materials; and the cost of capital. In
addition, there can be no assurance that costs related to capital expenditures
will be fully recovered.
Other funding requirements relate to obligations associated with scheduled
maturities of long-term debt and preferred securities, as well as the related
interest and distributions, preferred stock dividends, leases, and other
purchase commitments are as follows. See Notes 1, 6, and, 7 to the financial
statements for additional information.
2005- 2007- After
2004 2006 2008 2008 Total
- ---------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Long-term debt and preferred
securities (a) --
Principal $ 80,000 $ - $ - $237,695 $ 317,695
Interest and distributions 11,750 21,468 21,468 265,263 319,949
Preferred stock dividends (b) 2,013 4,026 4,026 - 10,065
Operating leases 30,982 61,839 61,407 93,355 247,583
Purchase commitments (c)
Capital (d) 80,166 167,525 - - 247,691
Coal 173,794 151,117 20,721 - 345,632
Natural Gas (e) 140,328 150,270 50,743 53,845 395,186
Long-term service agreements 10,913 22,627 19,453 128,141 181,134
Post retirement benefit trust (f) 330 660 - - 990
- ---------------------------------------------------------------------------------------------------------------------------------
Total $ 530,276 $579,532 $177,818 $778,299 $2,065,925
=================================================================================================================================
(a) All amounts are reflected based on final maturity dates. The Company will continue to retire higher-cost securities and
replace these obligations with lower-cost capital if market conditions permit. Variable rate interest obligations are
estimated based on rates as of January 1, 2004, as reflected in the Statements of Capitalization.
(b) Preferred stock does not mature; therefore, amounts are provided for the next five years only.
(c) The Company generally does not enter into non-cancelable commitments for other operation and maintenance expenditures.
Total other operation and maintenance expenses for the last three years were $300 million, $232 million, and $191 million,
respectively.
(d) The Company forecasts capital expenditures over a three-year period. Amounts represent current estimates of total
expenditures. At December 31, 2003, significant purchase commitments were outstanding in connection with the construction
program.
(e) Natural gas purchase commitments are based on various indices at the time of delivery. Amounts reflected have been estimated
based on the New York Mercantile future prices at December 31, 2003.
(f) The Company forecasts postretirement trust contributions over a three-year period. No contributions related to the Company's
pension trust are currently expected during this period. See Note 2 to the financial statements for additional information
related to the pension plans.
II-216
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2003 Annual Report
Cautionary Statement Regarding Forward-Looking Information
The Company's 2003 Annual Report includes forward-looking statements in addition
to historical information. Forward-looking information includes, among other
things, statements concerning the estimated construction and other expenditures,
projections for energy sales, 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. 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:
o 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, tax and other laws and regulations to which the Company is
subject, as well as changes in application of existing laws and regulations;
o current and future litigation, regulatory investigations, proceedings or
inquiries, including the pending EPA civil action against the Company;
o the effects, extent, and timing of the entry of additional competition in the
markets in which the Company operates;
o the impact of fluctuations in commodity prices, interest rates, and customer
demand;
o available sources and costs of fuels;
o ability to control costs;
o investment performance of the Company's employee benefit plans;
o advances in technology;
o state and federal rate regulations and pending and future rate cases and
negotiations;
o effects of and changes in political, legal, and economic conditions and
developments in the United States, including the current soft economy;
o internal restructuring or other restructuring options that may be pursued;
o potential business strategies, including acquisitions or dispositions of
assets, which can not be assumed to be completed or beneficial to the
Company;
o the ability of counterparties of the Company to make payments as and when
due;
o the ability to obtain new short- and long-term contracts with neighboring
utilities;
o the direct or indirect effects on the Company's business resulting from the
terrorist incidents on September 11, 2001, or any similar incidents or
responses to such incidents;
o financial market conditions and the results of financing efforts, including
the Company's credit ratings;
o the ability of the Company to obtain additional generating capacity at
competitive prices;
o weather and other natural phenomena;
o the direct or indirect effects on the Company's business resulting from the
August 2003 power outage in the Northeast, or any similar incidents;
o the effect of accounting pronouncements issued periodically by
standard-setting bodies; and
o other factors discussed elsewhere herein and in other reports (including the
Form 10-K) filed from time to time by the Company with the SEC.
II-217
STATEMENTS OF INCOME
For the Years Ended December 31, 2003, 2002, and 2001
Mississippi Power Company 2003 Annual Report
- --------------------------------------------------------------------------------------------------------------------------
2003 2002 2001
- --------------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Revenues:
Retail sales $516,301 $536,827 $489,153
Sales for resale --
Non-affiliates 249,986 224,275 204,623
Affiliates 26,723 46,314 85,652
Contract termination 62,111 - -
Other revenues 14,803 16,749 16,637
- --------------------------------------------------------------------------------------------------------------------------
Total operating revenues 869,924 824,165 796,065
- --------------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Fuel 229,251 282,393 277,946
Purchased power --
Non-affiliates 18,523 18,550 41,254
Affiliates 74,674 32,783 53,990
Other operations --
Plant Daniel capacity 60,300 - -
Other 169,775 158,354 134,845
Maintenance 70,043 73,659 56,153
Depreciation and amortization 55,700 57,638 54,077
Taxes other than income taxes 53,991 55,518 44,966
- --------------------------------------------------------------------------------------------------------------------------
Total operating expenses 732,257 678,895 663,231
- --------------------------------------------------------------------------------------------------------------------------
Operating Income 137,667 145,270 132,834
Other Income and (Expense):
Interest income 617 655 369
Interest expense (14,369) (18,650) (23,568)
Distributions on mandatorily redeemable preferred securities (2,520) (3,016) (2,712)
Other income (expense), net (568) (3,354) (532)
- --------------------------------------------------------------------------------------------------------------------------
Total other income and (expense) (16,840) (24,365) (26,443)
- --------------------------------------------------------------------------------------------------------------------------
Earnings Before Income Taxes 120,827 120,905 106,391
Income taxes 45,315 45,879 40,533
- --------------------------------------------------------------------------------------------------------------------------
Earnings Before Cumulative Effect of 75,512 75,026 65,858
Accounting Change
Cumulative effect of accounting change--
less income taxes of $43 thousand - - 70
- --------------------------------------------------------------------------------------------------------------------------
Net Income 75,512 75,026 65,928
Dividends on Preferred Stock 2,013 2,013 2,041
- --------------------------------------------------------------------------------------------------------------------------
Net Income After Dividends on Preferred Stock $ 73,499 $ 73,013 $ 63,887
==========================================================================================================================
The accompanying notes are an integral part of these financial statements.
II-218
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2003, 2002, and 2001
Mississippi Power Company 2003 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------------
2003 2002 2001
- -----------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Activities:
Net income $ 75,512 $ 75,026 $ 65,928
Adjustments to reconcile net income
to net cash provided from operating activities --
Depreciation and amortization 60,226 61,930 58,105
Deferred income taxes and investment tax credits, net (8,562) (3,404) (9,718)
Plant Daniel capacity 60,300 - -
Pension, postretirement, and other employee benefits (1,014) 730 (2,467)
Tax benefit of stock options 2,323 1,826 -
Other, net 6,517 2,017 4,349
Changes in certain current assets and liabilities --
Receivables, net 21,038 6,120 (7,796)
Fossil fuel stock 2,070 4,186 (20,269)
Materials and supplies (1,607) 1,160 (1,529)
Other current assets 1,750 (13,346) 138
Accounts payable (12,292) 18,487 53,462
Accrued taxes (8,976) 3,160 4,695
Other current liabilities (13,804) 34,770 6,977
- -----------------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities 183,481 192,662 151,875
- -----------------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (69,345) (67,460) (61,193)
Cost of removal net of salvage (5,811) (9,987) (3,042)
Other (2,080) (3,471) 54
- -----------------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities (77,236) (80,918) (64,181)
- -----------------------------------------------------------------------------------------------------------------------------------
Financing Activities:
Increase (decrease) in notes payable, net - (15,973) (40,027)
Proceeds --
Pollution control bonds - 42,625 -
Senior notes 90,000 80,000 -
Mandatorily redeemable preferred securities - 35,000 -
Capital contributions from parent company 4,912 16,198 73,095
Redemptions --
First mortgage bonds (33,350) (650) (36,000)
Pollution control bonds (850) (42,645) (20)
Senior notes (86,628) (80,550) (21,001)
Mandatorily redeemable preferred securities - (35,000) -
Payment of preferred stock dividends (2,013) (2,013) (2,041)
Payment of common stock dividends (66,000) (63,500) (50,200)
Other (5,891) (1,491) (81)
- -----------------------------------------------------------------------------------------------------------------------------------
Net cash used for financing activities (99,820) (67,999) (76,275)
- -----------------------------------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents 6,425 43,745 11,419
Cash and Cash Equivalents at Beginning of Period 62,695 18,950 7,531
- -----------------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ 69,120 $ 62,695 $ 18,950
===================================================================================================================================
Supplemental Cash Flow Information:
Cash paid during the period for --
Interest (net of $0, $0, and $0 capitalized, respectively) $17,334 $17,743 $28,126
Income taxes (net of refunds) 60,618 50,240 45,761
- -----------------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
II-219
BALANCE SHEETS
At December 31, 2003 and 2002
Mississippi Power Company 2003 Annual Report
- ------------------------------------------------------------------------------------------------------------------------------
Assets 2003 2002
- ------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Current Assets:
Cash and cash equivalents $ 69,120 $ 62,695
Receivables --
Customer accounts receivable 30,514 31,136
Unbilled revenues 19,278 18,434
Under recovered regulatory clause revenues 14,607 27,233
Other accounts and notes receivable 8,088 8,056
Affiliated companies 12,160 20,674
Accumulated provision for uncollectible accounts (897) (718)
Fossil fuel stock, at average cost 25,233 27,303
Materials and supplies, at average cost 23,670 22,063
Assets from risk management activities 2,857 13,061
Vacation pay 5,766 5,782
Prepaid income taxes 27,415 18,675
Prepaid expenses 4,517 1,687
- ------------------------------------------------------------------------------------------------------------------------------
Total current assets 242,328 256,081
- ------------------------------------------------------------------------------------------------------------------------------
Property, Plant, and Equipment:
In service 1,841,668 1,786,378
Less accumulated provision for depreciation 672,730 652,358
- ------------------------------------------------------------------------------------------------------------------------------
1,168,938 1,134,020
Construction work in progress 25,844 34,065
- ------------------------------------------------------------------------------------------------------------------------------
Total property, plant, and equipment 1,194,782 1,168,085
- ------------------------------------------------------------------------------------------------------------------------------
Other property and investments 2,750 1,768
- ------------------------------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets:
Deferred charges related to income taxes 12,125 12,617
Prepaid pension costs 18,167 14,993
Unamortized debt issuance expense 6,993 4,304
Unamortized loss on reacquired debt 10,201 7,776
Prepaid rent 14,758 -
Other 16,280 16,416
- ------------------------------------------------------------------------------------------------------------------------------
Total deferred charges and other assets 78,524 56,106
- ------------------------------------------------------------------------------------------------------------------------------
Total Assets $1,518,384 $1,482,040
==============================================================================================================================
The accompanying notes are an integral part of these financial statements.
II-220
BALANCE SHEETS
At December 31, 2003 and 2002
Mississippi Power Company 2003 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------------
Liabilities and Stockholder's Equity 2003 2002
- ----------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Current Liabilities:
Securities due within one year $ 80,000 $ 69,200
Accounts payable --
Affiliated 21,259 22,396
Other 55,309 65,372
Customer deposits 11,863 6,855
Accrued taxes --
Income taxes 1,696 12,042
Other 42,834 41,464
Accrued interest 3,223 6,562
Accrued vacation pay 5,766 5,782
Accrued compensation 23,832 26,338
Regulatory clauses over recovery 31,118 35,680
Other 4,867 5,533
- ----------------------------------------------------------------------------------------------------------------------------------
Total current liabilities 281,767 297,224
- ----------------------------------------------------------------------------------------------------------------------------------
Long-term debt (See accompanying statements) 202,488 243,715
- ----------------------------------------------------------------------------------------------------------------------------------
Mandatorily redeemable preferred securities (See accompanying statements) 35,000 35,000
- ----------------------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 142,088 146,631
Deferred credits related to income taxes 23,279 20,798
Accumulated deferred investment tax credits 19,841 21,054
Employee benefit obligations 54,830 52,840
Plant Daniel lease guarantee obligation, at fair value 14,758 -
Plant Daniel capacity 60,300 -
Other cost of removal obligations 80,588 69,873
Miscellaneous regulatory liabilities 11,899 20,807
Other 27,248 24,336
- ----------------------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 434,831 356,339
- ----------------------------------------------------------------------------------------------------------------------------------
Total liabilities 954,086 932,278
- ----------------------------------------------------------------------------------------------------------------------------------
Preferred stock (See accompanying statements) 31,809 31,809
- ----------------------------------------------------------------------------------------------------------------------------------
Common stockholder's equity (See accompanying statements) 532,489 517,953
- ----------------------------------------------------------------------------------------------------------------------------------
Total Liabilities and Stockholder's Equity $1,518,384 $1,482,040
==================================================================================================================================
Commitments and Contingent Matters (See notes)
- -----------------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
II-221
STATEMENTS OF CAPITALIZATION
At December 31, 2003 and 2002
Mississippi Power Company 2003 Annual Report
- ---------------------------------------------------------------------------------------------------------------------------
2003 2002 2003 2002
- ---------------------------------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
Long-Term Debt:
First mortgage bonds --
7.45% due 2023 $ - $ 33,350
6.875% due 2025 30,000 30,000
- ---------------------------------------------------------------------------------------------------------------------------
Total first mortgage bonds 30,000 63,350
- ---------------------------------------------------------------------------------------------------------------------------
Long-term notes payable --
6.05% due May 1, 2003 - 35,000
5.63% due May 1, 2033 90,000 -
6.75% due June 30, 2038 - 51,628
Adjustable rates (1.27% at 1/1/04)
due 2004 80,000 80,000
- ---------------------------------------------------------------------------------------------------------------------------
Total long-term notes payable 170,000 166,628
- ---------------------------------------------------------------------------------------------------------------------------
Other long-term debt --
Pollution control revenue bonds --
Collateralized:
5.80% due 2007 - 850
Non-collateralized:
Variable rates (1.25% to 1.40% at 1/1/04)
due 2020-2028 82,695 82,695
- ---------------------------------------------------------------------------------------------------------------------------
Total other long-term debt 82,695 83,545
- ---------------------------------------------------------------------------------------------------------------------------
Unamortized debt premium (discount), net (207) (608)
- ---------------------------------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
requirement -- $9.2 million) 282,488 312,915
Less amount due within one year 80,000 69,200
- ---------------------------------------------------------------------------------------------------------------------------
Long-term debt excluding amount due within one year 202,488 243,715 25.2% 29.5%
- ---------------------------------------------------------------------------------------------------------------------------
Mandatorily Redeemable Preferred Securities:
$25 liquidation value --
7.20% due 2041 35,000 35,000
- ---------------------------------------------------------------------------------------------------------------------------
Total (annual distribution requirement -- $2.5 million) 35,000 35,000 4.4 4.2
- ---------------------------------------------------------------------------------------------------------------------------
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 4.0 3.8
- ---------------------------------------------------------------------------------------------------------------------------
Common Stockholder's Equity:
Common stock, without par value --
Authorized - 1,130,000 shares
Outstanding - 1,121,000 shares in 2003 and 2002 37,691 37,691
Paid-in capital 292,515 285,280
Premium on preferred stock 326 326
Retained earnings 203,419 195,920
Accumulated other comprehensive income (loss) (1,462) (1,264)
- ---------------------------------------------------------------------------------------------------------------------------
Total common stockholder's equity 532,489 517,953 66.4 62.5
- ---------------------------------------------------------------------------------------------------------------------------
Total Capitalization $801,786 $828,477 100.0% 100.0%
===========================================================================================================================
The accompanying notes are an integral part of these financial statements.
II-222
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
For the Years Ended December 31, 2003, 2002, and 2001
Mississippi Power Company 2003 Annual Report
- ---------------------------------------------------------------------------------------------------------------------------------
Premium on Other
Common Paid-In Preferred Retained Comprehensive
Stock Capital Stock Earnings Income (loss) Total
- ---------------------------------------------------------------------------------------------------------------------------------
(in thousands)
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 - 18,024 - - - 18,024
Other comprehensive income (loss) - - - - (1,264) (1,264)
Cash dividends on common stock - - - (63,500) - (63,500)
- ---------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2002 37,691 285,280 326 195,920 (1,264) 517,953
Net income after dividends on preferred stock - - - 73,499 - 73,499
Capital contributions from parent company - 7,235 - - - 7,235
Other comprehensive income (loss) - - - - (198) (198)
Cash dividends on common stock - - - (66,000) - (66,000)
- ----------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2003 $37,691 $292,515 $326 $203,419 $ (1,462) $532,489
=================================================================================================================================
The accompanying notes are an integral part of these financial statements.
STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2003, 2002, and 2001
Mississippi Power Company 2003 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------
2003 2002 2001
- -----------------------------------------------------------------------------------------------------------------------------
Net income after dividends on preferred stock $73,499 $73,013 $63,887
- -----------------------------------------------------------------------------------------------------------------------------
Other comprehensive income (loss):
Change in additional minimum pension liability, net (198) (1,264) -
of tax of $(123) and $(783), respectively
- -----------------------------------------------------------------------------------------------------------------------------
Total other comprehensive income (loss) (198) (1,264) -
- -----------------------------------------------------------------------------------------------------------------------------
Comprehensive Income $73,301 $71,749 $63,887
=============================================================================================================================
The accompanying notes are an integral part of these financial statements.
II-223
NOTES TO FINANCIAL STATEMENTS
Mississippi Power Company 2003 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 retail operating companies,
Southern Power Company (Southern Power), Southern Company Services (SCS),
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 retail 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. The
Company 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. 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 retail 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--the system
service company -- provides, at cost, specialized services to Southern Company
and subsidiary companies. Southern LINC provides digital wireless communications
services to the retail 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 is a competitive retail natural gas
marketer serving customers in Georgia. Southern Holdings is an intermediate
holding subsidiary for Southern Company's investments in synthetic fuels and
leveraged leases and an energy services business. Southern Nuclear operates and
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, including the Company, are subject to the regulatory provisions of
PUHCA. In addition, the Company is 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 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 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
$46.2 million, $43.6 million, and $44.1 million during 2003, 2002 and 2001,
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 $6.6 million, $6.4 million and, $5.5 million in 2003,
2002, and 2001, respectively. 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 $17.7
II-224
NOTES (continued)
Mississippi Power Company 2003 Annual Report
million, $16.6 million, and $13.1 million in 2003, 2002 and, 2001. See Note 4
for additional information.
The retail operating companies (including the Company), Southern Power, and
Southern Company GAS may jointly enter into various types of wholesale energy,
natural gas, and certain other contracts, either directly or through SCS as an
agent. Each participating company may be jointly and severally liable for the
obligations incurred under these agreements.
Revenues and Fuel Costs
Energy and other revenues are recognized as services are rendered. Capacity
revenues from long-term contracts are recognized at the lesser of the levelized
amount or the amount billable under the contract 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. For the year ended
December 31, 2003, Dynegy, Inc. (Dynegy) accounted for approximately 14.8
percent of revenues as a result of non-recurring contract termination revenues.
See Note 3 under "Contract Termination" for additional information. No other
single customer or industry accounted for 10 percent or more of revenues in
2003. For the years ended December 31, 2002 and 2001, no single customer or
industry accounted for 10 percent or more of revenues. For all periods
presented, uncollectible accounts continued to average less than 1/2 percent of
revenues.
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.
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.
II-225
NOTES (continued)
Mississippi Power Company 2003 Annual Report
Regulatory assets and (liabilities) reflected in the Balance Sheets at
December 31 relate to:
2003 2002 Note
- ------------------------------------------------------------------
(in thousands)
(in thousands)
Deferred income tax charges $ 12,125 $ 12,617 (a)
Vacation pay 5,766 5,782 (b)
Loss on reacquired debt 10,201 7,776 (c)
Fuel hedging asset 2,397 14,558 (d)
Asset retirement obligations 689 - (a)
Other assets - 49 (e)
Property damage reserve (6,796) (5,077) (e)
Deferred income tax credits (23,279) (20,798) (a)
Other cost of removal
obligations (80,588) (69,873) (a)
Plant Daniel capacity (60,300) - (f)
Fuel-hedging liabilities (3,870) (14,990) (d)
Other liabilities (1,756) (2,450) (e)
- -------------------------------------------------------------
Total $ (145,411) $ (72,406)
=============================================================
Note: The recovery and amortization periods for these regulatory assets and
(liabilities) are as follows:
(a) Asset retirement and removal liabilities are recorded, deferred income
tax assets are recovered and deferred tax liabilities are amortized over
the related property lives, which may range up to 50 years. Asset
retirement and removal liabilities will be settled and trued up following
completion of the related activities.
(b) Recorded as earned by employees and recovered as paid, generally within
one year.
(c) Recovered over either the remaining life of the original issue or, if
refinanced, over the life of the new issue, which may range up to 50
years.
(d) Fuel-hedging assets and liabilities are recorded over the life of the
underlying hedged purchase contracts, which generally do not exceed two
years. Upon final settlement, costs are recovered through the fuel cost
recovery clause.
(e) Recorded and recovered or amortized as approved by the MPSC.
(f) See Note 3 under "Retail Regulatory Filing."
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 to be reflected in rates.
Depreciation and Amortization
Depreciation of the original cost of plant in service is provided primarily by
using composite straight-line rates, which approximated 3.4 percent in 2003, 3.4
percent in 2002, and 3.5 percent in 2001. 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.
Asset Retirement Obligations
and Other Costs of Removal
In accordance with regulatory requirements, prior to 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 accordance with SEC requirements, such
amounts are reflected on the balance sheet as regulatory liabilities. Effective
January 1, 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 costs 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 costs 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 the continued accrual of future retirement costs for
long-lived assets that the Company does not have a legal obligation to retire.
However, the Company has received guidance regarding accounting for the
financial statement impacts of Statement No. 143 from the MPSC and will continue
to recognize the accumulated removal costs for other obligations as a regulatory
liability. Therefore, the Company has no cumulative effect to net income
resulting from the adoption of Statement No. 143.
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
II-226
NOTES (continued)
Mississippi Power Company 2003 Annual Report
facilities. However, liabilities for the removal of these transmission and
distribution assets have not been recorded because no reasonable estimate can be
made regarding the timing of the obligations. The Company will continue to
recognize in the income statement allowed removal costs in accordance with its
regulatory treatment. Any difference between costs recognized under Statement
No. 143 and those reflected in rates are recognized as either a regulatory asset
or liability and are reflected in the Balance Sheets.
Details of the asset retirement obligations included in the Balance Sheets
are as follows:
2003
- -------------------------------------------------------------
(in millions)
Balance, beginning of year $ -
Liabilities incurred 2.4
Liabilities settled -
Accretion 0.1
Cash flow revisions -
- -------------------------------------------------------------
Balance, end of year $2.5
=============================================================
If Statement No. 143 had been adopted on January 1, 2002, the pro-forma
asset retirement obligations would have been $1 million.
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 cost of funds used
during construction, if applicable. 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 except for the cost of maintenance of coal cars and a portion of the
railway track maintenance costs, which are charged to fuel stock and recovered
through the Company's fuel clause.
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 either by the amount of regulatory disallowance or by
estimating the fair value of the asset and recording a loss for the amount of
the carrying value that 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.
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 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
II-227
NOTES (continued)
Mississippi Power Company 2003 Annual Report
recognized as either assets or liabilities and are measured at fair value.
Substantially all of the Company's bulk energy purchases and sales contracts
that meet the definition of a derivative are exempt from fair value accounting
requirements and are accounted for under the accrual method. Other derivative
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. Other
derivative contracts 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 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 the fair value at December 31 were as follows:
Carrying Fair
Amount Value
- ---------------------------------------------------------------
(in millions)
Long-term debt:
At December 31, 2003 $282 $286
At December 31, 2002 $313 $313
Preferred securities:
At December 31, 2003 $35 $37
At December 31, 2002 $35 $36
==============================================================
The fair values 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
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 $2.5 million in 2003, $1.8 million in 2002, and $2.5 million in 2001. As
of December 31, 2003, the accumulated provision amounted to $6.8 million.
Comprehensive Income
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. Comprehensive
income consists of net income and changes in additional minimum pension
liability, less income taxes and reclassifications for amounts included in net
income.
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 plan is funded in accordance with Employee Retirement Income
Security Act (ERISA) requirements. No contributions to the plan are expected for
the year ending December 31, 2004. The Company provides certain medical care and
life insurance benefits for retired employees. Benefits under these
non-qualified plans are funded on a cash basis. The Company funds trusts to the
extent deductible under federal income tax regulations or the extent required by
II-228
NOTES (continued)
Mississippi Power Company 2003 Annual Report
the MPSC and the FERC. For the year ended December 31, 2004, postretirement
benefit contributions are expected to total approximately $330,000.
The measurement date for plan assets and obligations is September 30 for
each year. 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.
Pension Plans
The accumulated benefit obligation for the pension plans was $188 million and
$161 million for 2003 and 2002, respectively. Changes during the year in the
projected benefit obligations, accumulated benefit obligations, and fair value
of plan assets were as follows:
Projected
Benefit Obligations
- -------------------------------------------------------------
2003 2002
- -------------------------------------------------------------
(in thousands)
Balance at beginning of year $186,443 $172,167
Service cost 5,607 5,259
Interest cost 11,964 12,674
Benefits paid (9,317) (8,386)
Actuarial loss and employee
transfers 12,992 528
Amendments - 4,200
- -------------------------------------------------------------
Balance at end of year $207,689 $186,442
=============================================================
Plan Assets
------------------------
2003 2002
- -------------------------------------------------------------
(in thousands)
Balance at beginning of year $188,839 $211,546
Actual return on plan assets 30,024 (14,089)
Benefits paid (8,512) (7,875)
Employee transfers (66) (743)
- -------------------------------------------------------------
Balance at end of year $210,285 $188,839
=============================================================
The plan assets are managed and invested in accordance with all applicable
requirements, including ERISA and the Internal Revenue Service (IRS) revenue
code. The Company's investment policy covers a diversified mix of assets,
including equity and fixed income securities, real estate, and private equity,
as described in the table below. Derivative instruments are used primarily as
hedging tools but may also be used to gain efficient exposure to the various
asset classes. The Company primarily minimizes the risk of large losses through
diversification but also monitors and manages other aspects of risk.
Plan Assets
---------------------
Target 2003 2002
- --------------------------------------------------------------
Domestic equity 37% 37% 35%
International equity 20 20 18
Global fixed income 26 24 25
Real estate 10 11 12
Private equity 7 8 10
- --------------------------------------------------------------
Total 100% 100% 100%
==============================================================
The accrued pension costs recognized in the Balance Sheets
were as follows:
2003 2002
- -----------------------------------------------------------------
(in thousands)
Funded status $ 2,596 $ 2,396
Unrecognized transition obligation (1,635) (2,180)
Unrecognized prior service cost 15,004 16,669
Unrecognized net gain (5,507) (9,087)
- ----------------------------------------------------------------
Prepaid pension asset, net 10,458 7,798
Portion included in
benefit obligations 7,709 7,195
- ----------------------------------------------------------------
Total prepaid assets recognized in
the Balance Sheets $18,167 $14,993
================================================================
In 2003 and 2002, amounts recognized in the Balance Sheets for accumulated
other comprehensive income were $2.3 million and $2.0 million, respectively.
Intangible assets recognized were $1.4 million in 2003 and $1.7 million in 2002.
Components of the pension plans' net periodic cost were as follows:
2003 2002 2001
- ---------------------------------------------------------------
(in thousands)
Service cost $ 5,607 $ 5,259 $ 4,797
Interest cost 11,965 12,674 11,818
Expected return on
plan assets (18,329) (18,380) (17,328)
Recognized net gain (1,847) (2,654) (3,012)
Net amortization 862 650 511
- ---------------------------------------------------------------
Net pension income $ (1,742) $ (2,451) $ (3,214)
===============================================================
II-229
NOTES (continued)
Mississippi Power Company 2003 Annual Report
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
-----------------------
2003 2002
-----------------------------------------------------------
(in thousands)
Balance at beginning of year $61,168 $51,523
Service cost 1,149 959
Interest cost 3,897 3,781
Benefits paid (2,813) (3,320)
Actuarial loss and
employee transfers 8,785 8,225
-----------------------------------------------------------
Balance at end of year $72,186 $61,168
===========================================================
Plan Assets
-----------------------
2003 2002
-----------------------------------------------------------
(in thousands)
Balance at beginning of year $16,078 $16,269
Actual return on plan assets 1,979 (516)
Employer contributions 2,941 3,645
Benefits paid (2,813) (3,320)
-----------------------------------------------------------
Balance at end of year $18,185 $16,078
===========================================================
Postretirement benefits plan assets are managed and invested in accordance
with all applicable requirements, including ERISA and the IRS revenue code. The
Company's investment policy covers a diversified mix of assets, including equity
and fixed income securities, real estate, and private equity, as described in
the table below. Derivative instruments are used primarily as hedging tools but
may also be used to gain efficient exposure to the various asset classes. The
Company primarily minimizes the risk of large losses through diversification but
also monitors and manages other aspects of risk.
Plan Assets
-----------------------
Target 2003 2002
- ----------------------------------------------------------------
Domestic equity 27% 27% 24%
International equity 14 14 13
Global fixed income 47 45 47
Real estate 7 8 9
Private equity 5 6 7
- ----------------------------------------------------------------
Total 100% 100% 100%
================================================================
The accrued postretirement costs recognized in the Balance
Sheets were as follows:
Accrued Costs
---------------------
2003 2002
- ----------------------------------------------------------------
(in thousands)
Funded status $(54,001) $(45,090)
Unrecognized transition obligation 3,235 3,582
Unrecognized prior service cost 1,610 1,715
Unrecognized net gain 18,503 10,216
Fourth quarter contributions 926 1,029
- ----------------------------------------------------------------
Accrued liability recognized in the
Balance Sheets $(29,727) $(28,548)
================================================================
Components of the postretirement plans' net periodic cost
were as follows:
Net Periodic Costs
- ----------------------------------------------------------------
2003 2002 2001
- ----------------------------------------------------------------
(in thousands)
Service cost $ 1,149 $ 959 $ 922
Interest cost 3,898 3,781 3,411
Expected return on
plan assets (1,598) (1,514) (1,409)
Transition obligation 346 346 346
Prior service cost 106 106 80
Recognized net loss 116 - (38)
- ----------------------------------------------------------------
Net postretirement cost $ 4,017 $ 3,678 $ 3,312
================================================================
The weighted average rates assumed in the actuarial calculations for both
the pension plan and postretirement benefits plans were as follows:
2003 2002 2001
- ----------------------------------------------------------------
Discount 6.00% 6.50% 7.50%
Annual salary increase 3.75 4.00 5.00
Long-term return on plan assets 8.50 8.50 8.50
- ----------------------------------------------------------------
The Company determined the long-term rate of return on based historical
asset class returns and current market conditions, taking into account the
diversification benefits of investing in multiple asset classes.
An additional assumption used in measuring the accumulated postretirement
benefit obligation was a weighted average medical care cost trend rate of 8.25
percent for 2003, decreasing gradually to 5.25 percent through the year 2010 and
remaining at that level thereafter. An annual increase or decrease in the
II-230
NOTES (continued)
Mississippi Power Company 2003 Annual Report
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,
2003 as follows:
1 Percent 1 Percent
Increase Decrease
- ----------------------------------------------------------------
(in thousands)
Benefit obligation $5,499 $4,863
Service and interest costs 329 290
- ----------------------------------------------------------------
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 2003, 2002, and 2001 were $2.7
million, $2.6 million, and $2.5 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. In addition, 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 against the Company cannot be predicted at this time;
however, management does not anticipate that the liabilities, if any, arising
from such current proceedings would have a material adverse effect on the
Company's financial statements.
New Source Review Actions
In November 1999, the Environmental Protection Agency (EPA) brought a civil
action in the U.S. District Court for the Northern District of Georgia against
Alabama Power, Georgia Power, and SCS. The complaint alleged violations of the
New Source Review (NSR) provisions of the Clean Air Act with respect to five
coal-fired generating facilities in Alabama and Georgia and violations of
related state laws. The civil action requested 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 retail
operating companies notices of violation relating to 10 generating facilities,
which include 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 notices of violation and to add
Gulf Power, the Company, and Savannah Electric as defendants.
In August 2000, the U.S. District Court in Georgia granted Alabama Power's
motion to dismiss for lack of jurisdiction in Georgia and granted SCS' motion to
dismiss on the grounds that it neither owned nor operated the generating units
involved in the proceedings. In March 2001, 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 in Georgia 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. In
addition, the EPA refiled its claims against Alabama Power in the U.S. District
Court for the Northern District of Alabama. These complaints allege violations
with respect to eight coal-fired generating facilities in Alabama and Georgia,
and they request the same kinds of relief as was requested in the original
complaint, i.e. penalties and injunctive relief, including installation of the
best available control technology. The EPA has not refiled against Gulf Power,
the Company, or SCS.
The actions against Alabama Power, Georgia Power, and Savannah Electric
were stayed in the spring of 2001 during the appeal of a very similar NSR
enforcement action against the Tennessee Valley Authority (TVA) before the U.S.
Court of Appeals for the Eleventh Circuit. The TVA appeal involves many of the
same legal issues raised by the actions against Alabama Power, Georgia Power,
and Savannah Electric. Because the final resolution of the TVA appeal could have
a significant impact on Alabama Power and Georgia Power, both companies have
been involved in that appeal. On June 24, 2003, the court of appeals issued its
II-231
NOTES (continued)
Mississippi Power Company 2003 Annual Report
ruling in the TVA case. It found unconstitutional the statutory scheme set forth
in the Clean Air Act that allowed the EPA to impose penalties for failing to
comply with an administrative compliance order, like the one issued to TVA,
without the EPA having to prove the underlying violation. Thus, the court of
appeals held that the compliance order was of no legal consequence, and TVA was
free to ignore it. The court did not, however, rule directly on the substantive
legal issues about the proper interpretation and application of certain NSR
provisions that had been raised in the TVA appeal. On September 16, 2003, the
court of appeals denied the EPA's request for a rehearing of the decision. On
February 13, 2004, the EPA petitioned the U.S. Supreme Court to review the
decision of the court of appeals. The EPA also filed a motion to lift the stay
in the action against Alabama Power. At this time, no party to the Georgia Power
and Savannah Electric action, which was administratively closed two years ago,
has asked the court to reopen that case.
Since the inception of the NSR proceedings against Georgia Power, Alabama
Power, and Savannah Electric, the EPA has also been proceeding with similar NSR
enforcement actions against other utilities, involving many of the same legal
issues. In each case, the EPA alleged that the utilities failed to comply with
the NSR permitting requirements when performing maintenance and construction
activities at coal-burning plants, which activities the utilities considered to
be routine or otherwise not subject to NSR. In 2003, district courts addressing
these cases issued opinions that reached conflicting conclusions.
In October 2003, the EPA issued final revisions to its NSR regulations
under the Clean Air Act clarifying the scope of the existing Routine
Maintenance, Repair, and Replacement exclusion. On December 24, 2003, the U.S.
Court of Appeals for the District of Columbia Circuit stayed the effectiveness
of these revisions pending resolution of related litigation. In January 2004,
the Bush Administration announced that it would continue to enforce the existing
rules.
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. 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.
Right of Way Litigation
Southern Company and certain of its subsidiaries, including the Company, Georgia
Power, Gulf Power, and Southern Telecom (collectively, defendants), have been
named as defendants in numerous lawsuits brought by landowners since 2001
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
Company has complied with the applicable laws and 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.
In addition, in late 2001, certain subsidiaries of Southern Company,
including Alabama Power, Georgia Power, Gulf Power, the Company, Savannah
Electric, and Southern Telecom (collectively, defendants), were named as
defendants in a lawsuit brought by a telecommunications company that uses
certain of the defendants' rights of way. This lawsuit alleges, among other
things, that the defendants are contractually obligated to indemnify, defend,
and hold harmless the telecommunications company from any liability that may be
assessed against the telecommunications company in pending and future right of
way litigation. The Company believes that the plaintiff's claims are without
merit. An adverse outcome in this matter, combined with an adverse outcome
against the telecommunications company in one or more of the right of way
lawsuits, could result in substantial judgments; however, the final outcome of
these matters cannot now be determined.
II-232
NOTES (continued)
Mississippi Power Company 2003 Annual Report
Contract Termination
On May 21, 2003, the Company entered into an agreement with Dynegy to resolve
all outstanding matters related to a capacity sales contract with a subsidiary
of Dynegy. Under the terms of the agreement, Dynegy made a cash payment of $75
million to the Company. The contract between the Company and Dynegy was
terminated effective October 31, 2003. The termination payment from Dynegy
resulted in the Company recognizing a gain of $38 million after tax.
Retail Regulatory Filing
The Company's retail base rates are set under Performance Evaluation Plan (PEP),
a rate plan originally approved in 1986 and modified from time to time since its
inception. See "2001 Retail Rate Case" for further information on the 2002
modification. PEP was designed with the objective that PEP would reduce the
impact of rate changes on the customer and provide incentives for the Company to
keep customer prices low and customer satisfaction and reliability high. PEP is
a mechanism for rate adjustments based on three indicators: the Company's
ability to maintain low rates for customers, and the Company's performance as
measured by two additional indicators that emphasize customer satisfaction and
providing reliable 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 two percent of retail revenues per evaluation period. PEP
will remain in effect until the MPSC modifies, suspends, or terminates the plan.
On December 5, 2003, the Company filed a request with the MPSC to
include 266 megawatts of Plant Daniel Units 3 and 4 generating capacity not
currently included in jurisdictional cost of service. See "2001 Retail Rate
Case" for further information on the current cost allocation for this capacity.
In addition, the Company proposed to modify certain provisions of PEP. The
proposed changes include (1) the use of a forward-looking, rather than a
historical, test year, (2) adjustments to the performance indicator mechanism,
and (3) an annual, rather than semi-annual, evaluation period.
As part of the Company's proposal to include the additional Plant Daniel
capacity in retail rates, the MPSC issued an interim accounting order in
December 2003 directing the Company to expense and record in 2003 a regulatory
liability in the amount of approximately $60 million while the MPSC fully
considers the entire request. However, if the MPSC ultimately denies the
Company's request, the regulatory liability will be required to be reversed.
The Company expects the MPSC to render a final order in the second
quarter of 2004 on the inclusion of the additional Plant Daniel capacity in
rates, the amortization period for the regulatory liability, and the requested
changes to PEP.
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 two percent of retail revenues. However, the ECO Plan
also provides for carryover of any amount over the two 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 2004 ECO Plan in
January 2004, which, if approved as filed, will result in a slight decrease in
customer prices.
2001 Retail Rate Case
In December 2001, the MPSC approved an annual retail rate increase of
approximately $39 million, which took effect in January 2002. In October 2000,
the MPSC approved a cost allocation that allocated a pro-rata share of the Plant
Daniel Units 3 and 4 leased capacity, along with the Company's existing
generation, to the retail jurisdiction. The MPSC's December 2001 order approved
these cost allocations.
II-233
NOTES (continued)
Mississippi Power Company 2003 Annual Report
Additionally, the MPSC ordered the Company to reactivate semi-annual
evaluations under PEP, beginning with the 12-month period ending December 31,
2002. In May 2002, the MPSC issued an order adopting new return on equity models
to be used in the PEP process that are very similar to those that established
the $39 million rate increase.
Potentially Responsible Party Status
In 2003, the Texas Commission on Environmental Quality (TCEQ) designated the
Company as a potentially responsible party in connection with the cleanup of a
site in Texas owned by a company that performed rebuilds and scrapping on
electric transformers for the Company and many other utilities. The site owner
is now in bankruptcy and the State of Texas has entered into an agreement with
the Company and several other utilities to perform off-site removal of
polychlorinated biphenyl (PCB) contaminated soil. Amounts expensed during 2003
related to this work were not material. Hundreds of entities have received
notices from the TCEQ requesting their participation in the anticipated site
remediation. The final outcome of this matter to the Company will depend upon
further environmental assessment and the ultimate number of potentially
responsible parties and cannot now be determined.
FERC Matters
Market-Based Rate Authority
The Company has obtained FERC approval to sell power to nonaffiliates at
market-based prices under specific contracts. Through SCS, as agent , the
Company also has FERC authority to make short-term opportunity sales at market
rates. Specific FERC approval must be obtained with respect to a market-based
contract with an affiliate. In November 2001, the FERC modified the test it uses
to consider utilities' applications to charge market-based rates and adopted a
new test called the Supply Margin Assessment (SMA). The FERC applied the SMA to
several utilities, including Southern Company's retail operating companies, and
found them and others to be "pivotal suppliers" in their service areas and
ordered the implementation of several mitigation measures. SCS, on behalf of the
Company and the other retail operating companies sought rehearing of the FERC
order, and the FERC delayed the implementation of certain mitigation measures.
SCS, on behalf of the Company and the other retail operating companies,
submitted comments to the FERC in 2002 regarding these issues. In December 2003,
the FERC issued a staff paper discussing alternatives and held a technical
conference in January 2004. The Company anticipates that the FERC will address
the requests for rehearing in the near future. The final outcome of this matter
will depend on the form in which the SMA test and mitigation measures rules may
be ultimately adopted and cannot be determined at this time.
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 ECM and the cost allocation of
Plant Daniel Units 3 and 4, similar to the plans approved by the Company's
retail jurisdiction.
Transmission Facilities Agreement
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, yields an
overall just and reasonable rate. In July 2003, the FERC approved a settlement
between the Company and the FERC staff. The impact of the settlement provides
for no refund of prior revenues collected and a minimal change in revenues
effective in 2004.
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.
II-234
At December 31, 2003, 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% $ 68,504 $ 36,733
Daniel
Units 1 and 2 1,000 50% $240,032 $116,815
-------------------------------------------------------------
The Company's proportionate share of plant operating expenses is included in
the Statements of Income.
5. INCOME TAXES
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 IRS regulations, each company is jointly and severally liable
for the tax liability.
At December 31, 2003, the tax-related regulatory assets and liabilities
were $12 million and $23 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.
Details of the federal and state income tax provisions are shown below:
2003 2002 2001
-----------------------------------------------------------------
(in thousands)
Total provision for income taxes:
Federal --
Current $46,116 $42,603 $43,596
Deferred (6,166) (3,122) (8,661)
39,950 39,481 34,935
-----------------------------------------------------------------
State --
Current 7,761 6,680 6,698
Deferred (2,396) (282) (1,057)
-----------------------------------------------------------------
5,365 6,398 5,641
-----------------------------------------------------------------
Total $45,315 $45,879 $40,576
=================================================================
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:
2003 2002
----------------------------------------------------------------
(in thousands)
Deferred tax liabilities:
Accelerated depreciation $168,373 $157,087
Basis differences 7,487 7,791
Other 46,689 38,005
----------------------------------------------------------------
Total 222,549 202,883
----------------------------------------------------------------
Deferred tax assets:
Other property
basis differences 15,067 14,501
Pension and
other benefits 10,722 9,546
Property insurance 2,599 1,942
Unbilled fuel 5,593 6,048
Other 68,257 42,891
----------------------------------------------------------------
Total 102,238 74,928
----------------------------------------------------------------
Total deferred tax
liabilities, net 120,311 127,955
Portion included in prepaid expenses
(accrued income taxes), net 21,777 18,675
----------------------------------------------------------------
Accumulated deferred
income taxes in the
Balance Sheets $142,088 $146,630
=================================================================
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 each of 2003, 2002, and 2001. At December 31, 2003,
II-235
NOTES (continued)
Mississippi Power Company 2003 Annual Report
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, as a result of the following:
2003 2002 2001
-------------------------------------------------------------
Federal statutory rate 35.0% 35.0% 35.0%
State income tax, net of
federal deduction 2.9 3.4 3.4
Non-deductible book
Depreciation .4 0.5 0.5
Other (0.8) (1.0) (0.8)
--------------------------------------------------- ---------
Effective income tax rate 37.5% 37.9% 38.1%
=============================================================
6. CAPITALIZATION
Mandatorily Redeemable Preferred Securities
The Company has formed a certain wholly owned trust subsidiary for the purpose
of issuing preferred securities. The proceeds of the related equity investment
and preferred security sale were loaned back to the Company through the issuance
of junior subordinated notes totaling $36 million, which constitute
substantially all assets of the trust. The Company considers that the mechanisms
and obligations relating to the preferred securities issued for its benefit,
taken together, constitute a full and unconditional guarantee by it of the
trust's payment obligations with respect to these securities. At December 31,
2003, preferred securities of $35 million were outstanding and recognized as
liabilities in the Balance Sheets.
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, 2003 was
$82.7 million.
Long-Term Debt Due Within One Year
A summary of the improvement fund requirements and scheduled maturities and
redemptions of long-term debt due within one year at December 31 is as follows:
2003 2002
---------------------------------------------------------------
(in thousands)
Bond improvement fund requirement $ 300 $ 634
Less: Portion to be satisfied by
certifying property additions 300 634
---------------------------------------------------------------
Cash sinking fund requirement - -
Current portion of other long-term debt 80,000 68,350
Pollution control bond cash
sinking fund requirements - 850
---------------------------------------------------------------
Total $80,000 $69,200
==============================================================-
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 1 and 2/3 times such requirement.
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 revenue
bonds, originally due in 2007.
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.
Bank Credit Arrangements
At the beginning of 2004, the Company had total committed credit agreements with
banks for approximately $100 million, all of which was unused. These credit
agreements expire in 2004. Some of these agreements allow short-term borrowings
to be converted into term loans, payable in eight 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.
II-236
NOTES (continued)
Mississippi Power Company 2003 Annual Report
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 $100 million in unused credit arrangements provides required liquidity
support to the Company's borrowings through a commercial paper program. The
Company has $60 million available to support its commercial paper program. At
December 31, 2003, the Company had no outstanding commercial paper or extendible
commercial notes. During 2003, the peak amount outstanding for commercial paper
was $33 million and the average amount outstanding was $4.2 million. The average
annual interest rate on commercial paper was 1.3 percent in 2003. The credit
arrangements also provide support to the Company's variable daily rate pollution
control bonds.
Financial Instruments
The Company enters into energy-related derivatives to hedge exposures to
electricity, natural gas, and other fuel price changes. However, due to
cost-based rate regulations, the Company has limited exposure to market
volatility in commodity fuel prices and prices of electricity. The Company has
implemented fuel-hedging programs at the instruction of the MPSC. The Company
enters into hedges of forward electricity sales.
At December 31, 2003, the fair value of derivative energy contracts was
reflected in the financial statements as follows:
Amounts
------------------------------------------------------------
(in thousands)
Regulatory liabilities, net $ 2,468
Net income 2
------------------------------------------------------------
Total fair value $ 2,470
============================================================
The fair value gains or losses for cash flow hedges that are recoverable
through the regulatory fuel clauses are recorded as regulatory assets and
liabilities and are recognized in earnings at the same time the hedged items
affect earnings.
Dividend Restrictions
The Company's first mortgage bond indenture and the corporate charter contain
various common stock dividend restrictions. At December 31, 2003, 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.
In accordance with the PUHCA, the Company is also restricted from paying
common dividends from paid-in capital without SEC approval.
7. COMMITMENTS
Construction Program
The Company is engaged in continuous construction programs, currently estimated
to total $80 million in 2004, $70 million in 2005, and $98 million in 2006. 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; changes in FERC rules
and transmission regulations; increasing costs of labor, equipment and
materials; and cost of capital. At December 31, 2003, significant purchase
commitments were outstanding in connection with the construction program. The
Company has no generating plants under construction. Capital improvements to
generating, transmission and distribution facilities -- including those to meet
environmental standards -- will continue.
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.
II-237
NOTES (continued)
Mississippi Power Company 2003 Annual Report
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 expense based on actual hours
of operation. The Company has recognized $6 and $11 million for 2003 and 2002,
respectively, which is included in maintenance expense on the Statements of
Income. Remaining payments to GE under this agreement are currently estimated to
total $174 million over the next 17 years. However, the LTSA contains various
cancellation provisions at the option of the Company.
The Company also has entered into a LTSA with ABB Power Generation Inc.
(ABB) for the purpose of securing maintenance support for its Chevron Unit 5
combustion turbine plant. In summary, the LTSA stipulates that ABB will perform
all planned maintenance on the covered equipment, which includes the cost of all
labor and materials. ABB is also obligated to cover the costs of unplanned
maintenance on the covered equipment subject to a limit specified in the
contract.
In general, this LTSA is in effect through two major inspection cycles.
Scheduled payments to ABB are made at various intervals based on actual
operating hours of the unit. Payments to ABB under this agreement are currently
estimated to total $6.8 million over the remaining life of the agreement, which
is approximately 4 years. However, the LTSA contains various cancellation
provisions at the option of the Company. Payments made to ABB 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.
Fuel and Purchased Power Commitments
To supply a portion of the fuel requirements of the 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 purchase levels, and other financial commitments. Natural gas purchase
commitments contain given volumes with prices based on various indices at the
time of delivery. Amounts included in the chart below represent estimates based
on New York Mercantile future prices at December 31, 2003. Total estimated
minimum long-term obligations at December 31, 2003 were as follows:
Natural
Year Gas Coal
--------------------------------------------------
(in millions)
2004 $140 $174
2005 83 86
2006 67 65
2007 45 21
2008 6 -
2009 and there after 54 -
- ---------------------------------------------------
Total commitments $395 $346
===================================================
Additional commitments for fuel will be required to supply the Company's
future needs.
SCS may enter into various types of wholesale energy and natural gas
contracts acting as an agent for the Company and all of the other Southern
Company retail operating companies, Southern Power, and Southern Company GAS.
Under these agreements, each of the retail operating companies, Southern Power,
and Southern Company GAS may be jointly and severally liable. The
creditworthiness of Southern Power and Southern Company GAS is currently
inferior to the creditworthiness of the retail operating companies. Accordingly,
Southern Company has entered into keep-well agreements with the Company and each
of the other 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 Company GAS as a contracting party under
these agreements.
Operating Leases
Railcar Leases
In 1989, the Company and Gulf 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 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 are for
the transport of coal to Plant Daniel.
II-238
NOTES (continued)
Mississippi Power Company 2003 Annual Report
Gulf Power, as joint owner of Plant Daniel Units 1 and 2, is responsible
for one half of the lease costs. 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 2003, $1.9 million in 2002, and $1.9 million in 2001. The
Company's annual lease payments for 2004 through 2008 will average
approximately $2 million and after 2008, lease payments total in aggregate
approximately $8 million.
Plant Daniel Combined Cycle Generating Units
In May 2001, the Company began the initial 10-year term of the lease agreement
signed in 1999 for a 1,064 megawatt natural gas combined cycle generating
facility built at Plant Daniel (Facility). The Company entered into this
transaction during a period when retail access was under review by the MPSC. 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
Regulatory Filing" for a description of the Company's PEP formula rate plan.
In 2003, the Facility was acquired by Juniper Capital L.P. (Juniper), whose
partners are unaffiliated with the Company. Simultaneously, Juniper entered into
a restructured lease agreement with the Company. Juniper has also entered into
leases with other parties unrelated to the Company. The assets leased by the
Company comprise less than 50 percent of Juniper's assets. In accordance with
FASB Interpretation No. 46, the Company is not required to consolidate the
leased assets and related liabilities, and the lease with Juniper is considered
an operating lease under FASB Statement No. 13. The lease agreement 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. The initial lease term ends in 2011 and the lease includes a
purchase and renewal option based on the cost of the Facility at the inception
of the lease, which was $369 million. The Company is required to amortize
approximately four percent of the initial acquisition cost over the initial
lease term. Eighteen months prior to the end of the initial lease, the Company
may elect to renew for 10 years. If the lease is renewed, 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, it may either exercise its purchase option or the Facility can be sold
to a third party.
The lease provides for a residual value guarantee -- approximately 73
percent of the acquisition cost -- by the Company that is due upon termination
of the lease in the event that the Company does not renew the lease or purchase
the Facility and that the fair market value is less than the unamortized cost of
the Facility. The Company has recognized in the Balance Sheets a liability of
approximately $15 million for the fair market value of this residual value
guarantee. In 2003, approximately $11 million in lease termination costs and $26
million in lease expense were included in other operation expense. The amount of
future minimum operating lease payments will be approximately $29 million
annually during the initial term.
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, 2003, are as follows:
Year Lease Payments
- -------------------------------------------------------------
(in millions)
2004 $29
2005 29
2006 29
2007 29
2008 28
2009 and thereafter 85
- -------------------------------------------------------------
Total commitments $229
=============================================================
II-239
NOTES (continued)
Mississippi Power Company 2003 Annual Report
8. QUARTERLY FINANCIAL INFORMATION
(UNAUDITED)
Summarized quarterly financial data for 2003 and 2002 are as follows:
Net Income
After Dividends
Operating Operating On Preferred
Quarter Ended Revenues Income Stock
- ------------------------------------------------------------------
(in thousands)
March 2003 $193,886 $39,750 $21,396
June 2003 264,360 90,386 53,059
September 2003 227,814 58,317 34,387
December 2003 183,864 (50,786) (35,343)
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
- ------------------------------------------------------------------
The Company's business is influenced by seasonal weather conditions and the
timing of rate changes.
II-240
SELECTED FINANCIAL AND OPERATING DATA 1999-2003
Mississippi Power Company 2003 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------------
2003 2002 2001 2000 1999
- -----------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands) $869,924 $824,165 $796,065 $687,602 $633,004
Net Income after Dividends
on Preferred Stock (in thousands) $73,499 $73,013 $63,887 $54,972 $54,809
Cash Dividends
on Common Stock (in thousands) $66,000 $63,500 $50,200 $54,700 $56,100
Return on Average Common Equity (percent) 13.99 14.46 14.25 13.80 14.00
Total Assets (in thousands) $1,518,384 $1,482,040 $1,411,050 $1,341,470 $1,317,297
Gross Property Additions (in thousands) $69,345 $67,460 $61,193 $81,211 $75,888
- -----------------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $532,489 $517,953 $491,680 $404,898 $391,968
Preferred stock 31,809 31,809 31,809 31,809 31,809
Mandatorily redeemable preferred securities 35,000 35,000 35,000 35,000 35,000
Long-term debt 202,488 243,715 233,753 370,511 321,802
- -----------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $801,786 $828,477 $792,242 $842,218 $780,579
===================================================================================================================================
Capitalization Ratios (percent):
Common stock equity 66.4 62.5 62.1 48.1 50.2
Preferred stock 4.0 3.8 4.0 3.8 4.1
Mandatorily redeemable preferred securities 4.4 4.2 4.4 4.2 4.5
Long-term debt 25.2 29.5 29.5 43.9 41.2
- -----------------------------------------------------------------------------------------------------------------------------------
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+ A+ AA-
Fitch AA- AA- AA- AA- AA-
Preferred Stock -
Moody's A3 A3 A3 a1 a1
Standard and Poor's BBB+ BBB+ BBB+ BBB+ A-
Fitch A A A A A
Unsecured Long-Term Debt -
Moody's A1 A1 A1 - -
Standard and Poor's A A A - -
Fitch A+ A+ A+ - -
===================================================================================================================================
Customers (year-end):
Residential 159,582 158,873 158,852 158,253 157,592
Commercial 33,135 32,713 32,538 32,372 31,837
Industrial 520 489 498 517 546
Other 171 171 173 206 202
- -----------------------------------------------------------------------------------------------------------------------------------
Total 193,408 192,246 192,061 191,348 190,177
===================================================================================================================================
Employees (year-end): 1,290 1,301 1,316 1,319 1,328
- -----------------------------------------------------------------------------------------------------------------------------------
II-241
SELECTED FINANCIAL AND OPERATING DATA 1999-2003 (continued)
Mississippi Power Company 2003 Annual Report
- --------------------------------------------------------------------------------------------------------------------------------
2003 2002 2001 2000 1999
- --------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $180,978 $186,522 $164,716 $170,729 $159,945
Commercial 175,416 181,224 163,253 163,552 153,936
Industrial 154,825 164,042 156,525 159,705 151,244
Other 5,082 5,039 4,659 4,565 4,309
- --------------------------------------------------------------------------------------------------------------------------------
Total retail 516,301 536,827 489,153 498,551 469,434
Sales for resale - non-affiliates 249,986 224,275 204,623 145,931 131,004
Sales for resale - affiliates 26,723 46,314 85,652 27,915 19,446
- --------------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 793,010 807,416 779,428 672,397 619,884
Other revenues 76,914 16,749 16,637 15,205 13,120
- --------------------------------------------------------------------------------------------------------------------------------
Total $869,924 $824,165 $796,065 $687,602 $633,004
================================================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 2,255,445 2,300,017 2,162,623 2,286,143 2,248,255
Commercial 2,914,133 2,902,291 2,840,840 2,883,197 2,847,342
Industrial 4,111,199 4,161,902 4,275,781 4,376,171 4,407,445
Other 39,890 39,635 41,009 41,153 40,091
- --------------------------------------------------------------------------------------------------------------------------------
Total retail 9,320,667 9,403,845 9,320,253 9,586,664 9,543,133
Sales for resale - non-affiliates 5,874,724 5,380,145 5,011,212 3,674,621 3,256,175
Sales for resale - affiliates 709,065 1,586,968 2,952,455 452,611 539,939
- --------------------------------------------------------------------------------------------------------------------------------
Total 15,904,456 16,370,958 17,283,920 13,713,896 13,339,247
================================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 8.02 8.11 7.62 7.47 7.11
Commercial 6.02 6.24 5.75 5.67 5.41
Industrial 3.77 3.94 3.66 3.65 3.43
Total retail 5.54 5.71 5.25 5.20 4.92
Sales for resale 4.20 3.88 3.64 4.21 3.96
Total sales 4.99 4.93 4.51 4.90 4.65
Residential Average Annual
Kilowatt-Hour Use Per Customer 14,160 14,453 13,634 14,445 14,301
Residential Average Annual
Revenue Per Customer $1,136.27 $1,172.12 $1,038.41 $1,078.76 $1,017.42
Plant Nameplate Capacity
Ratings (year-end) (megawatts) 3,156 3,156 3,156 2,086 2,086
Maximum Peak-Hour Demand (megawatts):
Winter 2,458 2,311 2,249 2,305 2,125
Summer 2,330 2,492 2,466 2,593 2,439
Annual Load Factor (percent) 60.5 61.8 60.7 59.3 59.6
Plant Availability Fossil-Steam (percent): 92.6 91.7 92.8 92.6 91.0
- --------------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 57.7 50.8 52.0 67.8 69.4
Oil and gas 19.9 37.7 35.9 13.5 15.9
Purchased power -
From non-affiliates 3.5 3.1 3.1 7.7 6.2
From affiliates 18.9 8.4 9.0 11.0 8.5
- --------------------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0 100.0 100.0
================================================================================================================================
II-242
SAVANNAH ELECTRIC AND POWER COMPANY
FINANCIAL SECTION
II-243
MANAGEMENT'S REPORT
Savannah Electric and Power Company 2003 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 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 internal accounting controls are 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
four independent directors, provides a broad overview of management's financial
reporting and control functions. Additionally, the Controls and Compliance
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
March 1, 2004
II-244
INDEPENDENT AUDITORS' REPORT
Savannah Electric and Power Company:
We have audited the accompanying balance sheets and statements of capitalization
of Savannah Electric and Power Company (a wholly owned subsidiary of Southern
Company) as of December 31, 2003 and 2002, and the related statements of income,
comprehensive income, common stockholder's equity, and cash flows for the years
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 audits. The financial
statements of Savannah Electric and Power Company for the year ended December
31, 2001 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 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, the financial statements (pages II-261 to II-281) present
fairly, in all material respects, the financial position of Savannah Electric
and Power Company at December 31, 2003 and 2002, and the results of its
operations and its cash flows for the years then ended in conformity with
accounting principles generally accepted in the United States of America.
As discussed in Note 1 to the financial statements, in 2003 Savannah
Electric and Power Company changed its method of accounting for asset retirement
obligations.
/s/Deloitte & Touche LLP
Atlanta, Georgia
March 1, 2004
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(f)2 FOR
ADDITIONAL INFORMATION.
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-245
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND
FINANCIAL CONDITION
Savannah Electric and Power Company 2003 Annual Report
OVERVIEW OF EARNINGS AND BUSINESS
- ---------------------------------
ACTIVITIES
- ----------
Earnings
Savannah Electric and Power Company's net income for 2003 totaled $22.8 million,
remaining stable from the prior year. Higher operating expenses and income taxes
were generally offset by higher operating revenues, lower depreciation and
amortization expenses, and lower interest expenses.
Earnings were $22.9 million in 2002, representing an increase of $0.8
million or 3.7 percent from the prior year. Earnings were up in 2002 primarily
due to higher retail revenues, somewhat offset by higher operating expenses. In
2001, earnings were $22.1 million, representing a decrease of $0.9 million or
3.9 percent from the prior year. Earnings in 2001 were down primarily due to
lower retail revenues.
Business Activities
The Company operates as a vertically integrated utility providing electricity to
retail customers within its traditional service area of southeastern Georgia.
Several factors affect the opportunities, challenges, and risk of selling
electricity. These factors include the Company's ability to maintain a stable
regulatory environment, to achieve energy sales growth while containing costs,
and to recover costs related to growing demand and increasingly stricter
environmental standards. 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 price of electricity, the price elasticity of demand, and the
rate of economic growth in the Company's service area.
RESULTS OF OPERATIONS
- ---------------------
A condensed income statement is as follows:
Increase (Decrease)
Amount From Prior Year
- ----------------------------------------------------------------
2003 2003 2002 2001
- ----------------------------------------------------------------
(in thousands)
Operating revenues $314,055 $14,503 $15,700 $(11,866)
- ----------------------------------------------------------------
Fuel 55,308 353 4,159 (6,381)
Purchased power 89,505 13,901 2,518 (2,254)
Other operation
and maintenance 83,621 2,603 10,525 (1,927)
Depreciation
and amortization 20,499 (2,205) (3,247) 711
Taxes other than
income taxes 14,665 208 473 868
- ------------------------------------------------------ ---------
Total operating
Expenses 263,598 14,860 14,428 (8,983)
- ----------------------------------------------------------------
Operating income 50,457 (357) 1,272 (2,883)
Other income
(expense), net (12,542) 2,959 247 134
Less --
Income taxes 15,108 2,675 702 (1,843)
- ----------------------------------------------------------------
Net Income $ 22,807 $ (73) $ 817 $ (906)
================================================================
Revenues
Total operating revenues for 2003 were $314.1 million, reflecting a 4.8 percent
increase when compared to 2002. The following table summarizes the factors
affecting operating revenues for the past three years:
Amount
- -------------------------------------------------------------------
2003 2002 2001
- -------------------------------------------------------------------
(in thousands)
Retail - prior year $285,771 $269,172 $282,622
Change in --
Base rates 2,799 5,101 -
Sales growth (1,524) 8,729 (1,541)
Weather (263) 2,397 (427)
Fuel cost recovery
and other 10,962 372 (11,482)
- -------------------------------------------------------------------
Retail - current year 297,745 285,771 269,172
- -------------------------------------------------------------------
Sales for resale --
Non-affiliates 5,653 6,354 8,884
Affiliates 6,499 4,075 3,205
- -------------------------------------------------------------------
Total sales for resale 12,152 10,429 12,089
- -------------------------------------------------------------------
Other operating revenues 4,158 3,352 2,591
- -------------------------------------------------------------------
Total operating revenues $314,055 $299,552 $283,852
===================================================================
Percent change 4.8% 5.5% (4.0)%
- -------------------------------------------------------------------
II-246
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 2003 Annual Report
Retail revenues increased 4.2 percent or $12.0 million in 2003, increased
$16.6 million in 2002, and declined $13.5 million in 2001. 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. At the time, the GPSC-approved FCR anticipated
a three year recovery of the under-recovered fuel balance. However, due to
decreasing fuel costs in late 2001 and early 2002, the Company fully recovered
the balance by March 2002 and, in May 2002, the GPSC 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 non-affiliated utilities are primarily energy
related. These sales do not have a significant impact on net income since the
energy is generally sold at variable cost.
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 since the energy is
generally sold at variable cost.
Energy Sales
Changes in revenues are influenced heavily by the amount of energy sold each
year. Kilowatt-hour (KWH) sales for 2003 and the percent change by year were as
follows:
KWH Percent Change
----------- --------------------------
2003 2003 2002 2001
----------- -------------------------
(in millions)
Residential 1,738 (3.1)% 8.1% (0.7)%
Commercial 1,451 (1.8) 6.4 1.4
Industrial 860 8.5 0.7 (1.6)
Other 138 (2.6) 4.4 (1.4)
-----------
Total retail 4,187 (0.4) 5.9 (0.2)
Sales for resale --
Non-affiliates 162 7.7 35.7 43.4
Affiliates 185 47.1 43.4 (1.0)
-----------
Total 4,534 1.2% 7.5% 0.6%
===============================================================
In 2003, residential and commercial energy sales decreased from the prior
year primarily due to weather-related demand. Industrial sales were higher
because of an increase in usage by several industrial customers, reflecting the
beginning of an economic recovery from the previous two year slowdown. All three
categories benefited from a continued increase in the number of customers
served.
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, and
were 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.
Energy sales to retail customers are projected to increase at a compound
average growth rate of 2.1 percent during the period 2004 through 2014.
Expenses
Fuel and purchased power costs constitute the single largest expense for the
Company. The mix of energy supply is determined primarily by demand, the unit
cost of fuel consumed, and the availability and cost of generating units.
II-247
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 2003 Annual Report
The amount and sources of generation, the average cost of fuel per net KWH
generated, and the amount and average cost of purchased power were as follows:
2003 2002 2001
--------------------------
Total generation
(millions of KWHs) 2,325 2,249 2,350
Sources of generation
(percent) --
Coal 94 91 93
Oil 2 1 1
Gas 4 8 6
Average cost of fuel per net
KWH generated (cents) 2.38 2.44 2.16
Total purchased power
(millions of KWHs) 2,581 2,379 1,960
Average cost of purchased
power per net KWH (cents) 3.47 3.18 3.73
- -----------------------------------------------------------------
Fuel expense increased 0.6 percent due to a slight increase in generation
offset somewhat by a lower cost of coal in 2003. In 2002, fuel expense increased
8.2 percent due to increased gas usage and a higher cost of coal. In 2001, fuel
expense decreased 11.2 percent due to a decrease in generation and a slightly
lower average cost of fuel.
Purchased power expense increased $13.9 million or 18.4 percent in 2003 due
to increased energy demands and a purchased power agreement between the Company
and Southern Power for energy and capacity from Plant Wansley Units 6 and 7
which began in June 2002. Purchased power from non-affiliates decreased 72.5
percent and from affiliates increased 38.6 percent in 2002 due principally to
the Plant Wansley purchased power agreement discussed above. Purchased power
expense decreased 3.0 percent in 2001 from the prior year primarily due to lower
fuel prices. Purchased power from affiliates also included energy purchases
which will vary depending on demand and cost of generation resources at each
company. These energy costs are recovered through the fuel cost recovery clause
and have no significant impact on earnings.
In 2003, other operation and maintenance expenses increased 3.2 percent.
Administrative and general expenses increased by $1.0 million primarily due to
increases in accounting and auditing services, insurance reserves, and employee
benefits expense, somewhat offset by 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 $1.5 million primarily
due to a scheduled turbine maintenance outage at Plant Kraft and higher
transmission and distribution maintenance expenses.
In 2002, other operation and maintenance expenses increased 14.9 percent.
Other operation expense was higher reflecting increased distribution expenses of
$0.6 million, increased administrative and general costs of $3.7 million, and
$0.5 million 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, legal, accounting and
auditing services, 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
in 2002 increased over 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 a decrease in 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.
Depreciation and amortization decreased 9.7 percent in 2003 and 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 GPSC rate order. Depreciation and amortization
increased over the prior year by 2.8 percent in 2001 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 2003 primarily as a result of a lower
principal amount of debt outstanding during the year. Lower interest rates in
2003, 2002, and 2001 also contributed to lower expenses in those years.
II-248
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 2003 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 operations for the past three years are not necessarily
indicative of future earnings potential. The level of future earnings depends on
numerous factors. These factors affect the opportunities, challenges, and risk
of electricity. These factors include the Company's ability to maintain a stable
regulatory environment, to achieve energy sales growth while containing costs,
and to recover costs related to growing demand and increasingly stricter
environmental standards. 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 price of electricity, the price elasticity of demand, and the
rate of economic growth in the Company's service area.
Industry Restructuring
The Company operates as a vertically integrated utility providing electricity to
retail customers within the traditional service area of southeastern Georgia.
Prices for electricity provided by the Company to retail customers are set by
the GPSC under cost-based regulatory principles. 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). 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.
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
allowed independent power producers to access a utility's transmission network
and sell electricity to other utilities.
Although the Energy Act does not provide for retail customer access, it was
a major catalyst for 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 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, as well as the August 2003 power outage in
the Northeast. 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.
Since 2001, merchant energy companies and traditional electric utilities
with significant energy marketing and trading activities have come 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 adverse financial impact regarding its limited energy trading
operations through Southern Company Services (SCS).
Continuing to be a low-cost producer could provide opportunities to
increase the size and profitability of the electricity sales business in markets
II-249
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 2003 Annual Report
that evolve with changing regulation and competition. Conversely, future
regulatory changes could adversely affect the Company's growth, and 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.
Environmental Matters
New Source Review Actions
In November 1999, the Environmental Protection Agency (EPA) brought a civil
action against Alabama Power, Georgia Power, and SCS. The EPA later amended its
complaints to add the Company as a defendant alleging violations of the New
Source Review (NSR) provisions of the Clean Air Act with respect to eight
coal-fired generating facilities in Alabama and Georgia, including the Company's
Plant Kraft. The civil actions request penalties and injunctive relief,
including an order requiring the installation of the best available control
technology at the affected units. The actions against Alabama Power, Georgia
Power, and the Company have been stayed since the spring of 2001 during the
appeal of a very similar NSR action against the Tennessee Valley Authority
before the U.S. Court of Appeals for the Eleventh Circuit. The Eleventh Circuit
appeal was decided on September 16, 2003 and, on February 13, 2004, the EPA
petitioned the U.S. Supreme Court to review the Eleventh Circuit's decision. The
EPA also filed a motion to lift the stay in the action against Alabama Power. At
this time, no party to the Georgia Power and Savannah Electric action, which was
administratively closed two years ago, has asked the court to reopen that case.
See Note 3 to the financial statements under "New Source Review Actions" for
additional information.
In December 2002 and October 2003, the EPA issued final revisions to its
NSR regulations under the Clean Air Act. The December 2002 revisions included
changes to the regulatory exclusions and the methods of calculating emissions
increases. The October 2003 regulations clarified the scope of the existing
Routine Maintenance, Repair, and Replacement exclusion. A coalition of states
and environmental organizations filed petitions for review of these revisions
with the U.S. Court of Appeals for the District of Columbia Circuit. On December
24, 2003, the court of appeals granted a stay of the October 2003 revisions
pending its review of the rules and ordered that its review be conducted on an
expedited basis. In January 2004, the Bush Administration announced that it
would continue to enforce the existing rules until the courts resolve legal
challenges to the EPA's revised NSR regulations. In any event, the final
regulations must be adopted by the State of Georgia in order to apply to the
Company's facilities. The effect of these final regulations and the related
legal challenges cannot be determined 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 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 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
- -- both capital and operating -- a major portion of which is expected to be
recovered through existing ratemaking provisions. Environmental costs that are
known and estimable at this time are included in capital expenditures discussed
under "Capital Requirements and Contractual Obligations." 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. Title IV compliance
was effective in 2000 and associated construction expenditures totaled
approximately $2 million.
To help ozone nonattainment areas attain the one-hour ozone standard, in
1998 the EPA issued regional nitrogen oxide reduction rules. Those rules
II-250
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 2003 Annual Report
required 21 states, including Georgia, to reduce and cap nitrogen oxide
emissions from power plants and other large industrial sources. As a result of
litigation challenging the rule, the courts required the EPA to complete a
separate rulemaking before the requirements can be applied in Georgia. The final
EPA rules have not been issued in Georgia. The impact of this rule on the
Company will depend on the form in which it is finalized and cannot be
determined at this time.
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
eight-hour ozone standard unlawful and remanded it to the EPA for further
rulemaking. During 2003, the EPA proposed implementation rules designed to
address the court's concerns. The EPA plans to designate areas as attainment or
nonattainment with the new eight-hour ozone standard in April 2004 and with the
new fine particulate matter standard by the end of 2004. These designations will
be 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 these
standards. State implementation plans (SIPs), including new emission control
regulations necessary to bring those areas into attainment, could be required as
early as 2007. These SIPs could require reductions in sulfur dioxide emissions
and 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 and cannot be determined at this time.
In January 2004, the EPA issued a proposed Interstate Air Quality Rule to
address interstate transport of ozone and fine particles. This proposed rule
would require additional year-round sulfur dioxide and nitrogen oxide emission
reductions from power plants in the eastern United States in two phases - in
2010 and 2015. The EPA currently plans to finalize this rule by 2005. If
finalized, the rule could modify or supplant other SIP requirements for
attainment of the fine particulate matter standard and the eight-hour ozone
standard. The impact of this rule on the Company will depend upon the specific
requirements of the final rule and cannot be determined at this time.
Further reductions in sulfur dioxide and nitrogen oxides 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's Regional Haze program calls for
states to submit SIPs in 2007. The SIPs must contain emission reduction
strategies for implementing BART and achieving progress toward the Clean Air
Act's 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. The EPA has
entered into an agreement that requires proposed revised rules in April 2004 and
final rules in 2005. Because new BART rules have not been developed and state
visibility assessments for progress 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 apply for renewal of certain Title V
operating permits in 2004, and some units will likely become subject to CAM
requirements, at least for particulate matter. The Company is in the process of
developing CAM plans. Because the plans are still under development, the Company
cannot determine the costs associated with implementation of the CAM
regulations. Actual ongoing monitoring costs are expensed as incurred and are
not material for any year presented.
In January 2004, the EPA issued proposed rules regulating mercury emissions
from electric utility boilers. The proposal solicits comments on two possible
approaches for the new regulations - a Maximum Achievable Control Technology
approach and a cap-and-trade approach. Either approach would require significant
reductions in mercury emissions from company facilities. The regulations are
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 2003 Annual Report
scheduled to be finalized by the end of 2004, and compliance could be required
as early as 2007. Because the regulations have not been finalized, the impact on
the Company cannot be determined at this time.
Several major bills to amend the Clean Air Act to impose more stringent
emissions limitations on power plants have been proposed by Congress. Three of
these, the Bush Administration's Clear Skies Act, the Clean Power Act of 2003,
and the Clean Air Planning Act of 2003, propose to further limit power plant
emissions of sulfur dioxide, nitrogen oxides, and mercury. The latter two bills
also propose to limit emissions of carbon dioxide. The cost impacts of such
legislation would depend upon the specific requirements enacted and cannot be
determined at this time.
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, known
as Climate VISION, 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.
Through Southern Company, the Company is involved in a voluntary electric
utility industry sector climate change initiative in partnership with the
government. The electric utility sector has pledged to reduce its greenhouse gas
intensity 3 percent to 5 percent over the next decade and is in the process of
developing a memorandum of understanding with the Department of Energy (DOE) to
cover this voluntary program.
The Company must comply with other environmental laws and regulations that
cover the handling and disposal of 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. Amounts for cleanup and ongoing monitoring
costs were not material for any year presented. The Company may be liable for
some 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 has been developing new rules aimed at
reducing impingement and entrainment of fish and fish larvae at power plants'
cooling water intake structures. On February 16, 2004, the EPA finalized these
rules. These rules will require biological studies and, perhaps, retrofits to
some intake structures at existing power plants. The impact of these new rules
will depend on the results of studies and analyses performed as part of the
rules' implementation.
In addition, under the Clean Water Act, the EPA and the Georgia
Environmental Protection Division (EPD) are developing total maximum daily loads
(TMDLs) for certain impaired waters. Establishment of maximum loads by the EPA
or the Georgia EPD 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 that discharge 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.
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 or
regulations related to global climate change, electromagnetic fields, or other
environmental and health concerns could also significantly affect the Company.
The impact of any new legislation, changes to existing legislation, or
environmental regulations could affect many areas of the Company's operations.
The full impact of any such changes cannot, however, be determined at this time.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 2003 Annual Report
FERC Matters
Transmission
In December 1999, the FERC issued its final rule (Order 2000) on Regional
Transmission Organizations (RTOs). Order 2000 encouraged utilities owning
transmission systems to form RTOs on a voluntary basis. Southern Company and its
retail operating companies, including the Company, worked with a number of
utilities in the Southeast to develop a for-profit RTO known as SeTrans. In
2002, the sponsors of SeTrans established a Stakeholder Advisory Committee to
provide input into the development of the RTO from other sectors of the electric
industry, as well as consumers. During the development of SeTrans, state
regulatory authorities expressed concern over certain aspects of the FERC's
policies regarding RTOs. In December 2003, the SeTrans sponsors announced that
they would suspend work on SeTrans because the regulated utility participants,
including the Company, had determined that it is highly unlikely to obtain
support of both federal and state regulatory authorities. Any impact of the
FERC's rule on the Company will depend on the regulatory reaction to the
suspension of SeTrans and future developments, which 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 day ahead and spot energy markets;
and (7) revise the FERC policy on the pricing of transmission expansions.
Comments on the proposal were submitted by many interested parties, including
Southern Company, and the FERC has indicated that it has revised certain aspects
of the proposal in response to public comments. Proposed energy legislation
would prohibit the FERC from issuing the final rule before October 31, 2006, and
from making any final rule effective before December 31, 2006. That legislation
has been approved by the House of Representatives but remains pending before the
Senate. Passage of the legislation now appears in doubt. It is uncertain whether
in the absence of legislation the FERC will move forward with any part or all of
the proposed rule. Any impact of this proposal on Southern Company and its
subsidiaries, including the Company, will depend on the form in which the final
rule may be ultimately adopted. The Company's financial statements could be
adversely affected by changes in the transmission regulatory structure in its
regional power market.
Market-Based Rate Authority
The Company has obtained FERC approval to sell power to nonaffiliates at
market-based prices under specific contracts. Through SCS as agent, the Company
also has FERC authority to make short-term opportunity sales at market rates.
Specific FERC approval must be obtained with respect to a market-based contract
with an affiliate. In November 2001, the FERC modified the test it uses to
consider utilities' applications to charge market-based rates and adopted a new
test called the Supply Margin Assessment (SMA). The FERC applied the SMA to
several utilities, including Southern Company's retail operating companies, and
found them to be "pivotal suppliers" in their control area market and ordered
the implementation of several mitigation measures. SCS, on behalf of the retail
operating companies, sought rehearing of the FERC order, and the FERC delayed
the implementation of certain mitigation measures. SCS, on behalf of the retail
operating companies, submitted comments to the FERC in 2002 regarding these
issues. In December 2003, the FERC issued a staff paper discussing alternatives
and held a technical conference in January 2004. The Company anticipates that
the FERC will address the requests for rehearing in the near future. Regardless
of the outcome of the SMA proposal, the FERC retains the ability to modify or
withdraw the authorization for any seller to sell at market-based rates, if it
determines that the underlying conditions for having such authority are no
longer applicable. The final outcome of this matter will depend on the form in
which the SMA test and mitigation measures rules may be ultimately adopted and
cannot be determined at this time.
Southern Power PPA
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
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 2003 Annual Report
planned combined-cycle plant at Plant McIntosh being built and owned by Southern
Power. The annual capacity cost is expected to be approximately $15.0 million.
Purchased power agreements (PPAs) by Georgia Power and the Company for
Southern Power's Plant McIntosh capacity were certified by the GPSC in December
2002 after a competitive bidding process. In April 2003, Southern Power applied
for FERC approval of these PPAs. Interveners opposed the FERC's acceptance of
the PPAs, alleging that the PPAs do not meet the applicable standards for
market-based rates between affiliates. In July 2003, the FERC accepted the PPAs
to become effective as scheduled on June 1, 2005, subject to refund, and ordered
that hearings be held. For additional information, see Note 3 to the financial
statements under "FERC Matters."
Other Matters
In accordance with Financial Accounting Standards Board (FASB) Statement No. 87,
Employers' Accounting for Pensions, the Company recorded non-cash pension costs
of approximately $4.3 million, $4.4 million, and $4.0 million pre-tax in 2003,
2002, and 2001, respectively. Future pension costs are dependent on several
factors including trust earnings and changes to the plan. Postretirement benefit
costs for the Company were approximately $2.7 million in 2003 and $2.6 million
in 2002 and 2001 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.
On December 8, 2003, President Bush signed into law the Medicare
Prescription Drug, Improvement and Modernization Act of 2003 (Medicare Act). The
Medicare Act introduces a prescription drug benefit for Medicare-eligible
retirees starting in 2006, as well as a federal subsidy to plan sponsors like
the Company that provide prescription drug benefits. In accordance with FASB
Staff Position No. 106-1, the Company has elected to defer recognizing the
effects of the Medicare Act for its postretirement plans under FASB Statement
No. 106, Employers' Accounting for Postretirement Benefits Other than Pension
until authoritative guidance on accounting for the federal subsidy is issued or
until a significant event occurs that would require remeasurement of the plans'
assets and obligations. The Company anticipates that the benefits it pays after
2006 will be lower as a result of the Medicare Act; however, the retiree medical
obligations and costs reported in Note 2 to the financial statements do not
reflect these changes. The final accounting guidance could require changes to
previously reported information.
In May 2002, the GPSC approved a $7.8 million base rate increase to recover
expenses related to a new purchased power agreement and other operation and
maintenance expenses and approved 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 2002, the Company filed a request and received an accounting order to defer
until May 2005 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. 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 can be retained by the Company. The accounting
order provides the Company with discretionary authority to amortize up to an
additional $1.5 million annually. In January 2003, the Company began deferring
the costs under the terms of the accounting order. Through December 2003, the
Company has amortized $3.7 million of the $3.8 million deferred. The deferred
costs are included in other deferred debits in the Balance Sheets. The Company
anticipates filing a base rate case in late 2004.
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 is involved in various matters being litigated and regulatory
matters that could affect future earnings. See Note 3 to the financial
statements for information regarding material issues.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 2003 Annual Report
ACCOUNTING POLICIES
- -------------------
Application of Critical Accounting Policies and
Estimates
The Company prepares its financial statements in accordance with accounting
principles generally accepted in the United States. Significant accounting
policies are described in Note 1 to the financial statements. In the application
of these policies, certain estimates are made that may have a material impact on
the Company's results of operations and related disclosures. Different
assumptions and measurements could produce estimates that are significantly
different from those recorded in the financial statements. Senior management has
discussed the development and selection of the critical accounting policies and
estimates described below with the Control and Compliance Committee of the
Company's Board of Directors and the Audit Committee of Southern Company's Board
of Directors.
Electric Utility Regulation
The Company is subject to retail regulation by the GPSC and wholesale regulation
by the FERC. These regulatory agencies set the rates the Company is permitted to
charge customers based on allowable costs. As a result, the Company applies FASB
Statement No. 71, Accounting for the Effects of Certain Types of Regulation.
Through the ratemaking process, the regulators may require the inclusion of
costs or revenues in periods different than when they would be recognized by a
non-regulated company. This treatment may result in the deferral of expenses and
the recording of related regulatory assets based on anticipated future recovery
through rates or the deferral of gains or creation of liabilities and the
recording of related regulatory liabilities. The application of Statement No. 71
has a further effect on the Company's financial statements as a result of the
estimates of allowable costs used in the ratemaking process. These estimates may
differ from those actually incurred by the Company; therefore, the accounting
estimates inherent in specific costs such as depreciation and pension and
post-retirement benefits have less of a direct impact on the Company's results
of operations than they would on a non-regulated company.
As reflected in Note 1 to the financial statements, significant regulatory
assets and liabilities have been recorded. Management reviews the ultimate
recoverability of these regulatory assets and liabilities based on applicable
regulatory guidelines. However, adverse legislation and judicial or regulatory
actions could materially impact the amounts of such regulatory assets and
liabilities and could adversely impact the Company's financial statements.
Contingent Obligations
The Company is subject to a number of federal and state laws and regulations, as
well as other factors and conditions that potentially subject it to
environmental, litigation, income tax, and other risks. See "Future Earnings
Potential" and Note 3 to the financial statements for more information regarding
certain of these contingencies. The Company periodically evaluates its exposure
to such risks and records reserves for those matters where a loss is considered
probable and reasonably estimable in accordance with generally accepted
accounting principles. The adequacy of reserves can be significantly affected by
external events or conditions that can be unpredictable; thus, the ultimate
outcome of such matters could materially affect the Company's financial
statements. These events or conditions include the following:
o Changes in existing state or federal regulation by governmental authorities
having jurisdiction over air quality, water quality, control of toxic
substances, hazardous and solid wastes, and other environmental matters.
o Changes in existing income tax regulations or changes in Internal Revenue
Service interpretations of existing regulations.
o Identification of additional sites that require environmental remediation or
the filing of other complaints in which the Company may be asserted to be a
potentially responsible party.
o Identification and evaluation of other potential lawsuits or complaints in
which the Company may be named as a defendant.
o Resolution or progression of existing matters through the legislative
process, the court systems, or the EPA.
New Accounting Standards
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,
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 2003 Annual Report
established 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 is recorded in the
period in which the liability is incurred. The costs are capitalized as part of
the related long-lived asset and depreciated over the asset's useful life.
Additionally, non-regulated companies are no longer permitted 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 "Asset Retirement Obligations and Other Costs of Removal."
FASB Statement No. 149, Amendment of Statement 133 on Derivative
Instruments and Hedging Activities, which further amends and clarifies the
accounting and reporting for derivative instruments, became effective generally
for financial instruments entered into or modified after June 30, 2003. Current
interpretations of Statement No. 149 indicate that certain electricity forward
transactions subject to unplanned netting -- including those typically referred
to as "book outs" -- may only qualify as cash flow hedges if an entity can
demonstrate that physical delivery or receipt of power occurred. The Company's
forward electricity contracts continue to be exempt from fair value accounting
requirements or to qualify as cash flow hedges, with the related gains and
losses deferred in other comprehensive income. The implementation of Statement
No. 149 did not have a material effect on the Company's financial statements.
In July 2003, the Emerging Issues Task Force (EITF) of FASB issued EITF No.
03-11, which became effective on October 1, 2003. The standard addresses the
reporting of realized gains and losses on derivative instruments and is being
interpreted to require book outs to be recorded on a net basis in operating
revenues. Adoption of this standard did not have a material impact on the
Company's financial statements.
FASB Interpretation No. 46, Consolidation of Variable Interest Entities,
which was originally issued in January 2003, requires the primary beneficiary of
a variable interest entity to consolidate the related assets and liabilities. In
December 2003, the FASB revised Interpretation No. 46 and deferred the effective
date until March 31, 2004, for interests held in variable interest entities or
potential variable interest entities other than special purpose
entities.
Current analysis indicates that any trust established by the Company to
issue preferred securities is a variable interest entity under Interpretation
No. 46, and that the Company is not the primary beneficiary of such a trust. If
this conclusion is finalized, effective March 31, 2004, the investments in such
trusts and loans from such trusts to the Company would be reflected as equity
method investments and as long-term notes payable to affiliates, respectively,
on the Balance Sheets. In January 2004, the Company redeemed all $40 million of
its outstanding mandatorily redeemable preferred securities; thus the adoption
of Interpretation No. 46 is not expected to have any impact on the Company's
financial statements.
In May 2003, the FASB issued Statement No. 150, Accounting for Certain
Financial Instruments with Characteristics of Both Liabilities and Equity, which
requires classification of certain financial instruments within its scope,
including shares that are mandatorily redeemable, as liabilities. Statement No.
150 was effective for financial instruments entered into or modified after May
31, 2003, and otherwise on July 1, 2003. In accordance with Statement No. 150,
mandatorily redeemable preferred securities are reflected as liabilities on the
Balance Sheets. The adoption of Statement No. 150 had no impact on the
Statements of Income and Cash Flows.
FINANCIAL CONDITION AND LIQUIDITY
- ---------------------------------
Overview
As of December 31, 2003, the Company's capital structure consisted of 45.6
percent common stockholder's equity and 54.4 percent long-term debt, excluding
amounts due within one year.
The principal change in the Company's financial condition in 2003 was the
addition of $40.2 million to utility plant. The funds needed for gross property
additions are currently provided from operating activities. See Statements of
Cash Flows for additional information.
Sources of Capital
It is anticipated that the funds required for construction and other purposes,
including compliance with environmental regulations, will be derived from
II-256
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 2003 Annual Report
sources similar to those used in the past including both internal and external
funds. Historically, the external funding came from the issuance of debt and
mandatorily redeemable 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. Currently, the Company has $75
million available under GPSC long-term financing authority expiring December 31,
2005.
As shown in the chart below, at the beginning of 2004, the Company had $60
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.
At the beginning of 2004, bank credit arrangements are as follows:
Expires
-------------------------
2005 &
Total Unused 2004 Beyond
- --------------------------------------------------------------
(in millions)
$80 $60 $40 $20
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 retail operating companies. Proceeds from such issuances for
the benefit of the Company are loaned directly to the Company and are not
commingled with proceeds from such issuances for the benefit of any other
operating company. The obligations of each company under these arrangements are
several; there is no cross affiliate credit support. At December 31, 2003, the
Company had no 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, 2003, the amount of variable rate obligations outstanding requiring
liquidity support was $7.7 million.
The Company obtains financing separately without credit support from any
affiliate. The Southern Company system does not maintain a centralized cash or
money pool. Therefore, funds of the Company are not commingled with funds of any
other company. In accordance with the Public Utility Holding Company Act, most
loans between affiliated companies must be approved in advance by the Securities
and Exchange Commission (SEC).
Financing Activities
Maturities and retirements of long-term debt were $39.4 million in 2003, $53.6
million in 2002, and $50.7 million in 2001.
In May 2003, the Company retired its $20 million Series B 5.12% Senior
Notes due in 2003. In December 2003, the Company issued $25 million of Series E
4.90% Senior Notes maturing in 2013 and $35 million of Series F 5.50% Senior
Notes maturing in 2028. The Company used the proceeds from these two sales to
repay in December 2003 $5 million under a $30 million variable rate revolving
credit agreement of which the Company had borrowed $25 million, to redeem in
January 2004 $40 million of Savannah Electric Capital Trust I 6.85% Trust
Preferred Securities, to repay a portion of its outstanding short-term
indebtedness, and for other general corporate purposes.
In February 2003, the Company refinanced $13.9 million in pollution control
bonds from a daily variable interest rate to an auction rate mode.
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.
II-257
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 2003 Annual Report
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.
Derivative positions are monitored using techniques that include market
valuation and sensitivity analysis.
To mitigate exposure to interest rates, the Company has entered into
interest rate swaps that have been designated as cash flow hedges. The weighted
average rate on variable rate long-term debt outstanding that has not been
hedged at December 31, 2003 was 1.1 percent. If the Company sustained a 100
basis point change in interest rates for all unhedged variable rate long-term
debt, the change would affect annualized interest expense by approximately $0.2
million at December 31, 2003. The Company is not aware of any facts or
circumstances that would significantly affect such exposures in the near term.
See Notes 1 and 6 to the financial statements under "Financial Instruments" for
additional information.
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, the Company
has 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 $1.1 million for 2003 and will be $2.7 million
for 2004. The program has operated within the defined hedging position limits
set for each year.
The fair value of changes in energy related derivative contracts and
year-end valuations were as follows at December 31:
Changes in Fair Value
- -----------------------------------------------------------------
2003 2002
- -----------------------------------------------------------------
(in thousands)
Contracts beginning of year $ 626 $(1,053)
Contracts realized or settled (1,798) 269
New contracts at inception - -
Changes in valuation
techniques - -
Current period changes 1,635 1,410
- -----------------------------------------------------------------
Contracts end of year $ 463 $ 626
=================================================================
Source of 2003 Year-End Valuation Prices
- ------------------------------------------------------------------
Total Maturity
------------------------
Fair Value Year 1 2-3 Years
- ------------------------------------------------------------------
(in thousands)
- ------------------------------------------------------------------
Actively quoted $463 $529 $(66)
External sources - - -
Models and other methods
- - -
- ------------------------------------------------------------------
Contracts end of year $463 $529 $(66)
==================================================================
Unrealized gains and losses from mark to market adjustments on derivative
contracts related to the Company's fuel hedging program are recorded as
regulatory assets and liabilities. Realized gains and losses from this program
are included in fuel expense and recovered through the Company's FCR clause. Of
the net gains, the Company is allowed to retain 25 percent in earnings. Gains
and losses on derivative contracts that are not designated as hedges are
recognized in the Statements of Income as incurred. For the years ended December
31, 2003, 2002, and 2001, these amounts were not material. At December 31, 2003,
the fair value of derivative energy contracts was reflected in the financial
statements as follows:
Amounts
- ----------------------------------------------------------------
(in thousands)
Regulatory liabilities, net $462
Other comprehensive income -
Net income 1
- ----------------------------------------------------------------
Total fair value $463
================================================================
II-258
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 2003 Annual Report
The Company is exposed to market price risk in the event of nonperformance
by counterparties 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 6 to the financial statements under
"Financial Instruments."
Capital Requirements and Contractual Obligations
The Company's construction program is currently estimated to be $51.8 million in
2004, $42.6 million in 2005, and $41.3 million in 2006. Environmental
expenditures included in these amounts are $3.3 million, $1.4 million, and $3.0
million for 2004, 2005, and 2006, 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;
load projections; the cost and efficiency of construction labor, equipment, and
materials; and the cost of capital. In addition, there can be no assurance that
costs related to capital expenditures will be fully recovered. Construction of
new transmission and distribution facilities and capital improvements for
generation, transmission, and distribution facilities, including those needed to
meet the environmental standards previously discussed, will be ongoing.
As discussed in Note 2 to the financial statements, the company provides
postretirement benefits to substantially all employees and funds trusts to the
extent required by the GPSC.
Other funding requirements related to obligations associated with scheduled
maturities of long-term debt and preferred securities, as well as the related
interest and distributions, leases, and other purchase commitments are as
follows: See notes 1, 6, and 7 to the financial statements for additional
information.
2005- 2007- After
2004 2006 2008 2008 Total
- --------------------------------------------------------------------------------------------------------------------------
(in thousands)
Long-term debt and preferred securities(a) --
Principal $ 40,910 $ 41,642 $ 46,565 $134,286 $ 263,403
Interest and distributions 13,926 21,976 18,804 76,730 131,436
Operating leases 844 1,557 1,491 4,255 8,147
Purchase commitments(b) --
Capital(c) 51,750 83,902 - - 135,652
Coal 31,439 - - - 31,439
Natural gas(d) 867 19,142 35,260 284,097 339,366
Purchased power 13,221 51,790 54,720 171,262 290,993
Postretirement benefit trusts(e) -- 1,940 4,120 - - 6,060
- --------------------------------------------------------------------------------------------------------------------------
Total $154,897 $224,129 $156,840 $670,630 $1,206,496
==========================================================================================================================
(a) All amounts are reflected based on final maturity dates. The Company will continue to retire higher-cost securities and
replace these obligations with lower-cost capital if market conditions permit. Variable rate interest obligations are
estimated based on rates as of January 1, 2004, as reflected in the Statements of Capitalization.
(b) The Company generally does not enter into non-cancelable commitments for other operation and maintenance expenditures.
Total other operation and maintenance expenses for the last three years were $83.6 million, $81.0 million, and $70.5
million, respectively.
(c) The Company forecasts capital expenditures over a three-year period. Amounts represent current estimates of total
expenditures. At December 31, 2003, significant purchase commitments were outstanding in connection with the construction
program.
(d) Natural gas purchase commitments contain fixed volumes with prices based on various indices at the time of delivery. Amounts
reflected have been estimated based on the New York Mercantile future prices at December 31, 2003.
(e) The Company forecasts postretirement trust contributions over a three-year period. No contributions related to the Company's
pension trust are currently expected during this period. See Note 2 to the financial statements for additional information
related to the pension plans.
II-259
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 2003 Annual Report
Cautionary Statement Regarding Forward-Looking Information
The Company's 2003 Annual Report includes forward-looking statements in addition
to historical information. Forward-looking information includes, among other
things, statements concerning the estimated construction and other expenditures
and the Company's projections for energy sales and postretirement benefit trust
contributions. 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:
o 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, tax, and other laws and regulations to which the Company is
subject, as well as changes in application of existing laws and regulations;
o current and future litigation, regulatory investigations, proceedings or
inquiries, including the pending EPA civil action against the Company;
o the effects, extent, and timing of the entry of additional competition in the
markets in which the Company operates;
o the impact of fluctuations in commodity prices, interest rates, and
customer demand;
o available sources and costs of fuels;
o ability to control costs;
o investment performance of the Company's employee benefit plans;
o advances in technology;
o state and federal rate regulations and pending and future rate cases and
negotiations;
o effects of and changes in political, legal, and economic conditions and
developments in the United States, including the current soft economy;
o internal restructuring or other restructuring options that may be pursued;
o potential business strategies, including acquisitions or dispositions of
assets, which cannot be assured to be completed or beneficial to the Company;
o the ability of counterparties of the Company to make payments as and when
due;
o the ability to obtain new short- and long-term contracts with neighboring
utilities;
o the direct or indirect effects on the Company's business resulting from the
terrorist incidents on September 11, 2001, or any similar incidents or
responses to such incidents;
o financial market conditions and the results of financing efforts, including
the Company's credit ratings;
o the ability of the Company to obtain additional generating capacity
at competitive prices;
o weather and other natural phenomena;
o the direct or indirect effects on the Company's business resulting from the
August 2003 power outage in the Northeast, or any similar incidents;
o the effect of accounting pronouncements issued periodically by
standard-setting bodies; and
o other factors discussed elsewhere herein and in other reports (including the
Form 10-K) filed from time to time by the Company with the SEC.
II-260
STATEMENTS OF INCOME
For the Years Ended December 31, 2003, 2002, and 2001
Savannah Electric and Power Company 2003 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------------
2003 2002 2001
- ----------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Revenues:
Retail sales $297,745 $285,771 $269,172
Sales for resale --
Non-affiliates 5,653 6,354 8,884
Affiliates 6,499 4,075 3,205
Other revenues 4,158 3,352 2,591
- ----------------------------------------------------------------------------------------------------------------------------------
Total operating revenues 314,055 299,552 283,852
- ----------------------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Fuel 55,308 54,955 50,796
Purchased power --
Non-affiliates 5,713 6,368 23,147
Affiliates 83,792 69,236 49,939
Other operations 56,823 55,756 50,607
Maintenance 26,798 25,262 19,886
Depreciation and amortization 20,499 22,704 25,951
Taxes other than income taxes 14,665 14,457 13,984
- ----------------------------------------------------------------------------------------------------------------------------------
Total operating expenses 263,598 248,738 234,310
- ----------------------------------------------------------------------------------------------------------------------------------
Operating Income 50,457 50,814 49,542
Other Income and (Expense):
Interest income 290 147 173
Interest expense, net of amounts capitalized (9,590) (11,608) (12,517)
Distributions on mandatorily redeemable preferred securities (2,740) (2,740) (2,740)
Other income (expense), net (502) (1,300) (686)
- ----------------------------------------------------------------------------------------------------------------------------------
Total other income and (expense) (12,542) (15,501) (15,770)
- ----------------------------------------------------------------------------------------------------------------------------------
Earnings Before Income Taxes 37,915 35,313 33,772
Income taxes 15,108 12,433 11,731
- ----------------------------------------------------------------------------------------------------------------------------------
Earnings Before Cumulative Effect of
Accounting Change 22,807 22,880 22,041
Cumulative effect of accounting change--
less income taxes of $14 - - 22
- ----------------------------------------------------------------------------------------------------------------------------------
Net Income $ 22,807 $ 22,880 $ 22,063
==================================================================================================================================
The accompanying notes are an integral part of these financial statements.
II-261
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2003, 2002, and 2001
Savannah Electric and Power Company 2003 Annual Report
- ---------------------------------------------------------------------------------------------------------------------------
2003 2002 2001
- ---------------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Activities:
Net income $ 22,807 $ 22,880 $ 22,063
Adjustments to reconcile net income
to net cash provided from operating activities --
Depreciation and amortization 22,587 24,653 27,895
Deferred income taxes and investment tax credits, net 793 (6,227) (20,528)
Pension, postretirement, and other employee benefits 6,215 6,133 6,282
Tax benefit of stock options 884 1,451 -
Other, net 4,015 (10,559) (2,198)
Changes in certain current assets and liabilities --
Receivables, net 1,189 7,965 24,079
Fossil fuel stock (323) 1,522 (2,711)
Materials and supplies 516 3,383 (4,025)
Other current assets 4,057 (5,470) 8,587
Accounts payable 3,713 6,969 (8,439)
Accrued taxes (983) (627) 2,820
Other current liabilities (5,311) 6,560 1,224
- ---------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities 60,159 58,633 55,049
- ---------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (40,242) (32,481) (31,296)
Other 895 (1,331) (1,875)
- ---------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities (39,347) (33,812) (33,171)
- ---------------------------------------------------------------------------------------------------------------------------
Financing Activities:
Decrease in notes payable, net (2,897) (29,263) (13,241)
Proceeds --
Pollution control bonds 13,870 - -
Senior notes 60,000 55,000 65,000
Other long-term debt - 25,616 -
Capital contributions from parent company 6,757 2,499 1,561
Redemptions --
First mortgage bonds - (23,558) (20,642)
Pollution control bonds (13,870) - -
Senior notes (20,000) (30,000) -
Other long-term debt (5,541) - (30,071)
Payment of common stock dividends (23,000) (22,700) (21,700)
Other (2,166) (828) (394)
- ---------------------------------------------------------------------------------------------------------------------------
Net cash provided from (used for) financing activities 13,153 (23,234) (19,487)
- ---------------------------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents 33,965 1,587 2,391
Cash and Cash Equivalents at Beginning of Period 3,978 2,391 -
- ---------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ 37,943 $ 3,978 $ 2,391
===========================================================================================================================
Supplemental Cash Flow Information:
Cash paid during the period for --
Interest (net of $220, $165, and $271 capitalized,
respectively) $11,334 $13,353 $15,340
Income taxes (net of refunds) 8,439 23,478 21,034
- ---------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
II-262
BALANCE SHEETS
At December 31, 2003 and 2002
Savannah Electric and Power Company 2003 Annual Report
- ---------------------------------------------------------------------------------------------------------------------------
Assets 2003 2002
- ---------------------------------------------------------------------------------------------------------------------------
(in thousands)
Current Assets:
Cash and cash equivalents $ 37,943 $ 3,978
Receivables --
Customer accounts receivable 19,674 22,631
Unbilled revenues 11,288 11,531
Other accounts and notes receivable 1,138 2,937
Affiliated companies 4,872 1,102
Accumulated provision for uncollectible accounts (641) (682)
Fossil fuel stock, at average cost 8,652 8,328
Materials and supplies, at average cost 9,070 9,586
Prepaid income taxes 24,419 24,414
Prepaid expenses 1,377 806
Other 623 1,260
- ---------------------------------------------------------------------------------------------------------------------------
Total current assets 118,415 85,891
- ---------------------------------------------------------------------------------------------------------------------------
Property, Plant, and Equipment:
In service 912,504 880,605
Less accumulated provision for depreciation 402,394 384,348
- ---------------------------------------------------------------------------------------------------------------------------
510,110 496,257
Construction work in progress 14,121 6,082
- ---------------------------------------------------------------------------------------------------------------------------
Total property, plant, and equipment 524,231 502,339
- ---------------------------------------------------------------------------------------------------------------------------
Other property and investments 2,248 3,648
- ---------------------------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets:
Deferred charges related to income taxes 9,611 11,692
Cash surrender value of life insurance for deferred compensation plans 23,866 21,943
Unamortized debt issuance expense 5,652 3,757
Unamortized loss on reacquired debt 7,488 8,103
Other 18,410 11,716
- ---------------------------------------------------------------------------------------------------------------------------
Total deferred charges and other assets 65,027 57,211
- ---------------------------------------------------------------------------------------------------------------------------
Total Assets $709,921 $649,089
===========================================================================================================================
The accompanying notes are an integral part of these financial statements.
II-263
BALANCE SHEETS
At December 31, 2003 and 2002
Savannah Electric and Power Company 2003 Annual Report
- ------------------------------------------------------------------------------------------------------------------------------
Liabilities and Stockholder's Equity 2003 2002
- ------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Current Liabilities:
Securities due within one year $ 40,910 $ 20,892
Notes payable - 2,897
Accounts payable --
Affiliated 13,797 7,889
Other 13,147 15,211
Customer deposits 6,922 6,781
Accrued taxes --
Income taxes 1,172 311
Other 1,473 3,317
Accrued interest 2,802 3,268
Accrued vacation pay 2,530 2,427
Accrued compensation 5,652 6,471
Other 5,107 9,320
- ------------------------------------------------------------------------------------------------------------------------------
Total current liabilities 93,512 78,784
- ------------------------------------------------------------------------------------------------------------------------------
Long-term debt (See accompanying statements) 222,493 168,052
- ------------------------------------------------------------------------------------------------------------------------------
Mandatorily redeemable preferred securities (See accompanying statements) - 40,000
- ------------------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 83,852 78,970
Deferred credits related to income taxes 9,804 12,445
Accumulated deferred investment tax credits 8,625 9,289
Employee benefit obligations 39,833 33,619
Other cost of removal obligations 36,843 31,884
Miscellaneous regulatory liabilities 12,932 14,256
Other 15,735 1,986
- ------------------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 207,624 182,449
- ------------------------------------------------------------------------------------------------------------------------------
Total liabilities 523,629 469,285
- ------------------------------------------------------------------------------------------------------------------------------
Common stockholder's equity (See accompanying statements) 186,292 179,804
- ------------------------------------------------------------------------------------------------------------------------------
Total Liabilities and Stockholder's Equity $709,921 $649,089
==============================================================================================================================
Commitments and Contingent Matters (See notes)
- ------------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
II-264
STATEMENTS OF CAPITALIZATION
At December 31, 2003 and 2002
Savannah Electric and Power Company 2003 Annual Report
- ---------------------------------------------------------------------------------------------------------------------------------
2003 2002 2003 2002
- ---------------------------------------------------------------------------------------------------------------------------------
(in thousands) (percent of total)
Long-Term Debt:
First mortgage bonds --
6.9% due May 1, 2006 $ 20,000 $ 20,000
- ---------------------------------------------------------------------------------------------------------------------------------
Total first mortgage bonds 20,000 20,000
- ---------------------------------------------------------------------------------------------------------------------------------
Long-term notes payable --
5.12% due May 15, 2003 - 20,000
6.55% due May 15, 2008 45,000 45,000
4.90% to 5.50% due 2013 through 2028 115,000 55,000
Adjustable rates (1.56% at 1/1/04)
due September 6, 2005 20,000 25,000
- ---------------------------------------------------------------------------------------------------------------------------------
Total long-term notes payable 180,000 145,000
- ---------------------------------------------------------------------------------------------------------------------------------
Other long-term debt --
Pollution control revenue bonds --
Non-collateralized:
Variable rates (1.05% to 1.31% at 1/1/04)
due 2016-2038 17,955 17,955
- ---------------------------------------------------------------------------------------------------------------------------------
Total other long-term debt 17,955 17,955
- ---------------------------------------------------------------------------------------------------------------------------------
Capitalized lease obligations 5,448 5,989
- ---------------------------------------------------------------------------------------------------------------------------------
Total long-term debt (annual interest
requirement -- $11.2 million) 223,403 188,944
Less amount due within one year 910 20,892
- ---------------------------------------------------------------------------------------------------------------------------------
Long-term debt excluding amount due within one year 222,493 168,052 54.4% 43.3%
- ---------------------------------------------------------------------------------------------------------------------------------
Mandatorily Redeemable Preferred Securities:
$25 liquidation value --
6.85% due 2028 40,000 40,000
- ---------------------------------------------------------------------------------------------------------------------------------
Total mandatorily redeemable preferred securities
(annual distribution requirement -- $2.7 million) 40,000 40,000
Less amount due within one year 40,000 -
- ---------------------------------------------------------------------------------------------------------------------------------
Mandatorily redeemable preferred securities
excluding amount due within one year - 40,000 0.0 10.3
- ---------------------------------------------------------------------------------------------------------------------------------
Common Stockholder's Equity:
Common stock, par value $5 per share --
Authorized - 16,000,000 shares
Outstanding - 10,844,635 shares in 2003 and 2002
Par value 54,223 54,223
Paid-in capital 24,417 16,776
Retained earnings 109,856 110,049
Accumulated other comprehensive income (loss) (2,204) (1,244)
- ---------------------------------------------------------------------------------------------------------------------------------
Total common stockholder's equity 186,292 179,804 45.6 46.4
- ---------------------------------------------------------------------------------------------------------------------------------
Total Capitalization $408,785 $387,856 100.0% 100.0%
=================================================================================================================================
The accompanying notes are an integral part of these financial statements.
II-265
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
For the Years Ended December 31, 2003, 2002, and 2001
Savannah Electric and Power Company 2003 Annual Report
- --------------------------------------------------------------------------------------------------------------------------------
Other
Common Paid-In Retained Comprehensive
Stock Capital Earnings Income (loss) Total
- --------------------------------------------------------------------------------------------------------------------------------
(in thousands)
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
Net income - - 22,807 - 22,807
Capital contributions from parent company - 7,641 - - 7,641
Other comprehensive income (loss) - - - (960) (960)
Cash dividends on common stock - - (23,000) - (23,000)
- -------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2003 $54,223 $24,417 $109,856 $(2,204) $186,292
================================================================================================================================
The accompanying notes are an integral part of these financial statements.
STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2003, 2002, and 2001
Savannah Electric and Power Company 2003 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------------
2003 2002 2001
- -----------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Net income $22,807 $22,880 $22,063
- -----------------------------------------------------------------------------------------------------------------------------------
Other comprehensive income (loss):
Change in additional minimum pension liability, net of tax of
$(336) and $(785), respectively (533) (1,244) -
Changes in fair value of qualifying hedges, net of tax of $(284) (450) - -
Less: Reclassification adjustment for amounts included in net
income, net of tax of $15 23 - -
- -----------------------------------------------------------------------------------------------------------------------------------
Total other comprehensive income (loss) (960) (1,244) -
- -----------------------------------------------------------------------------------------------------------------------------------
Comprehensive Income $21,847 $21,636 $22,063
===================================================================================================================================
The accompanying notes are an integral part of these financial statements.
II-266
NOTES TO FINANCIAL STATEMENTS
Savannah Electric and Power Company 2003 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 retail operating
companies, Southern Power Company (Southern Power), Southern Company Services
(SCS), 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 retail operating companies -- Alabama Power,
Georgia Power, Gulf Power, Mississippi Power, and the Company -- provide
electric service in four Southeastern states. The Company operates as a
vertically integrated utility providing electricity to retail customers within
its traditional service area of southeastern Georgia. 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
retail 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, the system service
company, provides, at cost, specialized services to Southern Company and
subsidiary companies. Southern LINC provides digital wireless communications
services to the retail 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 is a competitive retail natural gas
marketer serving customers in Georgia. Southern Holdings is an intermediate
holding subsidiary for Southern Company's investments in synthetic fuels and
leveraged leases and an energy services business. Southern Nuclear operates and
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, including the Company, 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 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
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 $16.3 million, $15.6 million,
and $15.0 million during 2003, 2002, and 2001, respectively. Cost allocation
methodologies used by SCS 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 capacity and energy costs in 2003
amounted to $30.1 million. At December 31, 2003, approximately $1.5 million in
prepaid capacity expense related to this agreement was recorded in other
deferred debits in the Balance Sheets.
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 3 under "FERC Hearings"
and Note 7 under "Purchased Power Commitments" for additional information.
II-267
NOTES (continued)
Savannah Electric and Power Company 2003 Annual Report
In March 2003, the Company transferred to Southern Power 58 acres of land
to facilitate construction at Plant McIntosh. The transfer was made at the
Company's book value of approximately $16,500 in accordance with PUHCA and the
related SEC order (Release No. 35-27322) dated December 27, 2000, which
authorized the formation of Southern Power and the transfer of assets thereto.
On July 17, 2003, the GPSC issued an order requiring that the Company record the
transfer of this land at the higher of net book value or fair market value based
on an appraisal by an appraiser selected by the GPSC staff. Based on the
appraisal completed in September 2003, the fair market value of the land was
established at $320,000.
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 $3.6 million in 2003 and
$1.8 million in 2002. See Note 4 under "Joint Ownership Agreements" for
additional information.
The retail operating companies, including the Company, Southern Power, and
Southern Company 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 7 under "Fuel Commitments"
and "Purchased Power Commitments" for additional information.
Revenues 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.
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.
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.
Regulatory Assets and Liabilities
The Company is subject to the provisions of Financial Accounting Standards Board
(FASB) Statement No. 71, Accounting for the Effects of Certain Types of
Regulation. Regulatory assets represent probable future revenues to the Company
associated with certain costs that are expected to be recovered from customers
through the ratemaking process. Regulatory liabilities represent probable future
reductions in revenues associated with amounts that are expected to be credited
to customers through the ratemaking process.
II-268
NOTES (continued)
Savannah Electric and Power Company 2003 Annual Report
Regulatory assets and (liabilities) reflected in the Balance Sheets at
December 31 and the amortization periods are discussed below as follows:
2003 2002 Note
------------------------------
(in thousands)
Asset retirement obligations $ 3,265 $ - (a)
Deferred income tax charges 9,611 11,692 (a)
Loss on reacquired debt 7,488 8,103 (b)
Deferred McIntosh
maintenance costs 9,818 5,790 (c)
Wansley accounting order 162 - (d)
Other cost of removal
obligations (36,843) (31,884) (a)
Fuel-hedging liabilities (462) (621) (e)
Deferred income tax credits (9,804) (12,445) (a)
Storm damage reserves (7,103) (5,603) (d)
Accelerated cost recovery (4,269) (7,282) (f)
Property damages reserves (1,098) (750) (g)
Injuries and damages reserves (91) (250) (g)
- -------------------------------------------------------
Total $(29,326) $(33,250)
=======================================================
Note: The recovery and amortization periods for these regulatory assets and
(liabilities) are as follows:
(a) Asset retirement and removal liabilities are recorded, deferred income
tax assets are recovered, and deferred tax liabilities are amortized
over the related property lives, which may range up to 50 years. Asset
retirement and removal liabilities will be settled and trued up following
completion of the related activities.
(b) Recovered over either the remaining life of the original issue or, if
refinanced, over the life of the new issue, which may range up to 35
years.
(c) Amortized over 10 years ending in 2011.
(d) Recorded and recovered or amortized as approved by the GPSC.
(e) Fuel-hedging assets and liabilities are recorded over the life of the
underlying hedged purchase contracts, which generally do not exceed two
years. Upon final settlement, costs are recovered through the fuel cost
recovery clauses.
(f) Amortized over three-year period ending in May 2005.
(g) Recorded and relieved upon the occurrence of a loss.
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 to be reflected in rates.
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 2003, 2.9
percent in 2002, and 3.0 percent in 2001. 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 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 certain facilities. In
2002 and 2001, the Company recorded accelerated depreciation of $1.0 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 cost recovery as a credit to depreciation expense over a
three year period beginning June 2002. Accordingly, in 2003 and 2002, the
Company amortized $3.0 million and $1.8 million, respectively. See Note 3 under
"Retail Regulatory Matters" for additional information.
Asset Retirement Obligations
and Other Costs of Removal
In accordance with regulatory requirements, prior to 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 accordance with SEC requirements, such
amounts are reflected on the Balance Sheet as regulatory liabilities. Effective
January 1, 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 costs 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 costs 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 the continued accrual of future retirement costs for
long-lived assets that the Company does not have a legal obligation to retire.
However, the Company has received guidance regarding accounting for the
financial statement impacts of Statement No. 143 from the GPSC and will continue
to recognize the accumulated removal costs for other obligations as a regulatory
II-269
NOTES (continued)
Savannah Electric and Power Company 2003 Annual Report
liability included in accumulated depreciation. Therefore, the Company had no
cumulative effect to net income resulting from the adoption of Statement No.
143.
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, liabilities for the removal of these
transmission and distribution assets have not been recorded because no
reasonable estimate can be made regarding the timing of the obligations. The
Company will continue to recognize in the income statement allowed removal costs
in accordance with its regulatory treatment. Any difference between costs
recognized under Statement No. 143 and those reflected in rates are recognized
as either a regulatory asset or liability and are reflected in the Balance
Sheets.
Details of the asset retirement obligations included in the Balance Sheets
are as follows:
2003
- ----------------------------------------------------------------
(in thousands)
Balance beginning of year $ -
Liabilities incurred 4,020
Liabilities settled (11)
Accretion 211
Cash flow revisions -
- ----------------------------------------------------------------
Balance end of year $4,220
================================================================
If Statement No. 143 had been adopted on January 1, 2002, the pro-forma
asset retirement obligations would have been $2.7 million.
Allowance for Funds Used During Construction
(AFUDC)
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 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 4.22 percent in 2003, 2.82 percent in 2002, and 5.13 percent in 2001. AFUDC
as a percent of net income was 1.4 percent in 2003, 0.4 percent in 2002, and 0.8
percent in 2001.
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
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. 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
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 either the amount of regulatory disallowance or 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.
Materials and Supplies
Generally, materials and supplies include the average 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-270
NOTES (continued)
Savannah Electric and Power Company 2003 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.
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
that meet the definition of a derivative are exempt from fair value accounting
requirements and are accounted for under the accrual method. Other derivative
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. Other
derivative contracts 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.
The Company has implemented a natural gas/oil hedging program as 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 $1.1 million for 2003 and will be $2.7
million for 2004. The program has operated within the defined hedging position
limits set for each year.
The Company's other financial instruments for which the carrying amount
does not equal fair value at December 31 were as follows:
Carrying Fair
Amount Value
--------------------------
(in millions)
Long-term debt:
At December 31, 2003 $218 $220
At December 31, 2002 $183 $187
The fair values for long-term debt were based on either closing market
prices or closing prices of comparable instruments.
Comprehensive Income
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. Comprehensive
income consists of net income and changes in the fair value of qualifying cash
flow hedges and changes in additional minimum pension liability, net of income
taxes.
2. RETIREMENT BENEFITS
The Company has a defined benefit, trusteed, non-contributory pension plan that
covers substantially all employees. The plan is funded in accordance with
Employee Retirement Income Security Act (ERISA) requirements. The Company also
provides certain non-qualified benefit plans for a selected group of management
and highly compensated employees and directors. Benefits under these
non-qualified plans are funded on a cash basis. In addition, 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. 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. For the year ended December 31,
II-271
NOTES (continued)
Savannah Electric and Power Company 2003 Annual Report
2004, postretirement benefit contributions are expected to total approximately
$1.9 million.
The measurement date for plan assets and obligations is September 30 for
each year. In 2002, the Company adopted several plan changes that had the effect
of increasing benefits to both current and future retirees.
Pension Plans
The accumulated benefit obligation for the pension plans was $87.2 million in
2003 and $76.6 million in 2002. Changes during the year in the projected benefit
obligations, accumulated benefit obligations, and fair value of plan assets were
as follows:
Projected
Benefit Obligations
---------------------------
2003 2002
- ---------------------------------------------------------------
(in thousands)
Balance at beginning of year $85,262 $79,550
Service cost 2,175 2,204
Interest cost 5,409 5,811
Benefits paid (4,425) (4,213)
Actuarial loss and
employee transfers 6,137 1,793
Amendments 231 117
- ---------------------------------------------------------------
Balance at end of year $94,789 $85,262
===============================================================
Plan Assets
---------------------------
2003 2002
- ---------------------------------------------------------------
(in thousands)
Balance at beginning of year $44,092 $50,858
Actual return on plan assets 6,829 (2,720)
Benefits paid (3,909) (3,734)
Employee transfers 478 (312)
- ---------------------------------------------------------------
Balance at end of year $47,490 $44,092
===============================================================
Pension plan assets are managed and invested in accordance with all
applicable requirements, including ERISA and the Internal Revenue Service (IRS)
revenue code. The Company's investment policy covers a diversified mix of
assets, including equity and fixed income securities, real estate, and private
equity, as described in the table below. Derivative instruments are used
primarily as hedging tools but may also be used to gain efficient exposure to
the various asset classes. The Company primarily minimizes the risk of large
losses through diversification but also monitors and manages other aspects of
risk.
Plan assets were invested as follows:
Plan Assets
--------------------------------
Target 2003 2002
- ----------------------------------------------------------------
Domestic equity 37% 37% 35%
International equity 20 20 18
Global fixed income 26 24 25
Real estate 10 11 12
Private equity 7 8 10
- ----------------------------------------------------------------
Total 100% 100% 100%
================================================================
The accrued pension costs recognized in the Balance Sheets
were as follows:
2003 2002
- ---------------------------------------------------------------
(in thousands)
Funded status $(47,299) $(41,170)
Unrecognized prior service
cost 7,258 6,847
Unrecognized net loss 23,379 21,432
- ---------------------------------------------------------------
Accrued liability recognized
in the Balance Sheets $(16,662) $(12,891)
===============================================================
In 2003 and 2002, amounts recognized in the Balance Sheets for accumulated
other comprehensive income and intangible assets to record the minimum pension
liability related to the non-qualified plans were $2.9 million and $1.5 million
and $2.0 million and $1.5 million, respectively.
Components of the pension plans' net periodic cost were as follows:
2003 2002 2001
- -----------------------------------------------------------------
(in thousands)
Service cost $ 2,175 $ 2,204 $ 2,074
Interest cost 5,409 5,811 5,426
Expected return on plan
assets (4,186) (4,311) (4,215)
Recognized net loss 152 54 16
Net amortization 740 672 700
- -----------------------------------------------------------------
Net pension cost $ 4,290 $ 4,430 $ 4,001
=================================================================
II-272
NOTES (continued)
Savannah Electric and Power Company 2003 Annual Report
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
---------------------------
2003 2002
- ----------------------------------------------------------------
(in thousands)
Balance at beginning of year $32,702 $28,121
Service cost 493 431
Interest cost 2,082 2,065
Benefits paid (1,319) (1,160)
Actuarial loss (gain) and
employee transfers 3,291 3,245
- ---------------------------------------------------------------
Balance at end of year $37,249 $32,702
===============================================================
Plan Assets
---------------------------
2003 2002
- ---------------------------------------------------------------
(in thousands)
Balance at beginning of year $7,994 $7,401
Actual return on plan assets 1,481 (732)
Employer contributions 3,119 2,485
Benefits paid (1,319) (1,160)
- ---------------------------------------------------------------
Balance at end of year $11,275 $7,994
===============================================================
Postretirement benefits plan assets are managed and invested in accordance
with all applicable requirements, including ERISA and the IRS revenue code. The
Company's investment policy covers a diversified mix of assets, including equity
and fixed income securities, real estate, and private equity, as described in
the table below. Derivative instruments are used primarily as hedging tools but
may also be used to gain efficient exposure to the various asset classes. The
Company primarily minimizes the risk of large losses through diversification but
also monitors and manages other aspects of risk.
Plan assets were invested as follows:
Plan Assets
--------------------------------
Target 2003 2002
- ----------------------------------------------------------------
Domestic equity 52% 51% 44%
International equity 11 14 15
Global fixed income 33 30 34
Real estate 2 3 4
Private equity 2 2 3
- ----------------------------------------------------------------
Total 100% 100% 100%
================================================================
The accrued postretirement costs recognized in the Balance Sheets were as
follows:
2003 2002
- ---------------------------------------------------------------
(in thousands)
Funded status $(25,974) $(24,708)
Unrecognized transition
obligation 4,444 4,938
Unamortized prior service cost 4,167 4,429
Unrecognized net loss 8,886 6,435
Fourth quarter contributions 1,063 2,104
- ---------------------------------------------------------------
Accrued liability recognized in
the Balance Sheets $(7,414) $(6,802)
===============================================================
Components of the postretirement plan's net periodic cost
were as follows:
2003 2002 2001
- ----------------------------------------------------------------
(in thousands)
Service cost $ 493 $ 431 $ 433
Interest cost 2,082 2,065 2,022
Expected return on plan assets (732) (627) (555)
Recognized net loss 91 - -
Net amortization 756 756 731
- ----------------------------------------------------------------
Net postretirement cost $2,690 $2,625 $2,631
================================================================
The weighted average rates assumed in the actuarial calculations used to
determine both the benefit obligations and the net periodic costs for the
pension and postretirement benefit plans were as follows:
2003 2002 2001
- -----------------------------------------------------------------
Discount 6.00% 6.50% 7.50%
Annual salary increase 3.75 4.00 5.00
Long-term return on plan assets 8.50 8.50 8.50
- -----------------------------------------------------------------
The Company determined the long-term rate of return based on historical asset
class returns and current market conditions, taking into account the
diversification benefits of investing in multiple asset classes.
An additional assumption used in measuring the accumulated postretirement
benefit obligation was a weighted average medical care cost trend rate of 8.25
percent for 2003, 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
II-273
NOTES (continued)
Savannah Electric and Power Company 2003 Annual Report
benefit obligation and the service and interest cost components at
December 31, 2003 as follows:
1 Percent 1 Percent
Increase Decrease
- ---------------------------------------------------------------
(in thousands)
Benefit obligation $2,437 $2,209
Service and interest costs 158 142
===============================================================
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 2003, 2002, and 2001 were $1.1
million, $1.0 million, and $1.0 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. In addition, 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 against the Company cannot be predicted at this time;
however, management does not anticipate that the liabilities, if any, arising
from such current proceedings would have a material adverse effect on the
Company's financial statements.
New Source Review Actions
In November 1999, the Environmental Protection Agency (EPA) brought a civil
action in the U.S. District Court for the Northern District of Georgia against
Alabama Power, Georgia Power, and SCS. The complaint alleged violations of the
New Source Review (NSR) provisions of the Clean Air Act with respect to five
coal-fired generating facilities in Alabama and Georgia and violations of
related state laws. The civil action requested 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 retail
operating companies, notices of violation relating 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 notices of violation and to add Gulf Power,
Mississippi Power, and the Company as defendants.
In August 2000, the U.S. District Court in Georgia granted Alabama Power's
motion to dismiss for lack of jurisdiction in Georgia and granted SCS' motion to
dismiss on the grounds that it neither owned nor operated the generating units
involved in the proceedings. In March 2001, 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 in Georgia 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. In
addition, the EPA refiled its claims against Alabama Power in the U.S. District
Court for the Northern District of Alabama. These complaints allege violations
with respect to eight coal-fired generating facilities in Alabama and Georgia,
and they request the same kinds of relief as was requested in the original
complaint, i.e. penalties and injunctive relief, including installation of the
best available control technology. The EPA has not refiled against Gulf Power,
Mississippi Power, or SCS.
The actions against Alabama Power, Georgia Power, and the Company were
stayed in the spring of 2001 during the appeal of a very similar NSR enforcement
action against the Tennessee Valley Authority (TVA) before the U.S. Court of
Appeals for the Eleventh Circuit. The TVA appeal involves many of the same legal
issues raised by the actions against Alabama Power, Georgia Power, and the
Company. Because the final resolution of the TVA appeal could have a significant
impact on Alabama Power and Georgia Power, both companies have been involved in
that appeal. On June 24, 2003, the court of appeals issued its ruling in the TVA
case. It found unconstitutional the statutory scheme set forth in the Clean Air
Act that allowed the EPA to impose penalties for failing to comply with an
administrative compliance order, like the one issued to TVA, without the EPA
having to prove the underlying violation. Thus, the court of appeals held that
II-274
NOTES (continued)
Savannah Electric and Power Company 2003 Annual Report
the compliance order was of no legal consequence, and TVA was free to ignore it.
The court did not, however, rule directly on the substantive legal issues about
the proper interpretation and application of certain NSR provisions that had
been raised in the TVA appeal. On September 16, 2003, the court of appeals
denied the EPA's request for a rehearing of the decision. On February 13, 2004,
the EPA petitioned the U.S. Supreme Court to review the decision of the court of
appeals. The EPA also filed a motion to lift the stay in the action against
Alabama Power. At this time, no party to the Georgia Power and Savannah Electric
action, which was administratively closed two years ago, has asked the court to
reopen that case.
Since the inception of the NSR proceedings against Georgia Power, Alabama
Power, and the Company, the EPA has also been proceeding with similar NSR
enforcement actions against other utilities, involving many of the same legal
issues. In each case, the EPA alleged that the utilities failed to comply with
the NSR permitting requirements when performing maintenance and construction
activities at coal-burning plants, which activities the utilities considered to
be routine or otherwise not subject to NSR. In 2003, district courts addressing
these cases issued opinions that reached conflicting conclusions.
In October 2003, the EPA issued final revisions to its NSR regulations
under the Clean Air Act clarifying the scope of the existing Routine
Maintenance, Repair, and Replacement exclusion. On December 24, 2003, the U.S.
Court of Appeals for the District of Columbia Circuit stayed the effectiveness
of these revisions pending resolution of related litigation. In January 2004,
the Bush Administration announced that it would continue to enforce the existing
rules.
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 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 if such costs are not
recovered through regulated rates.
Right of Way Litigation
In late 2001, certain subsidiaries of Southern Company, including Alabama Power,
Georgia Power, Gulf Power, Mississippi Power, the Company, and Southern Telecom
(collectively, defendants), were named as defendants in a lawsuit brought by a
telecommunications company that uses certain of the defendants' rights of way.
This lawsuit alleges, among other things, that the defendants are contractually
obligated to indemnify, defend, and hold harmless the telecommunications company
from any liability that may be assessed against the telecommunications company
in pending and future right of way litigation. The Company believes that the
plaintiff's claims are without merit. An adverse outcome in this matter,
combined with an adverse outcome against the telecommunications company in one
or more of the right of way lawsuits, 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. 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 December
2002, at the Company's request, the GPSC issued an accounting order authorizing
the Company to defer until May 2005 approximately $3.8 million annually in Plant
Wansley purchased power costs that the GPSC had ruled to be outside the test
period for the base rate order. 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 can be retained by the Company. The
Company has the discretionary authority to amortize up to an additional $1.5
million annually. In January 2003, the Company began deferring the costs under
the terms of the accounting order. Through December 2003, the Company amortized
II-275
NOTES (continued)
Savannah Electric and Power Company 2003 Annual Report
$3.7 million of the $3.8 million deferred. The Company anticipates filing a base
rate case in late 2004.
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. Under the 2002 rate order, the
accumulated accelerated depreciation is being amortized equally over three years
as a credit to expense beginning June 1, 2002. At this time, the Company also
discontinued recording accelerated depreciation. 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 in 2001. Under the 2002 rate order, the
Company's annual storm damage accrual level was set at $1.5 million. The Company
accrued $1.5 million in 2003 and $0.9 million in 2002 to the accumulated
provision for storm damage.
FERC Matters
The Company has obtained FERC approval to sell power to nonaffiliates at
market-based prices under specific contracts. Through SCS as agent, the Company
also has FERC authority to make short-term opportunity sales at market rates.
Specific FERC approval must be obtained with respect to a market-based contract
with an affiliate. In November 2001, the FERC modified the test it uses to
consider utilities' applications to charge market-based rates and adopted a new
test called the Supply Margin Assessment (SMA). The FERC applied the SMA to
several utilities, including Southern Company's retail operating companies, and
found them to be "pivotal suppliers" in their control area market and ordered
the implementation of several mitigation measures. SCS, on behalf of the retail
operating companies, sought rehearing of the FERC order, and the FERC delayed
the implementation of certain mitigation measures. SCS, on behalf of the retail
operating companies, submitted comments to the FERC in 2002 regarding these
issues. In December 2003, the FERC issued a staff paper discussing alternatives
and held a technical conference in January 2004. The Company anticipates that
the FERC will address the requests for rehearing in the near future. Regardless
of the outcome of the SMA proposal, the FERC retains the ability to modify or
withdraw the authorization for any seller to sell at market-based rates, if it
determines that the underlying conditions for having such authority are no
longer applicable. The final outcome of this matter will depend on the form in
which the SMA test and mitigation measures rules may be ultimately adopted and
cannot be determined at this time.
Purchased power agreements (PPAs) by Georgia Power and the Company for
Southern Power's Plant McIntosh capacity were certified by the GPSC in December
2002 after a competitive bidding process. In April 2003, Southern Power applied
for FERC approval of these PPAs. Interveners opposed the FERC's acceptance of
the PPAs, alleging that the PPAs do not meet the applicable standards for
market-based rates between affiliates. In July 2003, the FERC accepted the PPAs
to become effective as scheduled on June 1, 2005, subject to refund, and ordered
that hearings be held to determine: (a) whether, in the design and
implementation of the GPSC competitive bidding process, Georgia Power and the
Company unduly preferred Southern Power; (b) whether the analysis of the
competitive bids unduly favored Southern Power, particularly with respect to
evaluation of non-price factors; (c) whether Georgia Power and the Company
selected their affiliate, Southern Power, based upon a reasonable combination of
price and non-price factors; (d) whether Southern Power received an undue
preference or competitive advantage in the competitive bidding process as a
result of access to its affiliate's transmission system; (e) whether and to what
extent the PPAs impact wholesale competition; and (f) whether the PPAs are just
and reasonable and not unduly discriminatory. Hearings are scheduled to begin in
March 2004. Management believes that the PPAs should be approved by the FERC;
however, the ultimate outcome of this matter cannot now be determined.
4. JOINT OWNERSHIP AGREEMENTS
The Company operates and jointly owns its Plant McIntosh combustion turbines
with Georgia Power. Two of the eight units are owned by the Company, and six
units are owned by Georgia Power. The Company's amount of investment in Plant
McIntosh combustion turbines and related accumulated depreciation at December
31, 2003 were $53 million and $13 million, respectively. The Company's
II-276
NOTES (continued)
Savannah Electric and Power Company 2003 Annual Report
proportionate share of its combustion turbine plant operating expenses is
included in the corresponding operating expenses in the Statements of Income.
5. INCOME TAXES
Southern Company files a consolidated federal income tax return. In 2002,
Southern Company began filing a combined State of Georgia 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 IRS
regulations, each company is jointly and severally liable for the tax liability.
At December 31, 2003, tax-related regulatory assets and liabilities were
$9.6 million and $9.8 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.
Details of income tax provisions are as follows:
2003 2002 2001
--------------------------------
(in thousands)
Total provision for income taxes
Federal --
Currently payable $11,725 $17,089 $27,991
Deferred 1,299 (5,660) (17,951)
- ------------------------------------------------------------------
13,024 11,429 10,040
- ------------------------------------------------------------------
State --
Currently payable 2,730 1,572 4,282
Deferred (646) (568) (2,577)
- ------------------------------------------------------------------
2,084 1,004 1,705
- ------------------------------------------------------------------
Total $15,108 $12,433 $11,745
==================================================================
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:
2003 2002
---------------------
(in thousands)
Deferred tax liabilities:
Accelerated depreciation $88,332 $83,092
Property basis differences (1,640) (1,250)
Other 2,696 3,630
- ------------------------------------------------------------------
Total 89,388 85,472
- ------------------------------------------------------------------
Deferred tax assets:
Pension and other benefits 15,671 12,792
Other 14,284 14,132
- ------------------------------------------------------------------
Total 29,955 26,924
- ------------------------------------------------------------------
Total deferred tax liabilities, net 59,433 58,548
Portion included in current assets, net 24,419 20,422
- ------------------------------------------------------------------
Accumulated deferred income taxes
in the Balance Sheets $83,852 $78,970
==================================================================
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 2003,
2002, and 2001. At December 31, 2003, 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:
2003 2002 2001
----------------------------
Federal statutory tax rate 35% 35% 35%
State income tax, net of
Federal income tax benefit 4 2 3
Other 1 (2) (3)
----------------------------------------------------------------
Effective income tax rate 40% 35% 35%
================================================================
6. FINANCING
Mandatorily Redeemable Preferred Securities
The Company formed a wholly owned trust subsidiary for the purpose of issuing
$40 million preferred securities. The proceeds of the related equity investment
and preferred security sale were loaned back to the Company through the issuance
of junior subordinated notes totaling $41.2 million, which constitute
substantially all of the assets of the trust. The Company considers that the
mechanisms and obligations relating to the preferred securities issued for its
benefit, taken together, constitute a full and unconditional guarantee by it of
the trust's payment obligations with respect to these securities.
II-277
NOTES (continued)
Savannah Electric and Power Company 2003 Annual Report
In January 2004, all preferred securities issued by the trust were redeemed
at par; therefore at December 31, 2003, they were included on the Balance Sheets
in Securities Due Within One Year.
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.
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.
Long-Term Debt 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:
2003 2002
----------------------
(in thousands)
Bond sinking fund requirement $ 200 $ 200
Less:
Portion to be satisfied by
certifying property additions 200 200
- -------------------------------------------------------------------
Cash sinking fund requirement - -
Mandatorily redeemable preferred
securities 40,000 -
Other long-term debt maturities 910 20,892
- -------------------------------------------------------------------
Total $40,910 $20,892
===================================================================
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 by certifying property additions in 2003. The 2004
requirement will be satisfied by certifying property additions. Sinking fund
requirements and/or maturities through 2008 applicable to long-term debt are as
follows: $40.9 million in 2004; $20.8 million in 2005; $20.8 million in 2006;
$0.7 million in 2007; and $45.8 million in 2008.
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.
Bank Credit Arrangements
At the beginning of 2004, credit arrangements with banks totaled $80 million and
expire at various times during 2004, 2005, and 2006. In September 2002, the
Company borrowed $25 million under a $30 million variable rate revolving credit
agreement that terminates in 2005. Of this amount, $5 million was repaid in
December 2003.
In connection with these credit arrangements, the Company agrees to pay
commitment fees based on the unused portions of the commitments. Commitment fees
are less than 1/8 of 1 percent for the Company.
The credit arrangements contain covenants that limit the level of
indebtedness to capitalization to 65 percent, as defined in the agreements.
Exceeding these debt levels would result in a default under the credit
arrangements. In addition, the credit arrangements contain cross default
provisions that would be triggered if the Company 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 $10 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 retail operating companies. Proceeds from such issuances for
the benefit of the Company are loaned directly to the Company and are not
II-278
NOTES (continued)
Savannah Electric and Power Company 2003 Annual Report
commingled with proceeds from such issuances for the benefit of any other retail
operating company. The obligations of each company under these arrangements are
several; there is no cross affiliate credit support. At December 31, 2003, the
Company had no commercial paper and no extendible commercial notes outstanding.
During 2003, the peak amount of commercial paper outstanding was $32.8 million
and the average amount outstanding was $9.1 million. The average annual interest
rate on commercial paper was 1.13 percent.
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, 2003, the amount of variable rate obligations outstanding requiring
liquidity support was $7.7 million.
Financial Instruments
The Company enters into energy related derivatives to hedge exposures to
electricity, gas, and other fuel price changes. However, due to cost-based rate
regulations, the Company has limited exposure to market volatility in commodity
fuel prices and prices of electricity. The Company has implemented fuel-hedging
programs at the instruction of the GPSC. The Company also enters into hedges of
forward electricity sales.
At December 31, 2003, the fair value of derivative energy contracts was
reflected in the financial statements as follows:
Amounts
- ----------------------------------------------------------------
(in thousands)
Regulatory liabilities, net $462
Other comprehensive income -
Net income 1
- ----------------------------------------------------------------
Total fair value $463
================================================================
The fair value gains or losses for cash flow hedges that are recoverable
through the regulatory fuel clauses are recorded as regulatory assets and
liabilities and are recognized in earnings at the same time the hedged items
affect earnings.
The Company enters into derivatives to hedge exposure to interest rate
changes. Derivatives related to variable rate securities or forecasted
transactions are accounted for as cash flow hedges. The derivatives are
generally structured to match the critical terms of the hedged debt instruments;
therefore, no material ineffectiveness has been recorded in earnings.
At December 31, 2003, the Company had $20 million notional amount of
interest rate swaps outstanding with net fair value losses of $0.1 million as
follows:
Cash Flow Hedges
Weighted Average Fair
Fixed Value
Rate Notional Gain/
Maturity Paid Amount (Loss)
- --------------------------------------------------------
(in millions)
2004 2.06% $20 $(0.1)
- --------------------------------------------------------
The fair value gain or loss for cash flow hedges is recorded in other
comprehensive income and is reclassified into earnings at the same time the
hedged items affect earnings. For 2004, pre-tax losses of approximately $0.1
million are expected to be reclassified from other comprehensive income to
interest expense.
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, 2003, approximately
$68 million of retained earnings was restricted against the payment of cash
dividends on common stock under the terms of the Indenture.
In accordance with the PUHCA, the Company is restricted from paying common
dividends from paid-in capital without SEC approval
7. COMMITMENTS
Construction Program
The Company is engaged in a continuous construction program, currently estimated
to total $51.8 million in 2004, $42.6 million in 2005, and $41.3 million in
2006. 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
II-279
NOTES (continued)
Savannah Electric and Power Company 2003 Annual Report
additional generating assets; revised load growth estimates; changes in
environmental regulations; changes in FERC rules and transmission regulations;
increasing costs of labor, equipment, and materials; and cost of capital. The
Company does not have any generating plants under construction. However,
construction related to new transmission and distribution facilities and capital
improvements to existing generation, transmission, and distribution facilities,
including those necessary to meet environmental standards, will continue. At
December 31, 2003, significant purchase commitments were outstanding in
connection with the construction program.
Fuel Commitments
To supply a portion of the fuel requirements of its generating plants, the
Company has entered into long-term commitments for the procurement of fuel. In
most cases, these contracts contain provisions for price escalations, minimum
purchase levels, and other financial commitments. In addition, SCS acts as agent
for the Company, the other retail operating companies, Southern Power, and
Southern Company GAS with regard to natural gas purchases. Natural gas purchase
commitments contain given volumes with prices based on various indices at the
actual time of delivery. Amounts included in the chart below represent estimates
based on New York Mercantile future prices at December 31, 2003. Total estimated
minimum long-term obligations at December 31, 2003 were as follows:
Natural
Year Gas Coal
- ---- -------------------------------------
(in thousands)
2004 $ 867 $31,439
2005 8,651 -
2006 10,491 -
2007 7,620 -
2008 27,640 -
2009 and thereafter 284,097 -
- ---------------------------------------------------------------
Total commitments $339,366 $31,439
===============================================================
Additional commitments for fuel will be required to supply the Company's
future needs.
SCS may enter into various types of wholesale energy and natural gas
contracts acting as an agent for the Company and all of the other Southern
Company retail operating companies, Southern Power, and Southern Company GAS.
Under these agreements, each of the retail operating companies, Southern Power,
and Southern Company GAS may be jointly and severally liable. The
creditworthiness of Southern Power and Southern Company GAS is currently
inferior to the creditworthiness of the retail operating companies. Accordingly,
Southern Company has entered into keep-well agreements with the Company and each
of the retail 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 Company GAS as a contracting party under
these agreements.
Purchased Power Commitments
The Company has entered into long-term commitments for the purchase of
electricity from Southern Power. Estimated total long-term obligations at
December 31, 2003 were as follows:
Year Commitments
- ---- ---------------
(in thousands)
2004 $ 13,221
2005 24,447
2006 27,343
2007 27,354
2008 27,366
2009 and thereafter 171,262
- ---------------------------------------------------------------
Total commitments $290,993
===============================================================
Operating Leases
The Company has rental agreements with various terms and expiration dates.
Rental expenses totaled $0.9 million for 2003, $0.6 million for 2002, and $0.5
million for 2001. Of these amounts, $0.8 million in 2003, $0.5 million in 2002,
and $0.4 million in 2001 related to railcar leases and coal dozers and were
recoverable through the Company's fuel cost recovery clause.
At December 31, 2003, estimated future minimum lease payments for
noncancelable operating leases were as follows:
Year Railcars Other Total
- ---------------------------------------------------------------
(in thousands)
2004 $ 429 $ 415 $ 844
2005 429 368 797
2006 429 331 760
2007 429 327 756
2008 429 306 735
2009 and thereafter 4,035 220 4,255
- ---------------------------------------------------------------
Total minimum payments $6,180 $1,967 $8,147
===============================================================
II-280
8. QUARTERLY FINANCIAL INFORMATION
(UNAUDITED)
Summarized quarterly financial data for 2003 and 2002 are as follows (in
thousands):
Operating Operating Net
Quarter Ended Revenues Income Income
- ----------------------------------------------------------------
March 2003 $68,875 $ 9,015 $ 3,509
June 2003 78,242 13,535 6,296
September 2003 99,115 25,584 14,378
December 2003 67,823 2,323 (1,376)
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
- ----------------------------------------------------------------
The Company's business is influenced by seasonal weather conditions and a
seasonal rate structure, among other factors.
II-281
SELECTED FINANCIAL AND OPERATING DATA 1999-2003
Savannah Electric and Power Company 2003 Annual Report
- ------------------------------------------------------------------------------------------------------------------------------
2003 2002 2001 2000 1999
- ------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands) $314,055 $299,552 $283,852 $295,718 $251,594
Net Income after Dividends
on Preferred Stock (in thousands) $22,807 $22,880 $22,063 $22,969 $23,083
Cash Dividends
on Common Stock (in thousands) $23,000 $22,700 $21,700 $24,300 $25,200
Return on Average Common Equity (percent) 12.46 12.83 12.54 13.13 13.16
Total Assets (in thousands) $709,921 $649,089 $621,023 $615,344 $586,255
Gross Property Additions (in thousands) $40,242 $32,481 $31,296 $27,290 $29,833
- ------------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $186,292 $179,804 $176,918 $174,994 $174,847
Mandatorily redeemable preferred securities - 40,000 40,000 40,000 40,000
Long-term debt 222,493 168,052 160,709 116,902 147,147
- ------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $408,785 $387,856 $377,627 $331,896 $361,994
==============================================================================================================================
Capitalization Ratios (percent):
Common stock equity 45.6 46.4 46.8 52.7 48.3
Mandatorily redeemable preferred securities - 10.3 10.6 12.1 11.0
Long-term debt 54.4 43.3 42.6 35.2 40.7
- ------------------------------------------------------------------------------------------------------------------------------
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+ AA-
Preferred Stock -
Moody's Baa1 Baa1 Baa1 a2 a2
Standard and Poor's BBB+ BBB+ BBB+ BBB+ A-
Unsecured Long-Term Debt -
Moody's A2 A2 A2 - -
Standard and Poor's A A A - -
==============================================================================================================================
Customers (year-end):
Residential 122,128 120,131 117,199 115,646 112,891
Commercial 17,102 16,512 16,121 15,727 15,433
Industrial 90 81 76 75 67
Other 506 494 474 444 417
- ------------------------------------------------------------------------------------------------------------------------------
Total 139,826 137,218 133,870 131,892 128,808
==============================================================================================================================
Employees (year-end): 549 550 550 554 533
- ------------------------------------------------------------------------------------------------------------------------------
II-282
SELECTED FINANCIAL AND OPERATING DATA 1999-2003 (continued)
Savannah Electric and Power Company 2003 Annual Report
- -------------------------------------------------------------------------------------------------------------------------------
2003 2002 2001 2000 1999
- -------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Residential $142,816 $139,262 $123,819 $129,520 $112,371
Commercial 106,072 104,195 100,835 102,116 88,449
Industrial 38,749 32,504 34,971 40,839 32,233
Other 10,108 9,810 9,547 10,147 9,212
- -------------------------------------------------------------------------------------------------------------------------------
Total retail 297,745 285,771 269,172 282,622 242,265
Sales for resale - non-affiliates 5,653 6,354 8,884 4,748 3,395
Sales for resale - affiliates 6,499 4,075 3,205 4,974 4,151
- -------------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 309,897 296,200 281,261 292,344 249,811
Other revenues 4,158 3,352 2,591 3,374 1,783
- -------------------------------------------------------------------------------------------------------------------------------
Total $314,055 $299,552 $283,852 $295,718 $251,594
===============================================================================================================================
Kilowatt-Hour Sales (in thousands):
Residential 1,738,488 1,793,330 1,658,735 1,671,089 1,579,068
Commercial 1,451,342 1,477,224 1,388,357 1,369,448 1,287,832
Industrial 860,351 793,181 787,674 800,150 713,448
Other 136,320 139,891 133,967 135,824 132,555
- -------------------------------------------------------------------------------------------------------------------------------
Total retail 4,186,501 4,203,626 3,968,733 3,976,511 3,712,903
Sales for resale - non-affiliates 162,469 150,795 111,145 77,481 51,548
Sales for resale - affiliates 185,202 125,882 87,799 88,646 76,988
- -------------------------------------------------------------------------------------------------------------------------------
Total 4,534,172 4,480,303 4,167,677 4,142,638 3,841,439
===============================================================================================================================
Average Revenue Per Kilowatt-Hour (cents):
Residential 8.21 7.77 7.46 7.75 7.12
Commercial 7.31 7.05 7.26 7.46 6.87
Industrial 4.50 4.10 4.44 5.10 4.52
Total retail 7.11 6.80 6.78 7.11 6.52
Sales for resale 3.50 3.77 6.08 5.85 5.87
Total sales 6.83 6.61 6.75 7.06 6.50
Residential Average Annual
Kilowatt-Hour Use Per Customer 14,366 15,085 14,241 14,593 14,100
Residential Average Annual
Revenue Per Customer $1,180.17 $1,171.46 $1,063.07 $1,131.08 $1,003.39
Plant Nameplate Capacity
Ratings (year-end) (megawatts) 788 788 788 788 788
Maximum Peak-Hour Demand (megawatts):
Winter 882 738 758 724 719
Summer 904 921 846 878 875
Annual Load Factor (percent) 56.8 54.5 55.9 53.4 51.2
Plant Availability Fossil-Steam (percent): 83.3 81.4 81.2 78.5 72.8
- -------------------------------------------------------------------------------------------------------------------------------
Source of Energy Supply (percent):
Coal 44.7 44.4 50.5 51.6 44.6
Oil and gas 2.7 4.2 4.0 6.9 12.3
Purchased power -
From non-affiliates 3.1 3.1 5.3 7.7 5.3
From affiliates 49.5 48.3 40.2 33.8 37.8
- -------------------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0 100.0 100.0
===============================================================================================================================
II-283
SOUTHERN POWER COMPANY
FINANCIAL SECTION
II-284
MANAGEMENT'S REPORT
Southern Power Company 2003 Annual Report
The management of Southern 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 internal accounting controls are 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
four 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 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/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
March 1, 2004
II-285
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, 2003 and 2002,
and the related statements of income, comprehensive income, common stockholder's
equity, and cash flows for the years then ended, 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-299 through II-312)
present fairly, in all material respects, the financial position of Southern
Power Company at December 31, 2003 and 2002, and the results of its operations
and its cash flows for the years then ended, 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
March 1, 2004
II-286
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Southern Power Company 2003 Annual Report
OVERVIEW OF EARNINGS AND BUSINESS
- ---------------------------------
ACTIVITIES
- ----------
In January 2001, Southern Power Company was formed as a wholly-owned subsidiary
of Southern Company and began commercial operations in August 2001.
Earnings
The Company's 2003 earnings totaled $155 million, representing a $101 million
increase over 2002. The 2003 increase is attributed to increased sales of
wholesale capacity and energy from units placed in service during 2003 (Plant
Franklin Unit 2, Plant Harris Units 1 and 2 and Plant Stanton A) and to a
one-time gain of $50 million recognized in May 2003 upon the termination of
Dynegy, Inc.'s (Dynegy) obligations under Power Purchase Agreements (PPAs). The
increased sales came from new PPAs with Alabama Power and Georgia Power as well
as the marketing of uncontracted capacity. As future PPAs become effective, the
amount of uncontracted capacity available for external sales will decline
significantly. Additional factors contributing to the increased earnings were
non-recurring energy sales transactions related to test period generation for
units placed in service in June 2003, as well as manufacturer's tax credits from
the State of Georgia related to construction of Plants Dahlberg and Wansley. As
of December 31, 2003, the Company had approximately 4,775 megawatts in
commercial operation compared to approximately 2,400 in commercial operation at
December 31, 2002.
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 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 reflected commercial operation of Plant Wansley Units 6 and 7 and
Plant Franklin Unit 1 that began in June 2002 and a full year of Plant Dahlberg
operations.
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.
Business Activities
The Company constructs, owns, and manages Southern Company's competitive
generating assets and sells electricity at market-based rates in the wholesale
market.
Several factors affect the opportunities, challenges, and risks of the
Company's competitive wholesale energy business. These factors include the
ability to achieve energy sales growth while containing costs. Another major
factor is federal regulatory policy, which may impact the Company's level of
participation in this market. Future earnings for the business in the near term
will depend, in part, upon completion of construction on new generating
facilities, regulatory matters, including those related to affiliate contracts,
energy sales, creditworthiness of customers, total generating capacity available
in the Southeast, and the successful remarketing of capacity as current
contracts expire.
RESULTS OF OPERATIONS
- ---------------------
A condensed income statement is as follows:
Increase (Decrease)
Amount From Prior Year
---------------------------------------
2003 2003 2002
- --------------------------------------------------------------------
(in thousands)
Operating revenues $681,780 $383,012 $269,467
- --------------------------------------------------------------------
Fuel 115,256 17,291 94,186
Purchased power 185,301 131,638 48,937
Other operation and
maintenance 62,241 33,890 21,726
Depreciation and
amortization 39,012 20,693 15,028
Taxes other than
income taxes 6,665 2,390 3,882
- --------------------------------------------------------------------
Total operating
expenses 408,475 205,902 183,759
- --------------------------------------------------------------------
Operating income 273,305 177,110 85,708
Other income, net (2,029) 2,841 (5,450)
Less --
Interest expense
and other, net 31,273 22,675 8,249
Income taxes 85,221 56,764 25,946
Cumulative effect of
accounting change 367 367 -
- --------------------------------------------------------------------
Net Income $155,149 $100,879 $ 46,063
====================================================================
II-287
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company 2003 Annual Report
Revenues
Operating revenues in 2003 were $682 million, reflecting a $383 million increase
from 2002. Operating revenues were positively impacted by a full year of energy
and capacity sales through PPAs with Georgia Power and Savannah Electric that
began in June 2002. New PPAs with Alabama Power and Georgia Power that commenced
in June 2003 also contributed to the increase. Additionally, $80 million of
contract termination revenues were recorded, as a result of the May 2003
termination of Dynegy's PPAs related to Plants Dahlberg and Franklin. See
"Future Earnings Potential - Other Matters" and Note 3 to the financial
statements under "Uncontracted Generating Capacity" for additional information.
The remaining increases in operating revenues are a result of wholesale energy
sales to non-affiliated companies under PPAs and through the Southern Company
system power pool (Southern Pool). These sales were possible due to capacity
made available from the commercial operation of Plant Franklin Unit 1 in June
2002, which was not fully obligated under a long-term PPA until June 2003 and
test period energy sales transactions for Plant Franklin Unit 2 and Plant Harris
Units 1 and 2 which were placed into commercial operation in June 2003. Capacity
for Plant Harris Unit 2 is not obligated until June 2004. The Company also
placed Plant Stanton A into commercial operation in October 2003. Other
operating revenue increased by $9.9 million primarily due to transmission
revenues, which were offset by additional transmission expense.
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 Plant Wansley Units 6 and 7 and Plant Franklin Unit 1
beginning in June 2002, and the initiation of PPAs with Georgia Power and
Savannah Electric and requirements agreements with 11 EMCs in June 2002, as well
as a full year of revenue from PPAs at Plant Dahlberg.
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.
Capacity revenues for 2003 were $201.6 million, or 33.4% of total revenues,
excluding $80 million related to termination of contracts with Dynegy. Capacity
revenues for 2002 were $123.9 million, or 41.5% of total revenues. Capacity
revenues for 2001 were $18.6 million, or 63.5% of total revenues. These revenues
are an integral component of the PPAs with both affiliate and non-affiliate
customers.
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 cost.
Expenses
Natural gas fuel costs constitute a significant expense for the Company. The
increase in fuel expense in 2003 is primarily due to the operation of Plant
Wansley Units 6 and 7 and Plant Franklin Unit 1 for a full year, as well as new
units at Plant Franklin and Plant Harris Units 1 and 2 which began operations in
June 2003. In addition, the average cost of natural gas per decatherm increased
24% from 2002 to 2003. The increase in fuel expense in 2002 was primarily due to
the commercial operation of Plant Wansley Units 6 and 7 and Plant Franklin Unit
1 beginning in June 2002, and a full year of operation for Plant Dahlberg. In
addition, the average cost of natural gas per decatherm increased 33% from 2001
to 2002. The Company's PPAs generally provide that the purchasers are
responsible for substantially all of the cost of fuel relating to energy
delivered under such PPAs; therefore, these fuel cost increases do not have a
significant impact on net income.
Purchased power from non-affiliates and affiliates increased by $27 million
and $105 million, respectively, in 2003, and by $33.3 million and $15.6 million,
respectively, in 2002, in all cases 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 generation, affiliate-owned generation or external
purchases. During 2003, purchased power from affiliates increased as a result of
the availability of lower cost generating capacity primarily due to the mild
summer weather in Southern Company's retail service territory.
II-288
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company 2003 Annual Report
In 2003, other operation and maintenance expense increased by $33.9 million
mainly due to increased administrative and general expenses of $12.7 million and
other production expenses of $21.2 million. These increases are primarily
attributed to a full year of operation at Plant Wansley Units 6 and 7 and Plant
Franklin Unit 1, as well as the commercial operation of Plant Franklin Unit 2
and Plant Harris Units 1 and 2 beginning in June 2003.
In 2002, other operation and maintenance expense increased by $21.7 million
mainly due to increased administrative and general expenses of $12.3 million and
other production expenses of $9.4 million. These increases are primarily
attributed to the June 2002 commercial operation of Plant Wansley Units 6 and 7
and Plant Franklin Unit 1.
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 2003 and 2002, depreciation and amortization increased as a direct
result of the commercial operation of Plant Wansley Units 6 and 7 and Plant
Franklin Unit 1 in June 2002 and Plant Franklin Unit 2 and Plant Harris Units 1
and 2 in June 2003. The 2002 increase also reflects a full year of depreciation
related to Plant Dahlberg, which was placed into service in July 2001.
In 2003 and 2002, the increases in taxes other than income taxes relate to
property taxes for the commercial operation of Plant Wansley Units 6 and 7 and
Plant Franklin Unit 1 in June 2002 and Plant Franklin Unit 2 and Plant Harris
Units 1 and 2 in June 2003. The 2002 increase also reflects a full year of Plant
Dahlberg's property taxes.
Interest expense in 2003 increased by $22.7 million from the amount
recorded in 2002. This increase is primarily attributed to a lower percentage of
interest costs being capitalized as projects have reached completion and an
increase in the amount of long-term debt outstanding. Interest expense in 2002
increased by $8.2 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.
Changes in other income, net in 2003 and 2002 resulted primarily from
unrealized gains and losses on derivative energy contracts. See "Financial
Condition and Liquidity - Market Price Risk" herein and Notes 1 and 6 to the
financial statements under "Financial Instruments."
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 the past three years are not necessarily
indicative of future earnings potential. Several factors affect the
opportunities, challenges, and risks of the Company's competitive wholesale
energy business. These factors include the ability to achieve energy sales
growth while containing costs. Another major factor is federal regulatory
policy, which may impact the Company's level of participation in this market.
The level of future earnings depends on numerous factors including completion of
construction on new generating facilities, regulatory matters, including those
related to affiliate contracts, energy sales, creditworthiness of customers,
total generating capacity available in the Southeast, and the successful
remarketing of capacity as current contracts expire.
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 6,000 megawatts of available generating capacity in
commercial operation. At December 31, 2003, 4,775 megawatts were in commercial
operation.
Although under some of the Company's PPAs energy will be sold to Southern
Company's five retail operating companies, the Company's generating facilities
will not be in the retail operating companies' regulated rate bases, and the
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company 2003 Annual Report
Company will not be able to seek recovery from the affiliated companies'
ratepayers for construction, repair, environmental 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 PPAs. 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 (a) Standard & Poor's or Moody's downgrades the credit ratings of
such counterparty to below investment grade, or, (b) 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.
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 (GE) to reduce its exposure to certain
O&M costs relating to GE equipment.
FERC Matters
Market-Based Rate Authority
The Company currently has general authorization from the Federal Energy
Regulatory Commission (FERC) to sell power to nonaffiliates at market-based
prices. In addition, each of the retail operating companies has obtained FERC
approval to sell power to nonaffiliates at market-based prices under specific
contracts. Southern Power and the retail operating companies also have FERC
authority to make short-term opportunity sales at market rates. Specific FERC
approval must be obtained with respect to a market-based contract with an
affiliate. In November 2001, the FERC modified the test it uses to consider
utilities' applications to charge market-based rates and adopted a new test
called the Supply Margin Assessment (SMA). The FERC applied the SMA to several
utilities, including Southern Company's retail operating companies, and found
them to be "pivotal suppliers" in their service areas and ordered the
implementation of several mitigation measures. SCS, on behalf of the retail
operating companies and others sought rehearing of the FERC order, and the FERC
delayed the implementation of certain mitigation measures. SCS, on behalf of the
retail operating companies and others submitted comments to the FERC in 2002
regarding these issues. In December 2003, the FERC issued a staff paper
discussing alternatives and held a technical conference in January 2004.
Southern Company anticipates that the FERC will address the requests for
rehearing in the near future. Regardless of the outcome of the SMA proposal, the
FERC retains the ability to modify or withdraw the authorization for any seller
to sell at market-based rates, if it determines that the underlying conditions
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. The final
outcome of this matter will depend on the form in which the SMA test and
mitigation measures rules may be ultimately adopted and cannot be determined at
this time.
PPAs by Georgia Power and Savannah Electric for the Company's Plant
McIntosh capacity were certified by the Georgia Public Service Commission (GPSC)
in December 2002 after a competitive bidding process. In April 2003, the Company
applied for FERC approval of these PPAs. Interveners opposed the FERC's
acceptance of the PPAs, alleging that the PPAs do not meet the applicable
standards for market-based rates between affiliates. In July 2003, the FERC
accepted the PPAs to become effective as scheduled on June 1, 2005, subject to
refund, and ordered that hearings be held to determine: (a) whether, in the
design and implementation of the GPSC competitive bidding process, Georgia Power
and Savannah Electric unduly preferred the Company; (b) whether the analysis of
the competitive bids unduly favored the Company, particularly with respect to
evaluation of non-price factors; (c) whether Georgia Power and Savannah Electric
selected their affiliate, the Company, based upon a reasonable combination of
price and non-price factors; (d) whether the Company received an undue
preference or competitive advantage in the competitive bidding process as a
result of access to its affiliate's transmission system; (e) whether and to what
extent the PPAs impact wholesale competition; and (f) whether the PPAs are just
and reasonable and not unduly discriminatory. Hearings are scheduled to begin in
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company 2003 Annual Report
March 2004. Management believes that the PPAs should be approved by the FERC;
however, the ultimate outcome of this matter cannot now be determined.
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 allowed
independent power producers to access a utility's transmission network in order
to sell electricity to other utilities.
Since 2001, merchant energy companies and traditional electric utilities
with significant energy marketing and trading activities have come 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 adverse 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, which is optimized by limited energy trading
activities.
Power Sales Agreements
In June 2003, the Company placed Plant Franklin Unit 2 and Plant Harris Units 1
and 2 into commercial operation. In October 2003, the Company placed Plant
Stanton A into commercial operation. In June 2004, the Company's PPA with
Georgia Power will begin for Plant Harris Unit 2. PPAs for the other units
became effective upon commercial operation. The Company also has Plant McIntosh
Units 10 and 11 under construction. Most of the Company's generating capacity in
operation, under construction, or planned has been sold under PPAs.
In June 2002, PPAs with Georgia Power and Savannah Electric and
requirements agreements with 11 EMCs went into effect upon the commercial
operation of Plant Wansley Units 6 and 7 and Plant Franklin Unit 1.
Also, effective in January 2003, the Company entered into contracts with
North Carolina Municipal Power Authority 1 (NCMPA) and the City of Dalton
(Dalton). Under the NCMPA contract, the Company is responsible for supplying
NCMPA's capacity and energy needs in excess of its existing resources and
disposing of its surplus energy 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 for the next 15
years, with a customer option to convert to a fixed capacity purchase at the end
of year 10.
In July 2003, the Company entered into a requirements service
agreement with Piedmont Municipal Power Agency (PMPA). PMPA is a full
requirements provider to 10 South Carolina cities. Under this agreement, the
Company will be responsible for supplying PMPA's capacity and energy needs in
excess of PMPA's existing resources and will purchase PMPA's surplus energy. The
initial contract term is for 5 years beginning in 2006 with mutual renewal
options through 2015.
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 6/05-5/20
---------------------------------------------------------
Total Affiliated 4,796
---------------------------------------------------------
Non-Affiliated
--------------
Dahlberg Units 1-7 578 6/00-12/04
Stanton A 396 11/03-11/13
---------------------------------------------------------
Total Non-affiliated 974
---------------------------------------------------------
* According to the original contract terms
** 370 megawatts during the first year
*** 400 megawatts during the first year
**** Contract does not begin until second year of
operation of Plant Harris Unit 2.
Capacity revenues from these long-term power sales agreements amounted to
$201.6 million, $123.9 million, and $18.6 million for the periods ended
December 31, 2003, 2002, and 2001, respectively. Forecasted future capacity
revenues under existing PPAs are expected to total $3.3 billion for affiliated
contracts and $1.1 billion for non-affiliated contracts. These capacity
revenues will
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company 2003 Annual Report
continue to represent approximately 40% of total annual revenues through 2007.
At that point, as certain existing contracts reach termination, assuming no new
contracts, capacity revenues are expected to decline to approximately 25% of
total annual revenues. Consistent with the Company's strategy to sell energy
under long-term contracts, capacity payments will continue to be an integral `
part of future contract negotiations. As such, capacity revenues will continue
to be a significant portion of annual revenues.
Environmental Matters
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 may involve significant costs.
Such environmental, natural resource and land use concerns, including the
applicability of air quality limitations, the availability of water withdrawal
rights, uncertainties regarding aesthetic impacts such as increased light or
noise, and concerns about potential adverse health impacts, can also increase
the cost of siting and operating any type of future electric generating
facility.
Federal and state environmental regulatory agencies are actively
considering and developing additional control strategies for emission of air
pollution from industrial sources, including electric generating facilities.
Among the various air quality matters being planned or considered for regulation
by the federal Environmental Protection Agency and/or relevant state agencies
are: designation of new target areas as non-attainment for ozone and particulate
matter under applicable federal air quality standards; the reduction of nitrogen
oxide and particulate matter emissions to reduce regional haze and visibility
impairment in sensitive areas; proposed reductions in sulfur dioxide and
nitrogen oxide emissions to reduce interstate transport of such pollutants;
regulations addressing the construction or modification of sources of regulated
pollutants; 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 further substantial reductions in all air emissions associated
with electricity generation.
Federal and state environmental regulatory agencies are also reviewing and
evaluating various other matters, including hazardous waste disposal
requirements, requirements for cooling water intake structures and establishment
of total pollutant loads for certain impaired waters. The impact of any new
standards or requirements 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. In 2003, several major bills to amend the
Clean Air Act to impose more stringent emissions limitations were proposed to
further limit power plant emissions of sulfur dioxide, nitrogen oxides, mercury,
and, in some cases, carbon dioxide. The cost impacts of such legislation would
depend upon the specific requirements enacted and cannot be determined at this
time.
Compliance with possible additional federal or state legislation or
regulations related to global climate change or other environmental and health
concerns could also significantly affect the Company. The impact of any new
legislation, changes to existing legislation, or environmental regulations could
affect many areas of the Company's operations. While all of the Company's PPAs
generally contain provisions that permit charging the purchaser with some of the
new costs incurred as a result of changes in environmental laws and regulations,
the full impact of any such regulatory or legislative changes cannot be
determined at this time.
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 against the Company cannot be predicted at this time; however,
management does not anticipate that the liabilities, if any, arising from such
current proceedings would have a material adverse effect on the Company's
financial statements.
Other Matters
On May 21, 2003, the Company entered into an agreement with Dynegy that resolved
and terminated in 2003 all outstanding matters related to capacity sales
contracts with subsidiaries of Dynegy. The termination payments from Dynegy
resulted in a one-time gain to the Company of approximately $50 million. As a
result of the Dynegy capacity contract terminations, the Company is completing
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company 2003 Annual Report
limited construction activities on Plant Franklin Unit 3 to preserve the
long-term viability of the project but has deferred final completion until the
2008-2011 period. The length of the deferral period will depend on forecasted
capacity needs and other wholesale market opportunities. The Company is
continuing to explore alternatives for its existing uncontracted capacity. See
Note 3 to the financial statements under "Uncontracted Generating Capacity" for
additional information.
The Company is involved in various matters being litigated and regulatory
matters that could affect future earnings. See Note 3 to the financial
statements for information regarding material issues.
ACCOUNTING POLICIES
- -------------------
Application of Critical Accounting Policies and
Estimates
The Company prepares its consolidated financial statements in accordance with
accounting principles generally accepted in the United States. Significant
accounting policies are described in Note 1 to the financial statements. In the
application of these policies, certain estimates are made that may have a
material impact on the Company's results of operations and related disclosures.
Different assumptions and measurements could produce estimates that are
significantly different from those recorded in the financial statements. Senior
management has discussed the development and selection of the critical
accounting policies and estimates described below with the Audit Committee of
Southern Company's Board of Directors.
Revenue Recognition
The Company's revenue recognition depends on appropriate classification and
documentation of transactions in accordance with Financial Accounting Standards
Board (FASB) Statement No. 133, Accounting for Derivative Instruments and
Hedging Activities, as amended and interpreted. In general, the Company's power
sale transactions can be classified in one of four categories: non-derivatives,
normal sales, cash flow hedges, and mark to market. For more information on
derivative transactions, see "Financial Condition and Liquidity - Market Price
Risk" and Notes 1 and 6 to the financial statements under "Financial
Instruments." The Company's revenues are dependent upon significant judgments
used to determine the appropriate transaction classification, which must be
documented upon the inception of each contract. Factors that must be considered
in making these determinations include:
o Assessing whether a sales contract meets the definition
of a lease
o Assessing whether a sales contract meets the definition
of a derivative
o Assessing whether a sales contract meets the definition
of a capacity contract
o Assessing the probability at inception and throughout
the term of the individual contract that the contract will
result in physical delivery
o Ensuring that the contract quantities do not exceed
available generating capacity
o Identifying the hedging instrument, the hedged
transaction, and the nature of the risk being hedged
o Assessing hedge effectiveness at inception and
throughout the contract term.
Normal Sale and Non-Derivative Transactions
- -------------------------------------------
The Company considers derivative contracts, including capacity contracts, that
provide for the sale of electricity to be physically delivered in quantities
less than the Company's available generating capacity to be normal sales. In
accordance with Statement No. 133, such transactions are accounted for as
executory contracts and are not subject to mark to market accounting. Therefore,
the related revenue is recognized, in accordance with Emerging Issues Task Force
(EITF) No. 91-6, Revenue Recognition of Long-Term Power Sales Contracts, on an
accrual basis in amounts equal to the lesser of the levelized amount or the
amount billable under the contract, over the respective contract periods.
Revenues from transactions that do not meet the definition of a derivative are
also recorded in this manner. Contracts recorded on the accrual basis
represented the majority of the Company's operating revenues for the year ended
December 31, 2003.
Cash Flow Hedge Transactions
- ----------------------------
The Company has designated other derivative contracts for sales of electricity
as cash flow hedges of anticipated sale transactions. These contracts are marked
to market through Other Comprehensive Income over the life of the contract.
Realized gains and losses are then recognized in revenues as incurred. At
December 31, 2003, approximately $1 million in unrealized gains (losses) were
deferred in Other Comprehensive Income.
Mark to Market Transactions
- ---------------------------
Contracts for sales of electricity that are not normal sales and are not
designated as cash flow hedges are marked to market and recorded directly
II-293
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company 2003 Annual Report
through net income. Net unrealized losses on such contracts totaled
approximately $1.9 million for the year ended December 31, 2003.
Asset Impairments
The Company's investments in long-lived assets are primarily generation assets,
whether in service or under construction. The Company evaluates the carrying
value of these assets under FASB Statement No. 144, Accounting for the
Impairment or Disposal of Long-lived Assets, whenever indicators of potential
impairment exist. Examples of impairment indicators could include significant
changes in construction schedules, current period losses combined with a history
of losses, or a projection of continuing losses or a significant decrease in
market prices. If an indicator exists, the asset is tested for recoverability by
comparing the asset carrying value to the sum of the undiscounted expected
future cash flows directly attributable to the asset. A high degree of judgment
is required in developing estimates related to these evaluations, which are
based on projections of various factors, including the following:
o Future demand for electricity based on projections of economic growth and
estimates of available generating capacity
o Future power and natural gas prices, which have been quite volatile in
recent years
o Future operating costs.
To date, the Company's evaluations of its assets have not required any
impairment to be recorded. See Note 3 to the financial statements under
"Uncontracted Generating Capacity" for additional information.
New Accounting Standards
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
established 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 is recorded in the
period in which the liability is incurred. The costs are capitalized as part of
the related long-lived asset and depreciated over the asset's useful life.
Additionally, non-regulated companies are no longer permitted 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 ($0.4 million after-tax). This represents removal costs accrued prior to
the implementation of Statement No. 143.
FASB Statement No. 149, Amendment of Statement 133 on Derivative
Instruments and Hedging Activities, which further amends and clarifies the
accounting and reporting for derivative instruments, became effective generally
for financial instruments entered into or modified after June 30, 2003. Current
interpretations of Statement No. 149 indicate that certain electricity forward
transactions subject to unplanned netting -- including those typically referred
to as "book outs" -- may only qualify as cash flow hedges if an entity can
demonstrate that physical delivery or receipt of power occurred. The Company's
forward electricity contracts continue to be exempt from fair value accounting
requirements or to qualify as cash flow hedges, with the related gains and
losses deferred in other comprehensive income. The implementation of Statement
No. 149 did not have a material effect on the Company's financial statements.
In July 2003, the EITF of FASB issued EITF No. 03-11, which became
effective on October 1, 2003. The standard addresses the reporting of realized
gains and losses on derivative instruments and is being interpreted to require
book outs to be recorded on a net basis in operating revenues. Adoption of this
standard did not have a material impact on the Company's financial statements.
FINANCIAL CONDITION AND LIQUIDITY
- ---------------------------------
Overview
The major change in the Company's financial condition during 2003 was the
addition of approximately $344.4 million to utility plant related to on-going
construction of combined-cycle units. The funds for these additions were
provided by the Company's credit facility, the issuance of senior notes in July
2003, commercial paper, capital contributions and subordinated loans from
Southern Company, and internally generated cash from operations. The Statements
of Cash Flows provide additional information.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company 2003 Annual Report
Sources of Capital
The Company will use external funds, equity capital from Southern Company and
internally generated cash from operations 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.
Currently, Southern Company provides limited credit support to the Company.
See Note 6 to the financial statements under "Bank Credit Arrangements" for
additional information. The Southern Company system does not maintain a
centralized cash or money pool. Therefore, funds of each company are not
commingled with funds of any other company. In accordance with the Public
Utility Holding Company Act, most loans between affiliated companies must be
approved in advance by the Securities and Exchange Commission (SEC).
The Company's current liabilities frequently exceed current assets because
of the continued use of short-term debt as an interim funding source for the
Company's ongoing construction program and the seasonality of the electricity
business.
At December 31, 2003, the Company had approximately $2.8 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,
2003, $650 million of unused committed credit arrangements with banks as shown
in the following table.
At the beginning of 2004, bank arrangements are as follows:
Expires
--------------------------------
Total Unused 2004 2005 & beyond
- -------------------------------------------------------------
(in millions)
$650 $650 $-- $650
- -------------------------------------------------------------
The $650 million of unused credit arrangements is committed to provide
liquidity support to the Company's commercial paper program. The commercial
paper program is used to finance acquisition and construction costs related to
gas-fired electric generating facilities and for general corporate purposes,
subject to borrowing limitations for each generating facility. The credit
arrangements permit the Company to fund construction of future generating
facilities upon meeting certain requirements. At December 31, 2003, the Company
had $114.3 million in outstanding commercial paper. See Note 6 to the financial
statements for additional information.
Financing Activities
During 2003, the Company repaid subordinated loans from Southern Company of
approximately $20 million, net of additional borrowings. In March 2003, $190
million of notes payable to Southern Company were converted to a capital
contribution from Southern Company. In September 2003, the SEC approved the
Company's payment of dividends in an amount up to $190 million to Southern
Company from capital surplus. The first such dividend of $77 million, recorded
as a reduction of paid-in capital, was made in October 2003. Equity
contributions and subordinated loans from Southern Company totaled $850 million
at the end of 2003.
In July 2003, the Company issued $575 million of senior notes. The proceeds
from the sale were used to repay a substantial portion of existing short-term
indebtedness, to settle interest rate hedges associated with such senior notes
and for general corporate purposes. See Note 6 to the financial statements under
"Long-Term Debt" and "Financial Instruments" for further information. The
interest rate swap agreements that the Company entered into in anticipation of
this issuance were settled at a $93.3 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.
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
purchases and sales, fixed-price physical gas purchases and agreements covering
interest rate swaps. At December 31, 2003, the maximum potential collateral
requirements under the electricity sales contracts were approximately $161
million. Generally, collateral may be provided for by a Southern Company
guaranty, a letter of credit, or cash. At December 31, 2003, there were no
material collateral requirements for the gas purchase contracts.
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company 2003 Annual Report
Market Price Risk
The Company is exposed to market risks, including changes in interest rates,
certain energy-related commodity prices, and, occasionally, currency exchange
rates. 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.
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 sale of 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 applicable date of the transfers. These contracts were recorded at fair
value on the applicable date of the transfer, which was equal to Georgia Power's
carrying amount. Following the transfer, these contracts were marked to market
through income until realized and settled in August 2003.
In prior years, to reduce its exposure to fluctuations in the exchange rate
for Euros, the Company entered into forward Euro purchase contracts designated
as fair value hedges of certain firm equipment purchase commitments that
required payment in Euros. As of May 2003, all Euro payments have been made and
the resulting gains associated with the hedges effectively reduced the purchase
price of the equipment, which is included in plant-in-service or construction
work in progress.
The fair value of changes in derivative energy contracts and year-end
valuations were as follows at December 31:
Changes in Fair Value
-----------------------------------------------------------
2003 2002
-----------------------------------------------------------
(in thousands)
Contracts beginning of year $3,864 $ 5,496
Contracts realized or settled (4,416) (4,336)
New contracts at inception - 1,576
Current period changes 1,217 1,128
-----------------------------------------------------------
Contracts end of year $ 665 $ 3,864
===========================================================
At December 31, 2003, all of these contracts are actively quoted and mature
within one year.
Unrealized pre-tax 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, 2003, the fair
value of derivative energy contracts was as follows:
Amounts
- -------------------------------------------------------------------
(in thousands)
Other comprehensive income $ 950
Net income (285)
- -------------------------------------------------------------------
Total fair value $ 665
===================================================================
Approximately $(1.9) million, $(4.9) million and $0.6 million of unrealized
pre-tax gains (losses) were recognized in income in 2003, 2002, and 2001,
respectively. The Company is exposed to market-price risk in the event of
nonperformance by counterparties 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 6 to the financial statements under "Financial Instruments."
At December 31, 2003, the Company had no variable long-term debt
outstanding. Therefore, there would be no effect on annualized interest expense
related to long-term debt if the Company sustained a 100 basis point change in
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MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company 2003 Annual Report
interest rates. 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 6 to the financial statements under the
heading "Financial Instruments" for additional information.
Capital Requirements and Contractual Obligations
The construction program of the Company is currently estimated to be $259
million for 2004, $254 million for 2005, and $355 million for 2006. Actual
construction costs may vary from these estimates because of changes in factors
such 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. The
Company has approximately 1,240 megawatts of new generating capacity scheduled
to be placed in service by 2005.
Other funding requirements related to obligations associated with scheduled
maturities of long-term debt, as well as the related interest, leases, and other
purchase commitments are as follows. See Notes 1, 6, and 7 to the financial
statements for additional information.
2005- 2007- After
2004 2006 2008 2008 Total
- ---------------------------------------------------------------------------------------------------------------------
(in millions)
Long-term debt(a) --
Principal $0.2 $0.4 $1.3 $1,150.0 $1,151.9
Interest 64.1 128.1 128.0 340.0 660.2
Operating leases 0.3 0.7 0.7 9.7 11.4
Purchase commitments(b) --
Capital(c) 259.4 609.4 - - 868.8
Natural gas(d) 95.2 101.0 56.0 430.8 683.0
Long-term service agreements 17.5 42.7 75.8 694.7 830.7
- ---------------------------------------------------------------------------------------------------------------------
Total $436.7 $882.3 $261.8 $2,625.2 $4,206.0
=====================================================================================================================
(a) All amounts are reflected based on final maturity dates. The Company will continue to retire higher-cost securities
and replace these obligations with lower-cost capital if market conditions permit.
(b) The Company generally does not enter into non-cancelable commitments for other operation and maintenance expenditures.
Total other operation and maintenance expenses for the last three years were $62.2 million, $28.4 million, and $6.6
million, respectively.
(c) The Company forecasts capital expenditures over a three-year period. Amounts represent current estimates of total
expenditures. At December 31, 2003, significant purchase commitments were outstanding in connection with the
construction program.
(d) Natural gas purchase commitments are based on various indices at the time of delivery. Amounts reflected have been
estimated based on New York Mercantile future prices at December 31, 2003.
II-297
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company 2003 Annual Report
Cautionary Statement Regarding Forward-Looking Information
The Company's 2003 Annual Report includes forward-looking statements in addition to historical information. Forward-looking
information includes, among other things, statements concerning the strategic goals for the Company, estimated construction
and other expenditures, and the Company's projections for energy sales and its goals for future generating capacity, 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. 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:
o 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, tax and
other laws and regulations to which the Company is subject, as well as changes in application of existing laws and regulations;
o current and future litigation, regulatory investigations, proceedings or inquiries;
o the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates;
o the impact of fluctuations in commodity prices, interest rates, and customer demand;
o available sources and costs of fuels;
o ability to control costs;
o advances in technology;
o state and federal rate regulations;
o effects of and changes in political, legal, and economic conditions and developments in the United States, including the
current soft economy;
o internal restructuring or other restructuring options that may be pursued;
o potential business strategies, including acquisitions or dispositions of assets, which cannot be assured to be completed or
beneficial to the Company;
o the ability of counterparties of the Company to make payments as and when due;
o the ability to obtain new short- and long-term contracts with neighboring
utilities;
o 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;
o financial market conditions and the results of financing efforts, including the Company's credit ratings;
o the ability of the Company to obtain additional generating capacity at competitive prices;
o weather and other natural phenomena;
o the direct or indirect effects on the Company's business resulting from the August 2003 power outage in the Northeast, or any
similar such incidents;
o the effect of accounting pronouncements issued periodically by standard-setting bodies; and
o other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed from time to time by the
Company with the SEC.
II-298
STATEMENTS OF INCOME
For the Years Ended December 31, 2003 and 2002
and for the Period from January 8, 2001 (Inception) to December 31, 2001
Southern Power Company 2003 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------------
2003 2002 2001
- ----------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Revenues:
Sales for resale --
Non-affiliates $278,559 $114,919 $26,390
Affiliates 312,586 183,111 2,906
Contract termination 80,000 - -
Other revenues 10,635 738 5
- ----------------------------------------------------------------------------------------------------------------------------------
Total operating revenues 681,780 298,768 29,301
- ----------------------------------------------------------------------------------------------------------------------------------
Operating Expenses:
Fuel 115,256 97,965 3,779
Purchased power --
Non-affiliates 61,234 34,499 1,209
Affiliates 124,067 19,164 3,517
Other operations 50,852 23,800 6,243
Maintenance 11,389 4,551 382
Depreciation and amortization 39,012 18,319 3,291
Taxes other than income taxes 6,665 4,275 393
- ----------------------------------------------------------------------------------------------------------------------------------
Total operating expenses 408,475 202,573 18,814
- ----------------------------------------------------------------------------------------------------------------------------------
Operating Income 273,305 96,195 10,487
Other Income and (Expense):
Interest income 435 288 78
Interest expense, net of amounts capitalized (31,708) (8,886) (427)
Other income (expense), net (2,029) (4,870) 580
- ----------------------------------------------------------------------------------------------------------------------------------
Total other income and (expense) (33,302) (13,468) 231
- ----------------------------------------------------------------------------------------------------------------------------------
Earnings Before Income Taxes 240,003 82,727 10,718
Income taxes 85,221 28,457 2,511
- ----------------------------------------------------------------------------------------------------------------------------------
Earnings Before Cumulative Effect of Accounting Change 154,782 54,270 8,207
Cumulative effect of accounting change--
less income taxes of $231 367 - -
- ----------------------------------------------------------------------------------------------------------------------------------
Net Income $155,149 $54,270 $ 8,207
==================================================================================================================================
The accompanying notes are an integral part of these financial statements.
II-299
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2003 and 2002
and for the Period from January 8, 2001 (Inception) to December 31, 2001
Southern Power Company 2003 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------------
2003 2002 2001
- ----------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Operating Activities:
Net income $155,149 $ 54,270 $8,207
Adjustments to reconcile net income
to net cash provided from operating activities --
Depreciation and amortization 43,712 18,319 3,291
Deferred income taxes and investment tax credits, net 22,521 2,739 3,534
Deferred capacity revenues 9,997 13,071 -
Tax benefit of stock options 130 499 -
Settlement of interest rate hedges (93,298) (16,884) -
Other, net (25,787) (1,618) (580)
Changes in certain current assets and liabilities --
Receivables, net (7,008) (12,433) (5,381)
Fossil fuel stock 5,232 (7,606) (3,425)
Materials and supplies (1,570) (822) (5,731)
Other current assets (9,675) (3,913) (183)
Accounts payable 32,694 8,628 2,242
Accrued taxes (6,939) 7,834 394
Accrued interest 9,299 20,713 -
Other current liabilities 236 - 6,236
- ----------------------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities $134,693 82,797 8,604
- ----------------------------------------------------------------------------------------------------------------------------------
Investing Activities:
Gross property additions (344,362) (1,214,677) (765,511)
Change in construction payables, net (16,931) 3,229 28,171
Other - (669) (10,126)
- ----------------------------------------------------------------------------------------------------------------------------------
Net cash used for investing activities (361,293) (1,212,117) (747,466)
- ----------------------------------------------------------------------------------------------------------------------------------
Financing Activities:
Increase (decrease) in notes payable, net - affiliated (20,488) 209,538 950
Increase (decrease) in notes payable, net 114,347 1,638 -
Proceeds --
Senior notes 575,000 575,000 -
Other long-term debt - 87,873 293,205
Capital contributions from parent company 5,953 278,634 452,097
Retirements --
Other long-term debt (379,640) - -
Capital distributions to parent company (77,000) - -
Other (8,248) (7,600) (3,679)
- ----------------------------------------------------------------------------------------------------------------------------------
Net cash provided from financing activities 209,924 1,145,083 742,573
- ----------------------------------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents (16,676) 15,763 3,711
Cash and Cash Equivalents at Beginning of Period 19,474 3,711 -
- ----------------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ 2,798 $ 19,474 $3,711
==================================================================================================================================
Supplemental Cash Flow Information:
Cash paid during the period for --
Interest (net of $36,736, $35,311 and $2,891 capitalized,
respectively) $105,765 $ 16,884 $ 427
Income taxes (net of refunds) 77,993 25,626 (423)
- ----------------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
II-300
BALANCE SHEETS
At December 31, 2003 and 2002
Southern Power Company 2003 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------------
Assets 2003 2002
- -----------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Current Assets:
Cash and cash equivalents $ 2,798 $ 19,474
Receivables --
Customer accounts receivable 10,772 6,609
Affiliated companies 14,130 11,555
Accumulated provision for uncollectible accounts (350) (350)
Other accounts receivable 270 -
Fossil fuel stock, at average cost 5,798 11,031
Materials and supplies, at average cost 8,123 6,553
Prepaid income taxes 11,222 -
Prepaid expenses 2,528 627
Assets from risk management activities 1,154 8,386
Other 20 1,568
- -----------------------------------------------------------------------------------------------------------------------------------
Total current assets 56,465 65,453
- -----------------------------------------------------------------------------------------------------------------------------------
Property, Plant, and Equipment:
In service 1,831,139 896,163
Less accumulated provision for depreciation 60,005 21,590
- -----------------------------------------------------------------------------------------------------------------------------------
1,771,134 874,573
Construction work in progress 504,097 1,082,987
- -----------------------------------------------------------------------------------------------------------------------------------
Total property, plant, and equipment 2,275,231 1,957,560
- -----------------------------------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets:
Unamortized debt issuance expense 18,315 12,177
Accumulated deferred income taxes 21,911 38,591
Prepaid maintenance expenses 21,728 6,269
Prepaid transmission expenses - affiliated 12,790 1,900
Other 2,845 4,026
- -----------------------------------------------------------------------------------------------------------------------------------
Total deferred charges and other assets 77,589 62,963
- -----------------------------------------------------------------------------------------------------------------------------------
Total Assets $2,409,285 $2,085,976
===================================================================================================================================
The accompanying notes are an integral part of these financial statements.
II-301
BALANCE SHEETS
At December 31, 2003 and 2002
Southern Power Company 2003 Annual Report
- -----------------------------------------------------------------------------------------------------------------------------------
Liabilities and Stockholder's Equity 2003 2002
- -----------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Current Liabilities:
Securities due within one year $ 200 $ 200
Notes payable 114,347 -
Notes payable to parent - 210,488
Accounts payable --
Affiliated 51,442 37,748
Other 6,591 4,522
Accrued taxes --
Income taxes - 3,915
Other 1,289 4,313
Accrued interest 30,012 20,713
Other 489 3,484
- -----------------------------------------------------------------------------------------------------------------------------------
Total current liabilities 204,370 285,383
- -----------------------------------------------------------------------------------------------------------------------------------
Long-Term Debt:
Senior notes
6.25% due 2012 575,000 575,000
4.875% due 2015 575,000 -
Other long-term debt 1,685 382,089
Unamortized debt premium (discount), net (2,573) (1,210)
- -----------------------------------------------------------------------------------------------------------------------------------
Long-term debt 1,149,112 955,879
- -----------------------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities:
Obligations under risk management activities - 63,191
Deferred capacity revenues --
Affiliated 28,799 13,075
Other 256 5,982
Other --
Affiliated 15,061 15,644
Other 211 218
- -----------------------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 44,327 98,110
- -----------------------------------------------------------------------------------------------------------------------------------
Total liabilities 1,397,809 1,339,372
- -----------------------------------------------------------------------------------------------------------------------------------
Common stockholder's equity:
Common stock, par value $0.01 per share --
Authorized - 1,000,000 shares
Outstanding - 1,000 shares
Paid-in capital 850,312 731,230
Retained earnings 217,626 62,477
Accumulated other comprehensive income (loss) (56,462) (47,103)
- -----------------------------------------------------------------------------------------------------------------------------------
Total common stockholder's equity 1,011,476 746,604
- -----------------------------------------------------------------------------------------------------------------------------------
Total Liabilities and Stockholder's Equity $2,409,285 $2,085,976
===================================================================================================================================
Commitments and Contingent Matters (See notes)
- -----------------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
II-302
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
For the Years Ended December 31, 2003 and 2002 and
for the Period from January 8, 2001 (Inception) to December 31, 2001
Southern Power Company 2003 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------
Other
Common Paid-In Retained Comprehensive
Stock Capital Earnings Income (loss) Total
- ----------------------------------------------------------------------------------------------------------------------------
(in thousands)
Balance at January 8, 2001 $ - $ - $ - $ - $ -
Net income - - 8,207 - 8,207
Capital contributions from parent company - 452,097 - - 452,097
Other comprehensive income (loss) - - - 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 income (loss) - - - (53,792) (53,792)
- ----------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2002 - 731,230 62,477 (47,103) 746,604
Net income - - 155,149 - 155,149
Conversion of parent company debt to equity - 190,000 - - 190,000
Capital distributions to parent company - (77,000) - - (77,000)
Capital contributions from parent company - 6,082 - - 6,082
Other comprehensive income (loss) - - - (9,359) (9,359)
- ----------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2003 $ - $850,312 $217,626 ($56,462) $1,011,476
============================================================================================================================
The accompanying notes are an integral part of these financial statements.
STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2003 and 2002 and for the Period
from January 8, 2001 (Inception) to December 31, 2001
Southern Power Company 2003 Annual Report
- ------------------------------------------------------------------------------------------------------------------------------
2003 2002 2001
- ------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Net income $155,149 $54,270 $ 8,207
- ------------------------------------------------------------------------------------------------------------------------------
Other comprehensive income (loss):
Changes in fair value of qualifying hedges, net of tax of
$(7,872), $(34,030), and $4,219, respectively (12,788) (54,360) 6,689
Less: Reclassification adjustment for amounts included in net income,
net of tax of $1,868 and $355, respectively 3,429 568 -
- ------------------------------------------------------------------------------------------------------------------------------
Total other comprehensive income (loss) (9,359) (53,792) 6,689
- ------------------------------------------------------------------------------------------------------------------------------
Comprehensive Income $145,790 $478 $14,896
==============================================================================================================================
The accompanying notes are an integral part of these financial statements.
II-303
NOTES TO FINANCIAL STATEMENTS
Southern Power Company 2003 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING
POLICIES
General
Southern Power Company (the Company) is a wholly owned subsidiary of Southern
Company, which is also the parent company of five retail operating companies,
Southern Company Services (SCS), Southern Communication 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 retail
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. The Company constructs,
owns and manages Southern Company's competitive generation assets and sells
electricity at market-based rates in the wholesale market. Contracts among the
retail operating companies and the Company -- 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, the system
service company, provides, at cost, specialized services to Southern Company and
subsidiary companies. Southern LINC provides digital wireless communications
services to the retail 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 is a competitive retail natural gas
marketer serving customers in Georgia. Southern Holdings is an intermediate
holding subsidiary for Southern Company's investments in synthetic fuels and
leveraged leases and an energy services business. Southern Nuclear operates and
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. In addition,
the retail operating companies and the Company are subject to regulation by the
FERC. 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 those estimates.
The Company was formed on January 8, 2001 and began commercial operations
in August 2001 after Georgia Power transferred its interest in Plant Dahlberg
Units 1 through 10. See Note 2 for further information regarding asset transfers
from affiliates. The financial statements include the accounts of the Company
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
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. 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 the Company. Because the Company has no
employees, all employee related charges are rendered at cost under agreements
with SCS or the retail operating companies. Costs for these services from SCS
amounted to approximately $47.7 million in 2003, $29.5 million in 2002, and $12
million during 2001. Approximately $32.8 million in 2003, $16.2 million in 2002,
and $4.7 million in 2001 were 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.
The Company has agreements with Georgia Power and Alabama Power to provide
operation and maintenance services for Plants Dahlberg, Wansley, Franklin, and
Harris. These services are billed at cost on a monthly basis and are recorded as
II-304
NOTES (continued)
Southern Power Company 2003 Annual Report
operations and maintenance expense in the accompanying statements of income. For
the periods ended December 31, 2003, 2002, and 2001, these services totaled
approximately $6.3 million, $5.3 million, and $1.0 million, respectively.
Additionally, the Company 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 2003, the Company entered into Power Purchase Agreements
(PPAs) with Alabama Power and Georgia Power for the sale of capacity and energy
from Plants Harris and Franklin. Billings under these agreements totaled $67.2
million, including $13.4 million of affiliated deferred capacity revenues
included in deferred capacity revenues on the Balance Sheets at December 31,
2003.
Effective June 2002, the Company entered into PPAs with Georgia Power and
Savannah Electric for the sale of capacity and energy from Plants Wansley and
Franklin. For 2003, billings under these agreements totaled $215 million,
including $15 million of affiliated deferred capacity revenues. For 2002,
billings under these agreements totaled $164 million, including $13 million of
affiliated deferred capacity revenues. These deferred capacity revenues are
included on the Balance Sheets at December 31, 2003 and 2002, respectively.
The retail operating companies, Southern Power, and Southern Company 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 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 3 and 6 for information related to various types of
financing support provided by Southern Company.
Revenues and Fuel Costs
Capacity is sold at rates specified under contractual terms and is recognized at
the lesser of the levelized amount or the amount billable under the contract
over the respective contract periods. Energy is generally sold at market-based
rates and the associated revenue is recognized as the energy is delivered. See
"Financial Instruments" herein for additional information.
Significant portions of the Company's revenues have been derived from
certain customers. For the year ended December 31, 2003, Georgia Power accounted
for approximately 33.7% of revenues, excluding $80 million related to
termination of contracts with Dynegy, Inc. (Dynegy). For the year ended December
31, 2002, Georgia Power, Savannah Electric, and LG&E Energy Marketing, Inc.
accounted for approximately 33.5%, 17.2% and 15.8% 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 7 herein under "Fuel
Commitments" for further details on future commitments.
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.
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. The Company'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.
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.
II-305
NOTES (continued)
Southern Power Company 2003 Annual Report
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.
Asset Retirement Obligations
And Other Costs of Removal
Prior to January 2003, the Company followed the industry practice of accruing
for the ultimate costs of retiring most long-lived assets over the life of the
related asset as part of the annual depreciation expense provision. Effective
January 1, 2003, the Company adopted Financial Accounting Standards Board (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 costs 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 costs 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 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 ($0.4 million after-tax). This represents removal costs accrued prior to
the implementation of Statement No. 143.
Property, Plant, and Equipment
Property, plant, and equipment is stated at original cost. Original cost
includes materials, direct labor incurred by affiliated companies, minor items
of property, and interest capitalized. Interest is capitalized on qualifying
projects during the development and construction period. Interest of
approximately $36.7 million in 2003, $35.3 million in 2002, and $2.9 million in
2001, 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.
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
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 loss recognized is determined by estimating the
fair value of the assets and recording a loss for the amount of the carrying
value that 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 loss is required. Until the
assets are disposed of, their estimated fair value is re-evaluated 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 were $2.2 million at December 31,
2003 and $3.6 million at December 31, 2002.
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 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.
Financial Instruments
The Company uses derivative financial instruments to limit exposure to
fluctuations in interest rates, the prices of certain fuel purchases and
II-306
NOTES (continued)
Southern Power Company 2003 Annual Report
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
that meet the definition of a derivative are exempt from fair value accounting
requirements and are accounted for under the accrual method. Other derivative
contracts qualify as cash flow hedges of anticipated transactions. This results
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. Other derivative contracts 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.
The Company's financial instruments for which the carrying amounts did not
equal fair value at December 31, 2003 were as follows:
Carrying Fair
Amount Value
------------------------
Long-term debt: (in millions)
At December 31, 2003 $1,149 $1,172
At December 31, 2002 $956 $990
- --------------------------------------------------------------
The fair values for securities were based on either closing market prices
or closing prices of comparable instruments.
Comprehensive Income
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. Comprehensive
income consists of net income and changes in the fair value of qualifying cash
flow hedges, less income taxes and reclassifications of amounts included in net
income.
2. ASSET TRANSFERS
On July 31, 2001, Georgia Power transferred its interests in Plant Dahlberg
Units 1 through 10 and related working capital to the Company. 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 the Company 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 Alabama Power 11/2001 $267.9
Units 1 & 2 and
Georgia Power
Wansley Georgia Power 01/2002 $389.9
Units 6 & 7
- -------------------------------------------------------------------
In conjunction with these transfers, Alabama Power and Georgia Power
assigned PPAs to the Company related to these plants. 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 the Company in connection with the
Plant Dahlberg transfer. At December 31, 2003, and 2002, the unamortized balance
of these amounts totaled $1.4 million and $2.8 million, respectively, and is
being amortized into income over the life of the agreements.
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. In addition, 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
II-307
NOTES (continued)
Southern Power Company 2003 Annual Report
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 against the Company cannot be predicted at this time;
however, management does not anticipate that the liabilities, if any, arising
from such current proceedings would have a material adverse effect on the
Company's financial statements.
Uncontracted Generating Capacity
In May 2003, the Company entered into an agreement with Dynegy to resolve all
outstanding matters related to capacity sales contracts with subsidiaries of
Dynegy. Under the terms of the agreement, Dynegy made a cash termination payment
of $80 million to the Company. The termination payments from Dynegy resulted in
a one-time gain to the Company of approximately $50 million.
As a result of the contract termination, the Company is completing limited
construction activities on Plant Franklin Unit 3 to preserve the long-term
viability of the project but has deferred final completion until the 2008-2011
period. The length of the deferral period will depend on forecasted capacity
needs and other wholesale market opportunities. As of December 31, 2003, the
Company's investment in Unit 3 of Plant Franklin was $156 million. The Company
is also continuing to explore alternatives for its existing uncontracted
capacity. The final outcome of these matters cannot now be determined.
FERC Matters
Market-Based Rate Authority
The Company currently has general authorization from the FERC to sell power to
nonaffiliates at market-based prices. In addition, each of the retail operating
companies has obtained FERC approval to sell power to nonaffiliates at
market-based prices under specific contracts. Southern Power and the retail
operating companies also have FERC authority to make short-term opportunity
sales at market rates. Specific FERC approval must be obtained with respect to a
market-based contract with an affiliate. In November 2001, the FERC modified the
test it uses to consider utilities' applications to charge market-based rates
and adopted a new test called the Supply Margin Assessment (SMA). The FERC
applied the SMA to several utilities, including Southern Company, and found
Southern Company and others to be "pivotal suppliers" in their service areas and
ordered the implementation of several mitigation measures. SCS, on behalf of the
retail operating companies and others sought rehearing of the FERC order, and
the FERC delayed the implementation of certain mitigation measures. SCS, on
behalf of the retail operating companies and others submitted comments to the
FERC in 2002 regarding these issues. In December 2003, the FERC issued a staff
paper discussing alternatives and held a technical conference in January 2004.
Southern Company anticipates that the FERC will address the requests for
rehearing in the near future. The final outcome of this matter will depend on
the form in which the SMA test and mitigation measures rules may be ultimately
adopted and cannot be determined at this time.
PPAs by Georgia Power and Savannah Electric for the Company's Plant
McIntosh capacity were certified by the Georgia Public Service Commission (GPSC)
in December 2002 after a competitive bidding process. In April 2003, the Company
applied for FERC approval of these PPAs. Interveners opposed the FERC's
acceptance of the PPAs, alleging that the PPAs do not meet the applicable
standards for market-based rates between affiliates. In July 2003, the FERC
accepted the PPAs to become effective as scheduled on June 1, 2005, subject to
refund, and ordered that hearings be held to determine: (a) whether, in the
design and implementation of the GPSC competitive bidding process, Georgia Power
and Savannah Electric unduly preferred the Company; (b) whether the analysis of
the competitive bids unduly favored the Company, particularly with respect to
evaluation of non-price factors; (c) whether Georgia Power and Savannah Electric
selected their affiliate, the Company, based upon a reasonable combination of
price and non-price factors; (d) whether the Company received an undue
preference or competitive advantage in the competitive bidding process as a
result of access to its affiliate's transmission system; (e) whether and to what
extent the PPAs impact wholesale competition; and (f) whether the PPAs are just
and reasonable and not unduly discriminatory. Hearings are scheduled to begin in
March 2004. Management believes that the PPAs should be approved by the FERC;
however, the ultimate outcome of this matter cannot now be determined.
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 with 660 megawatts. The
unit is co-owned by Orlando Utilities Commission (28%), Florida Municipal Power
Agency (3.5%), and Kissimmee Utility Authority (3.5%). The Company has a
services agreement with SCS where SCS is responsible for the operation and
maintenance of Stanton A and was responsible for the overall construction
project management. Construction on Stanton A began in October 2001 and the unit
II-308
NOTES (continued)
Southern Power Company 2003 Annual Report
was placed in service on October 1, 2003. As of December 31, 2003 $155.3 million
is recorded in plant in service with associated accumulated depreciation of $1.1
million. The Company's proportionate share of the plant's operating expense is
included in the corresponding operating expenses in the Statements of Income. At
December 31, 2002, the Company's share of the construction costs for Stanton A
was $128.3 million, and was recorded in construction work in progress in the
Balance Sheets.
The Company has guaranteed the performance of its subsidiary, SCF, for
SCF's payment obligations under the ownership agreement, PPAs and alternative
power supply agreements associated with the Stanton A project. The Company's
current exposure is $32.5 million under the PPAs and the ownership agreement and
$3.4 million under alternative power supply agreements.
5. INCOME TAXES
Southern Company and its subsidiaries file a consolidated federal income tax
return. In 2002, Southern Company began filing a combined State of Georgia
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.
Details of the income tax provisions are as follows:
2003 2002 2001
- ---------------------------------------------------------------
(in thousands)
Total provision for income taxes:
Federal:
Current $64,090 $26,900 $1,402
Deferred 19,354 2,338 3,017
--------------------------------------------------------------
83,444 29,238 4,419
- ---------------------------------------------------------------
State:
Current 10,459 4,622 240
Deferred 3,318 401 517
State manufacturer's
Tax credits (11,769) (5,804) (2,665)
- ---------------------------------------------------------------
2,008 (781) (1,908)
- ---------------------------------------------------- ----------
Total $85,452 $28,457 $2,511
===============================================================
The Company recorded a reduction in 2003, 2002, and 2001 tax expense of
approximately $11.8 million, $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 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:
2003 2002
- ---------------------------------------------------------------
(in thousands)
Deferred tax liabilities:
Accelerated depreciation $(44,602) $(17,401)
Other - (729)
- ---------------------------------------------------------------
Total (44,602) (18,130)
- ---------------------------------------------------------------
Deferred tax assets:
Book/tax basis difference
on asset transfer 15,061 15,644
Levelized capacity revenues 11,052 8,003
Other comprehensive loss
on interest rate swaps 40,003 30,745
Other 397 2,329
- ---------------------------------------------------------------
Total 66,513 56,721
- ---------------------------------------------------------------
Accumulated deferred income
taxes in the Balance Sheets $21,911 $38,591
===============================================================
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. The Company has recognized a payable to Georgia
Power for Georgia Power's deferred tax liability resulting from this gain of
approximately $15.1 million at December 31, 2003 and $15.6 million at December
31, 2002, which is recorded in other affiliated deferred credits on the Balance
Sheets.
A reconciliation of the federal statutory tax rate to the effective income
tax rate is as follows:
2003 2002 2001
- --------------------------------------------------------------
Federal statutory rate 35.0 35.0 35.0
State income tax, net of
federal deduction 3.7 3.9 4.6
State manufacturer's tax
credits, net of federal effect (3.2) (4.5) (16.2)
- --------------------------------------------------------------
Effective income tax rate 35.5 34.4 23.4
==============================================================
II-309
NOTES (continued)
Southern Power Company 2003 Annual Report
6. CAPITALIZATION
Parent Company Transactions
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 the Company's securities or
obligations. At December 31, 2003, equity contributions and subordinated loans
from Southern Company totaled $850 million.
Southern Company has committed to fund at least 35% of the Company's
construction project financing and to pay for construction cost overruns to the
extent that the Company's own cash flow is insufficient. Also, Southern Company
will prepay any portion of revolving credit arrangements used for the Company's
construction projects not completed within two years of the proposed completion
date. Currently, there are no borrowings related to the construction of Plant
Franklin Unit 3 outstanding under these credit arrangements.
In 2001, Southern Power entered into an intercompany note payable to
Southern Company, which was payable on demand. At December 31, 2002, $210.5
million was outstanding with an interest rate of 5.04%. In March 2003, $190
million of notes payable to Southern Company were converted to a capital
contribution from Southern Company. At December 31, 2003, there were no amounts
outstanding under this agreement.
Bank Credit Arrangements
In 2003, the Company amended and restated its $850 million unsecured syndicated
revolving credit facility (Facility) expiring in April 2006, reducing the
Facility to $650 million. The purpose of the Facility is to finance the
acquisition and construction costs related to gas-fired electric generating
facilities and general corporate expenditures (subject to a $50 million limit),
and to pay or support commercial paper used to fund construction of facilities.
At December 31, 2003, the Company had no outstanding borrowings under the
Facility. Borrowings under the Facility bear interest at the Company's option
equal to either the Eurodollar rate plus a specified margin ranging from 1.25%
to 3.0%, depending on the Company's credit rating and the amount drawn down
under the Facility, or a base rate plus a specified margin. The interest rate
and average interest rate on the Facility were 2.73% and 3.15% at December 31,
2002, and 3.44% and 3.61% at December 31, 2001, and during the periods then
ended. The Company is required to pay a commitment fee on the unused balance of
the Facility. The commitment fee ranges from 0.325% to 0.75%, depending on the
Company's credit rating. For the periods ended December 31, 2003, 2002 and 2001,
the Company paid approximately $2.0 million, $1.1 million, and $0.1 million in
commitment fees, respectively.
The Facility contains certain financial covenants relating to the Company's
debt capitalization which require that additional debt incurred by the Company
must generally be unsecured and the Company 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 65% debt
ratio, as defined in the Facility, excluding intercompany loans. The Company was
in compliance with such covenants at December 31, 2003. Initial borrowings under
the Facility for new projects would be prohibited if the Company or Southern
Company experiences a material adverse change (as defined in the Facility). The
Facility contains a cross default to Southern Company's indebtedness, which if
triggered would require prepayment of debt related to projects financed under
the Facility that are not complete.
Long-Term Debt
In July 2003, the Company issued $575 million of 4.875% senior notes, due July
15, 2015. In June 2002, the Company issued $575 million of 6.25% senior notes,
due July 15, 2012.
Commercial Paper
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. During 2003, the peak amount outstanding for commercial paper was
$493 million and the average amount outstanding was $239 million. The average
annual interest rate on commercial paper was 1.41% in 2003. Commercial paper is
included in notes payable on the Balance Sheets.
The Company's commercial paper program is supported by the Facility. The
Facility was structured to accommodate commercial paper, and the conditions that
II-310
NOTES (continued)
Southern Power Company 2003 Annual Report
the Company 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.
Financial Instruments
The Company enters into energy related derivatives to limit exposures to
electricity, gas, and other fuel price changes. The Company'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. The Company may enter into interest rate swaps to limit
exposure to interest rate changes. Swaps related to variable rate securities or
forecasted transactions are accounted for as cash flow hedges. These swaps are
generally structured to mirror the terms of the hedged debt instruments;
therefore, no material ineffectiveness has been recorded in earnings. At
December 31, 2003, the Company had no interest derivatives outstanding.
In July 2003, the Company terminated $500 million notional amount of
interest rates swaps for losses of $93.3 million at the same time it issued
senior notes. In June 2002, the Company settled interest rates swaps for losses
of $16.9 million associated with senior notes issued in 2002. These losses have
been deferred in other comprehensive income and will be amortized to interest
expense over the life of the senior notes.
During 2003, approximately $5.5 million of pre-tax losses were reclassified
from other comprehensive income to interest expense. During 2004, approximately
$10.4 million of pre-tax losses are expected to be reclassified from other
comprehensive income to interest expense.
At December 31, 2003, the fair value of derivative energy contracts was
reflected in the financial statements as follows:
Amounts
-------------------------------------------------------------------
(in thousands)
Other comprehensive income $1.0
Net income (0.3)
- -------------------------------------------------------------------
Total fair value $0.7
===================================================================
For the Company, the fair value gains or losses for cash flow hedges are
recorded in other comprehensive income and are reclassified into earnings at the
same time the hedged items affect earnings. For 2003, approximately $0.2 million
of pre-tax gains were reclassified from other comprehensive income to
depreciation and amortization. For 2004, approximately $1.4 million of pre-tax
gains are expected to be reclassified from other comprehensive income to
earnings.
7. COMMITMENTS
Construction Program
The Company currently estimates property additions to be $259 million, $254
million and $355 million in 2004, 2005 and 2006, respectively. The Company has
approximately 1,240 megawatts of additional generating capacity scheduled to be
placed in service by 2005.
Significant purchase commitments are outstanding in connection with the
construction program.
The Company has obligations related to the construction, by Alabama Power
and Georgia Power, of transmission interconnection facilities to these plants,
which are guaranteed by Southern Company. At December 31, 2003 these guarantees
totaled $17.5 million.
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 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 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 are $831 million over the
remaining life of the agreements, which may range up to 30 years per unit.
II-311
NOTES (continued)
Southern Power Company 2003 Annual Report
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 long term prepayment in the Deferred Charges and Other Assets
section of the Balance Sheets. Inspection costs are capitalized or charged to
expense based on the nature of the work performed.
Fuel Commitments
SCS, as agent for the retail 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.
Natural gas purchase commitments contain given volumes with prices based on
various indices at the actual time of delivery. Amounts included in the chart
below represent estimates based on New York Mercantile future prices at
December 31, 2003.
Fuel
Purchases
Year (in thousands)
- ---- ------------------
2004 $95,194
2005 53,138
2006 47,831
2007 37,426
2008 18,589
2009 and beyond 430,818
- ---------------------------------------------------------------
Total $682,996
===============================================================
Purchases of natural gas were approximately $139.1 million, $133.5 million,
and $4.4 million for the periods ended December 31, 2003, 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 retail operating
companies, Southern Power and Southern Company GAS, SCS may enter into various
types of wholesale energy and natural gas contracts. Under these agreements,
each of the retail operating companies, Southern Power and Southern Company GAS
may be jointly and severally liable. The creditworthiness of Southern Power and
Southern Company GAS is currently inferior to the creditworthiness of the retail
operating companies; therefore, Southern Company has entered into keep-well
agreements with each of the retail 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.
8. QUARTERLY FINANCIAL INFORMATION
(UNAUDITED)
Summarized quarterly financial information for 2003 and 2002 is as follows:
- ---------------------------------------------------------------------
Operating Operating
Quarter Ended Revenues Income Net Income
- ---------------------------------------------------------------------
(in millions)
--------------------------------------------
March 2003 $107,439 $ 38,217 $ 23,125
June 2003 238,281 132,421 79,290
September 2003 208,624 68,005 40,139
December 2003 127,436 34,662 12,595
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
The Company's business is influenced by seasonal weather conditions. The
Company had approximately 2,400 megawatts of generating capacity in service
through May 2002; approximately 2,400 megawatts through May 2003; approximately
4,350 megawatts through September 2003; and 4,775 megawatts through December
2003. During the second quarter of 2003, the Company recorded $80 million of
contract termination revenues, as a result of the termination of Dynegy's PPAs
related to Plants Dahlberg and Franklin, which resulted in a one-time gain of
$50 million. See Note 3 to the financial statements under "Uncontracted
Generating Capacity" for additional information.
II-312
SELECTED FINANCIAL AND OPERATING DATA 2001-2003
Southern Power Company 2003 Annual Report
- -------------------------------------------------------------------------------------------------------------------------------
2003 2002 2001
- -------------------------------------------------------------------------------------------------------------------------------
Operating Revenues (in thousands):
Sales for resale - non-affiliates $278,559 $114,919 $26,390
Sales for resale - affiliates 312,586 183,111 2,906
- -------------------------------------------------------------------------------------------------------------------------------
Total revenues from sales of electricity 591,145 298,030 29,296
Other revenues 90,635 738 5
- -------------------------------------------------------------------------------------------------------------------------------
Total $681,780 $298,768 $29,301
===============================================================================================================================
Net Income (in thousands) $155,149 $54,270 $8,207
Cash Dividends
on Common Stock (in thousands) $- $- $-
Return on Average Common Equity (percent) 17.65 8.94 3.51
Total Assets (in thousands) $2,409,285 $2,085,976 $822,857
Gross Property Additions (in thousands) $344,362 $1,214,677 $765,511
- -------------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands):
Common stock equity $1,011,476 $746,604 $466,993
Long-term debt 1,149,112 955,879 293,205
- -------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) $2,160,588 $1,702,483 $760,198
===============================================================================================================================
Capitalization Ratios (percent):
Common stock equity 46.8 43.9 61.4
Long-term debt 53.2 56.1 38.6
- -------------------------------------------------------------------------------------------------------------------------------
Total (excluding amounts due within one year) 100.0 100.0 100.0
===============================================================================================================================
Security Ratings:
Unsecured Long-Term Debt -
Moody's Baa1 Baa1 -
Standard and Poor's BBB+ BBB+ -
Fitch BBB+ BBB+ -
===============================================================================================================================
Kilowatt-Hour Sales (in thousands):
Sales for resale - non-affiliates 6,057,053 1,240,290 164,926
Sales for resale - affiliates 5,430,973 3,607,107 69,307
- -------------------------------------------------------------------------------------------------------------------------------
Total 11,488,026 4,847,397 234,233
===============================================================================================================================
Average Revenue Per Kilowatt-Hour (cents): 5.15 6.15 12.51
Plant Nameplate Capacity
Ratings (year-end) (megawatts) 4,775 2,408 800
Maximum Peak-Hour Demand (megawatts):
Winter 2,077 949 -
Summer 2,439 1,426 -
Annual Load Factor (percent) 54.9 51.1 -
Plant Availability (percent): 96.8 95.1 83.7
Source of Energy Supply (percent):
Gas 53.4 77.4 100.0
Purchased power -
From non-affiliates 30.5 5.9 -
From affiliates 16.1 16.7 -
- -------------------------------------------------------------------------------------------------------------------------------
Total 100.0 100.0 100.0
===============================================================================================================================
II-313
PART III
Items 10, 11, 12, 13 and 14 for Southern Company are incorporated by reference
in Southern Company's definitive Proxy Statement relating to the 2004 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, "Certain Relationships and Related Transactions"
for Item 13 and "Principal Public Accounting Firm Fees" for Item 14.
Additionally, Items 10, 11, 12, 13 and 14 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 2004 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, "Certain Relationships and Related Transactions"
for Item 13 and "Principal Public Accounting Firm Fees" for Item 14.
Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS
The ages of directors and executive officers set forth below are as of December
31, 2003.
SAVANNAH ELECTRIC
Identification of directors of Savannah Electric.
Anthony R. James
President and Chief Executive Officer
Age 53
Served as Director since 5-3-01
Gus H. Bell, III (1)
Age 66
Served as Director since 7-20-99
Archie H. Davis (1)
Age 62
Served as Director since 2-18-97
Walter D. Gnann (1)
Age 68
Served as Director since 5-17-83
Robert B. Miller, III (1)
Age 58
Served as Director since 5-17-83
Arnold M. Tenenbaum (1)
Age 67
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, 2003) 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 53
Served as Executive Officer since 7-27-00
W. Miles Greer
Vice President
Age 60
Served as Executive Officer since 11-20-85
Sandra R. Miller
Vice President
Age 51
Served as Executive Officer since 7-26-01
Kirby R. Willis
Vice President, Treasurer and
Chief Financial Officer
Age 52
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 24, 2003
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
III-1
selected as an officer, other than any arrangements or understandings with
officers of Savannah Electric acting solely in their capacities as such.
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 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 - Retired from Chatham Steel Corporation in 2003. Previously
served as President and Director of Chatham Steel Corporation (specializing in
carbon, stainless and specialty steel), Savannah, Georgia from 2001 to
2003; and served as President and Chief Executive Officer of Chatham Steel
Corporation from 1981 to 2001. Chairman of the Board of Directors of the holding
company of First Chatham 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.
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 47
Served as Director since 5-1-01
H. Allen Franklin (1) (2)
Age 59
Served as Director since 1-8-01
Thomas A. Fanning (1)
Age 46
Served as Director since 4-11-03
Charles D. McCrary (1)
Age 52
Served as Director since 2-11-02 and also
served as Director from 1-8-01 to 4-16-01
David M. Ratcliffe (1) (2)
Age 55
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.
(2) Mr. Franklin will retire in July 2004. Mr. Ratcliffe will become Chief
Executive Officer of Southern Company in July 2004.
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 11,
2003) 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 47
Served as Executive Officer since 5-1-01
Robert G. Moore
Senior Vice President
Age 54
Served as Executive Officer since 1-4-02
Edward Day
Senior Vice President
Age 43
Served as Executive Officer since 5-7-03
Douglas E. Jones
Senior Vice President
Age 45
Served as Executive Officer since 1-1-04
Anthony J. Topazi (1)
Senior Vice President
Age 53
Served as Executive Officer since 3-1-01
Cliff S. Thrasher
Senior Vice President, Comptroller and
Chief Financial Officer
Age 53
Served as Executive Officer since 6-10-02
(1) Mr. Topazi was elected President, Chief Executive Officer and Director of
Mississippi Power effective January 1, 2004 and resigned as Senior Vice
President of Southern Power effective January 1, 2004.
Except for Mr. Topazi, 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 7, 2003 for one year until the next annual meeting or until their
successors are elected and have qualified, except for Mr. Jones 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.
Edward Day - Senior Vice President since May 2003. Previously served as Vice
President of Business Development, Southern Company Generation and Energy
Marketing from 1998 to 2003.
Thomas A. Fanning - Executive Vice President, Chief Financial Officer and
Treasurer of Southern Company since April 11, 2003. Previously served as
President, Chief Executive Officer and Director of Gulf Power from May 2002 to
April 2003; Executive Vice President, Treasurer and Chief Financial Officer of
Georgia Power from 1999 to 2002.
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 Company system companies - Southern Company,
Alabama Power, Georgia Power and Gulf Power.
Douglas E. Jones - Senior Vice President since January 2004. Previously served
as Senior Vice President, Southern Company Energy Marketing from December 2001
to January 2004; and Vice President, Southern Company Wholesale Energy from
December 1998 to 2001.
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
Bancorporation.
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.
David M. Ratcliffe - Current Chief Executive Officer of Georgia Power and to
become Chief Executive Officer of Southern Company in July 2004. 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. He is a director of Georgia Power; Mississippi Chemical
Company; Federal Reserve Bank of Atlanta and CSX Corporation.
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 - President and Chief Executive Officer of Mississippi Power
since January 2004. Previously served as Senior Vice President of Southern Power
from November 2002 to December 2003 and Vice President of SCS from December 1999
to December 2003; 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
Code of Ethics
The registrants collectively have adopted a code of business conduct and
ethics that applies to each director, officer and employee of the registrants
and their subsidiaries. The code of business conduct and ethics can be found on
Southern Company's website located at http://www.southerncompany.com. The code
of business conduct and ethics is also available in print to any shareholder
upon request. Any amendment to or waiver from the code of ethics that applies to
executive officers and directors will be posted on the website.
Corporate Governance Guidelines
Southern Company has adopted corporate governance guidelines. The corporate
governance guidelines and the charters of Southern Company's audit committee,
corporate governance and nominating committee and compensation committee can be
found on Southern Company's website located at http://www.southerncompany.com.
The corporate governance guidelines and charters are also available in print to
any shareholder upon request.
III-5
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 2003.
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 2003 248,342 183,462 3,168 - 32,015 164,732 11,956
Executive Officer, 2002 235,748 189,044 13,109 - 35,354 136,462 12,235
Director 2001 210,856 177,858 1,328 - 31,363 87,577 30,195
W. Miles Greer 2003 198,238 97,376 1,716 - 12,744 111,890 24,702
Vice President 2002 191,400 101,796 107 - 14,278 115,884 20,261
2001 184,066 104,286 666 - 32,505 105,924 8,567
Kirby R. Willis
Vice President, 2003 182,109 89,491 2,207 - 11,712 68,470 14,634
Chief Financial 2002 175,476 93,329 891 - 13,090 61,913 13,283
Officer, Treasurer 2001 168,747 100,480 490 - 29,993 89,814 8,495
Sandra R. Miller 5 2003 146,072 108,696 5,135 - 9,432 32,304 12,424
Vice President 2002 138,074 104,769 1,720 - 10,317 18,824 7,016
2001 112,802 83,015 8,123 - 1,896 4,791 20,749
- -----------------------------------
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, 2001, 2002 and 2003, 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. For
eligible stock options held on December 31, 2001, 2002 and 2003, all named
executives received a payout of $1.34, $1.355 and $1.385 per option,
respectively.
3 Contributions in 2003 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 $7,967 $744 $3,245
W. Miles Greer 8,921 744 12,037
Kirby R. Willis 6,719 636 7,279
Sandra R. Miller 5,403 744 1,277
In 2003, these amounts included additional incentive compensation of $5,000
and $3,000 for Ms. Miller and Mr. Greer, respectively.
4 Mr. James became President and Chief Executive Officer effective in May 2001.
5 Ms. Miller became an executive officer of Savannah Electric in July 2001.
III-6
Summary Compensation Table. The following table sets forth information
concerning any Chief Executive Officer and the four most highly compensated
executive officers of Southern Power serving during 2003.
ANNUAL COMPENSATION LONG-TERM COMPENSATION
Number of
Securities Long-
Name Restricted Underlying Term
and Other Annual Stock Stock Incentive All Other
Principal Compensation Award Options Payouts Compensation
Position Year Salary($) Bonus($) ($)6 ($) (Shares) ($)7 ($)8
- ---------------------------------------------------------------------------------------------------------------------------------
W. Paul Bowers
President, Chief 2003 356,994 431,675 6,257 - 46,181 234,253 18,063
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 2003 272,240 272,895 25,856 - 27,526 188,241 54,595
Senior Vice President 2002 249,389 262,399 3,218 - 29,229 173,966 64,274
2001 237,095 185,293 112,839 - 49,800 145,178 213,144
Robert G. Moore 9 2003 231,138 242,714 6,988 - 18,687 98,489 18,985
Senior Vice President 2002 217,233 206,785 2,820 - 20,835 111,206 13,396
2001 - - - - - - -
Cliff S. Thrasher 9 2003 202,375 182,577 2,464 - 16,742 87,047 10,629
Senior Vice President, 2002 187,200 175,560 52,852 - 13,443 79,394 59,640
Comptroller & Chief 2001 - - - - - - -
Financial Officer
Edward Day 10 2003 182,560 176,459 1,158 - 10,843 41,292 29,502
Senior Vice President 2002 - - - - - - -
2001 - - - - - - -
- ---------------------------------------
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, 2001, 2002 and 2003, 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. For
eligible stock options held on December 31, 2001, 2002 and 2003, all named
executives received a payout of $1.34, $1.355 and $1.385 per option,
respectively.
8 Contributions in 2003 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 $7,934 $744 $9,385 $ -
Anthony J. Topazi 9,000 744 4,851 -
Robert G. Moore 7,934 744 2,519 788
Cliff S. Thrasher 9,000 744 885 -
Edward Day 8,215 744 543 -
In 2003, these amounts include additional incentive compensation of $40,000,
$7,000 and $20,000 for Messrs. Topazi, Moore and Day, respectively. In 2002,
these amounts include additional incentive compensation of $50,000 each for
Mr. Topazi and Mr. Thrasher. In 2001, these amounts included additional
incentive compensation for Messrs. Bowers and Topazi of $24,380 and $200,000
respectively.
9 Mr. Moore became an executive officer of Southern Power in January 2002 and
Mr. Thrasher became an executive officer of Southern Power in June 2002.
10 Mr. Day became an executive officer of Southern Power in May 2003.
III-7
STOCK OPTION GRANTS IN 2003
Stock Option Grants. The following table sets forth all stock option grants to
the named executive officers of Savannah Electric and Southern Power during the
year ending December 31, 2003.
Individual Grants Grant Date Value
% of Total
# of Securities Options
Underlying Granted to Exercise
Options Employee in or Base Price Expiration Grant Date
Name Granted 11 Fiscal Year 12 ($/Sh) 11 Date 11 Present Value13
- ---------------------------- --------------- -------------------- -------------------- -------------------- --------------------
Savannah Electric
Anthony R. James 32,015 25.5 $27.975 2/14/2013 $114,934
W. Miles Greer 12,744 10.2 $27.975 2/14/2013 45,751
Kirby R. Willis 11,712 9.3 $27.975 2/14/2013 42,046
Sandra R. Miller 9,432 7.5 $27.975 2/14/2013 33,861
Southern Power
W. Paul Bowers 46,181 1.6 $27.975 2/14/2013 165,790
Anthony J. Topazi 27,526 0.9 $27.975 2/14/2013 98,818
Robert G. Moore 18,687 0.6 $27.975 2/14/2013 67,086
Cliff S. Thrasher 16,742 0.6 $27.975 2/14/2013 60,104
Edward Day 10,843 0.4 $27.975 2/14/2013 38,926
- ---------------------------------------
11 Under the terms of the Omnibus Incentive Compensation Plan, stock option grants were made on February 14, 2003 and vest
annually at a rate of one-third on the anniversary date of the grant. Grants fully vest upon termination as a result of death,
total disability or retirement and expire five years after retirement, three years after death or total disability or their normal
expiration date if earlier. The exercise price is the average of the high and low price of Southern Company's common stock on the
date granted. Options may be transferred to a revocable trust and for Mr. Bowers may be transferred to certain family members,
family trusts and family limited partnerships.
12 A total of 125,397 and 2,885,181 stock options were granted in 2003 to Savannah Electric and SCS, respectively. Southern Power
has no employees; therefore, SCS employees perform work on behalf of Southern Power that is billed, at cost, to Southern Power.
13 Value was calculated using the Black-Scholes option valuation model. The actual value, if any, ultimately
realized depends on the market value of Southern Company's common stock at a future date. Significant assumptions
are shown below:
Risk-free Dividend Expected
Volatility rate of return Yield Term
-----------------------------------------------------------------------------------
23.59% 2.72% 4.90% 4.28 years
-----------------------------------------------------------------------------------
III-8
AGGREGATED STOCK OPTION EXERCISES IN 2003 AND YEAR-END OPTION VALUES
Aggregated Stock Option Exercises. The following table sets forth information
concerning options exercised during the year ending December 31, 2003 by the
named executive officers and the value of unexercised options held by them as of
December 31, 2003.
Number of Securities Underlying Value of Unexercised
Unexercised Options at Fiscal In-the-Money Options
Year-End (#) At Year-End ($)14
Shares ------------------------------------------------------------------
Acquired Value
Name on Exercise (#Realized ($)15 Exercisable Unexercisable Exercisable Unexercisable
- ------------------------- ------------- --------------- ---------------- ------------------- ------------- ---------------
Savannah Electric
Anthony R. James 13,785 201,626 52,902 66,038 576,957 292,108
W. Miles Greer 17,480 253,385 47,690 33,097 562,488 180,256
Kirby R. Willis 7,967 117,180 19,001 30,436 189,691 165,826
Sandra R. Miller - - 6,382 16,942 56,191 62,218
Southern Power
W. Paul Bowers 35,077 541,068 72,345 96,791 692,848 435,030
Anthony J. Topazi 20,000 336,570 72,302 63,612 775,745 317,744
Robert G. Moore 29,647 486,094 28,004 43,107 236,590 212,797
Cliff S. Thrasher 12,485 178,001 26,258 36,592 228,219 185,732
Edward Day 8,951 102,716 6,681 23,133 41,149 108,833
- -------------------------------------
14 This column represents the excess of the fair market value of Southern Company's common stock of $30.25 per share, as
of December 31, 2003, 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, 2003.
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-9
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 Company 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-6 and III-7.
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, 2003, 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 $382,476 24
W. Miles Greer 16 263,274 27
Kirby R. Willis 17 243,194 29
Sandra R. Miller 218,099 23
Southern Power
Compensation Accredited
Name Level Years of Service
------------ ----------------
W. Paul Bowers $650,994 23
Anthony J. Topazi 460,397 33
Robert G. Moore 388,047 29
Cliff S. Thrasher 324,619 32
Edward Day 279,250 19
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 5 years and 5 months
granted to Mr. Willis for time served at a non-affiliated electric utility.
III-10
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 2003 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 2003 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, 2003 in addition to or in lieu of
that specified by the standard arrangements specified above.
III-11
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.
Report on Repricing of Options.
- -------------------------------
None.
Compensation Committee Interlocks and Insider Participation.
- ------------------------------------------------------------
None.
III-12
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS
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, 2003. 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, 2003.
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 636 -
Archie H. Davis Southern Company Common 1,065 -
Walter D. Gnann Southern Company Common 3,312 -
Robert B. Miller, III Southern Company Common 2,775 -
Arnold M. Tenenbaum Southern Company Common 1,599 -
W. Miles Greer Southern Company Common 67,958 62,366
Anthony R. James Southern Company Common 96,553 81,289
Sandra R. Miller Southern Company Common 14,770 13,411
Kirby R. Willis Southern Company Common 37,798 32,465
The directors, nominees
and executive officers
as a group Southern Company Common 226,466 189,531
III-13
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 120,220 112,941
Thomas A. Fanning Southern Company Common 85,420 83,657
H. Allen Franklin Southern Company Common 1,249,368 1,207,841
Charles D. McCrary Southern Company Common 259,492 256,031
David M. Ratcliffe Southern Company Common 227,807 214,558
Edward Day Southern Company Common 19,659 17,283
Robert G. Moore Southern Company Common 60,232 46,725
Cliff S. Thrasher Southern Company Common 36,274 31,026
Anthony J. Topazi Southern Company Common 111,232 99,580
The directors, nominees
and executive officers
as a group Southern Company Common 2,169,704 2,069,642
(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-14
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
SAVANNAH ELECTRIC
Transactions with management and others.
Mr. Archie Davis is currently President, Chief Executive Officer and a
Director of Savannah Bancorp, Inc. and Vice Chairman and Director 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. Mr. Tenenbaum is Chairman of the Board of Directors
for the holding company of First Chatham Bank. During 2003, 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.
III-15
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The following represents the fees billed to Savannah Electric and Southern Power
for the last two fiscal years by Deloitte & Touche LLP, each company's principal
public accountant for 2003 and 2002:
2003 2002
------------------------------------------------------------------
Savannah Electric (in thousands)
- ------------------------------------------
Audit Fees (1) $250 $170
Audit-Related Fees (2) 101 2
Tax Fees - -
All Other Fees - -
----- ------
$351 $172
===== ======
Southern Power
- ------------------------------------------
Audit Fees (3) $535 $1,580
Audit-Related Fees (2) 290 1
Tax Fees - -
All Other Fees - -
----- -------
$825 $1,581
==== ======
(1) Includes services performed in connection with financing transactions.
(2) Includes internal control review services and accounting consultations.
(3) 2002 amount includes a re-audit of the 2001 financial statements and other
services performed in connection with Southern Power's initial public debt
offering. 2003 amount includes services performed in connection with additional
financing transactions.
The Southern Company Audit Committee (on behalf of Southern Company and all its
subsidiaries) adopted a Policy of Engagement of the Independent Auditor for
Audit and Non-Audit Services that includes requirements for such Audit Committee
to pre-approve audit and non-audit services provided by Deloitte & Touche LLP.
All of the audit services provided by Deloitte & Touche LLP in the fiscal year
2003 (described in the footnotes to the table above) and related fees were
approved in advance by the Southern Company Audit Committee.
III-16
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-9, IV-11, IV-13, IV-15, IV-17, IV-19 and IV-21.
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-10, IV-12, IV-14, IV-16, IV-18 and IV-20.
(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 2003 were as follows:
The registrants collectively and separately furnished a Current Report on
Form 8-K:
Date of event: October 21, 2003
Item reported: 12
The registrants collectively and separately filed Current Reports on Form
8-K:
Date of event: December 2, 2003
Items reported: 5 and 7
Date of event: December 8, 2003
Item reported: 5
Southern Company and Mississippi Power collectively and separately filed
Current Reports on Form 8-K:
Date of event: December 16, 2003
Item reported: 5
Alabama Power filed a Current Report on Form 8-K:
Date of event: November 14, 2003
Items reported: 5 and 7
Savannah Electric filed a Current Report on
Form 8-K:
Date of event: December 10, 2003
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 1, 2004
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)
Thomas A. Fanning
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 Zack T. Pate
Dorrit J. Bern J. Neal Purcell
Thomas F. Chapman David M. Ratcliffe
Bruce Gordon Gerald J. St. Pe'
Donald M. James
By: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 1, 2004
IV-2
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 1, 2004
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 Malcolm Portera
David J. Cooper Robert D. Powers
H. Allen Franklin C. Dowd Ritter
R. Kent Henslee James H. Sanford
Patricia M. King William F. Walker
James K. Lowder John Cox Webb, IV
Wallace D. Malone, Jr. James W. Wright
By: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 1, 2004
IV-3
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, Chief Executive Officer
By: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 1, 2004
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
Chief Executive Officer and Director
(Principal Executive Officer)
C. B. Harreld
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 D. Gary Thompson
Robert L. Brown, Jr. Richard W. Ussery
Anna R. Cablik William Jerry Vereen
H. Allen Franklin Carl Ware
Michael D. Garrett E. Jenner Wood, III
By: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 1, 2004
IV-4
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: Susan N. Story, President and
Chief Executive Officer
By: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 1, 2004
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.
Susan N. Story
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 William A. Pullum
William C. Cramer, Jr. Winston E. Scott
Fred C. Donovan, Sr.
By: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 1, 2004
IV-5
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: Anthony J. Topazi, President and
Chief Executive Officer
By: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 1, 2004
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 J. Topazi
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 1, 2004
IV-6
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 1, 2004
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 1, 2004
IV-7
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 1, 2004
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:
Thomas A. Fanning Charles D. McCrary
H. Allen Franklin David M. Ratcliffe
By: Wayne Boston
(Wayne Boston, Attorney-in-fact)
Date: March 1, 2004
IV-8
DELOITTE.
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 December 31, 2003 and 2002, and for the years then
ended, and have issued our report thereon dated March 1, 2004 (which report
expresses an unqualified opinion and includes an explanatory paragraph relating
to the change in the method of accounting for asset retirement obligations);
such consolidated financial statements and report are included elsewhere in this
Form 10-K. Our audit also included the 2003 and 2002 consolidated financial
statement schedules of Southern Company and Subsidiary Companies (page S-2)
listed in the accompanying index at Item 15. These financial statement schedules
are the responsibility of Southern Company's management. Our responsibility is
to express an opinion based on our audits. The 2001 consolidated financial
statement schedule was audited by other auditors who have ceased operations.
Those auditors expressed an opinion, in their report dated February 13, 2002,
that such 2001 consolidated financial statement schedule, when considered in
relation to the 2001 basic consolidated financial statements taken as a whole,
presented fairly, in all material respects, the information set forth therein.
In our opinion, the 2003 and 2002 consolidated financial statement schedules,
when considered in relation to the 2003 and 2002 basic consolidated financial
statements taken as a whole, present fairly, in all material respects, the
information set forth therein.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
March 1, 2004
Member of
Deloitte Touche Tohmatsu
IV-9
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-10
DELOITTE.
INDEPENDENT AUDITORS' REPORT
Alabama Power Company:
We have audited the financial statements of Alabama Power Company as of December
31, 2003 and 2002, and for the years then ended, and have issued our report
thereon dated March 1, 2004 (which report expresses an unqualified opinion an
includes and explanatory paragraph relating to the change in the method of
accounting for asset retirement obligations); such financial statements and
report are included elsewhere in this Form 10-K. Our audits also included the
2003 and 2002 financial statement schedules of Alabama Power Company (page S-3)
listed in the accompanying index at Item 15. These financial statement schedules
are the responsibility of Alabama Power Company's management. Our responsibility
is to express an opinion based on our audits. The 2001 financial statement
schedule was audited by other auditors who have ceased operations. Those
auditors expressed an opinion, in their report dated February 13, 2002, that
such 2001 financial statement schedule, when considered in relation to the 2001
basic financial statements taken as a whole, presented fairly, in all material
respects, the information set forth therein. In our opinion, the 2003 and 2002
financial statement schedules, when considered in relation to the 2003 and 2002
basic financial statements taken as a whole, present fairly, in all material
respects, the information set forth therein.
/s/ Deloitte & Touche LLP
Birmingham, Alabama
March 1, 2004
Member of
Deloitte Touche Tohmatsu
IV-11
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-12
DELOITTE.
INDEPENDENT AUDITORS' REPORT
Georgia Power Company:
We have audited the financial statements of Georgia Power Company as of December
31, 2003 and 2002, and for the years then ended, and have issued our report
thereon dated March 1, 2004 (which report expresses an unqualified opinion and
includes an explanatory paragraph relating to the change in the method of
accounting for asset retirement obligations); such financial statements and
report are included elsewhere in this Form 10-K. Our audits also included the
2003 and 2002 financial statement schedules of Georgia Power Company (page S-4)
listed in the accompanying index at Item 15. These financial statement schedules
are the responsibility of Georgia Power Company's management. Our responsibility
is to express an opinion based on our audits. The 2001 financial statement
schedule was audited by other auditors who have ceased operations. Those
auditors expressed an opinion, in their report dated February 13, 2002, that
such 2001 financial statement schedule, when considered in relation to the 2001
basic financial statements taken as a whole, presented fairly, in all material
respects, the information set forth therein. In our opinion, the 2003 and 2002
financial statement schedules, when considered in relation to the 2003 and 2002
basic financial statements taken as a whole, present fairly, in all material
respects, the information set forth therein.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
March 1, 2004
Member of
Deloitte Touche Tohmatsu
IV-13
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-14
DELOITTE.
INDEPENDENT AUDITORS' REPORT
Gulf Power Company:
We have audited the financial statements of Gulf Power Company as of December
31, 2003 and 2002, and for the years then ended, and have issued our report
thereon dated March 1, 2004 (which report expresses an unqualified opinion and
includes an explanatory paragraph relating to the change in the method of
accounting for asset retirement obligations); such financial statements and
report are included elsewhere in this Form 10-K. Our audits also included the
2003 and 2002 financial statement schedules of Gulf Power Company (page S-5)
listed in the accompanying index at Item 15. These financial statement schedules
are the responsibility of Gulf Power Company's management. Our responsibility is
to express an opinion based on our audits. The 2001 financial statement schedule
was audited by other auditors who have ceased operations. Those auditors
expressed an opinion, in their report dated February 13, 2002, that such 2001
financial statement schedule, when considered in relation to the 2001 basic
financial statements taken as a whole, presented fairly, in all material
respects, the information set forth therein. In our opinion, the 2003 and 2002
financial statement schedules, when considered in relation to the 2003 and 2002
basic financial statements taken as a whole, present fairly, in all material
respects, the information set forth therein.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
March 1, 2004
Member of
Deloitte Touche Tohmatsu
IV-15
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-16
DELOITTE.
INDEPENDENT AUDITORS' REPORT
Mississippi Power Company:
We have audited the financial statements of Mississippi Power Company as of
December 31, 2003 and 2002, and for the years then ended, and have issued our
report thereon dated March 1, 2004 (which report expresses an unqualified
opinion and includes an explanatory paragraph relating to the change in the
method of accounting for asset retirement obligations); such financial
statements and report are included elsewhere in this Form 10-K. Our audits also
included the 2003 and 2002 financial statement schedules of Mississippi Power
Company (page S-6) listed in the accompanying index at Item 15. These financial
statement schedules are the responsibility of Mississippi Power Company's
management. Our responsibility is to express an opinion based on our audits. The
2001 financial statement schedule was audited by other auditors who have ceased
operations. Those auditors expressed an opinion, in their report dated February
13, 2002, that such 2001 financial statement schedule, when considered in
relation to the 2001 basic financial statements taken as a whole, presented
fairly, in all material respects, the information set forth therein. In our
opinion, the 2003 and 2002 financial statement schedules, when considered in
relation to the 2003 and 2002 basic financial statements taken as a whole,
present fairly, in all material respects, the information set forth therein.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
March 1, 2004
Member of
Deloitte Touche Tohmatsu
IV-17
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-18
DELOITTE.
INDEPENDENT AUDITORS' REPORT
Savannah Electric and Power Company:
We have audited the financial statements of Savannah Electric and Power Company
as of December 31, 2003 and 2002, and for the years then ended, and have issued
our report thereon dated March 1, 2004 (which report expresses an unqualified
opinion and includes an explanatory paragraph relating to the change in the
method of accounting for asset retirement obligations); such financial
statements and report are included elsewhere in this Form 10-K. Our audits also
included the 2003 and 2002 financial statement schedules of Savannah Electric
and Power Company (page S-7) listed in the accompanying index at Item 15. These
financial statement schedules are the responsibility of Savannah Electric and
Power Company's management. Our responsibility is to express an opinion based on
our audits. The 2001 financial statement schedule was audited by other auditors
who have ceased operations. Those auditors expressed an opinion, in their report
dated February 13, 2002, that such 2001 financial statement schedule, when
considered in relation to the 2001 basic financial statements taken as a whole,
presented fairly, in all material respects, the information set forth therein.
In our opinion, the 2003 and 2002 financial statement schedules, when considered
in relation to the 2003 and 2002 basic financial statements taken as a whole,
present fairly, in all material respects, the information set forth therein.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
March 1, 2004
Member of
Deloitte Touche Tohmatsu
IV-19
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-20
DELOITTE.
INDEPENDENT AUDITORS' REPORT
Southern Power Company
We have audited the financial statements of Southern Power Company as of
December 31, 2003 and 2002, and for the years then ended and for the period from
January 8, 2001 (inception) to December 31, 2001, and have issued our report
thereon dated March 1, 2004; 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
March 1, 2004
Member of
Deloitte Touche Tohmatsu
IV-21
INDEX TO FINANCIAL STATEMENT SCHEDULES
Schedule Page
II Valuation and Qualifying Accounts and Reserves
2003, 2002 and 2001
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
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, 2003, 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
2003...................... $26,428 $56,332 $14,901 $67,506 (b) $30,155
2002...................... 24,383 40,313 5,961 (a) 44,229 (b) 26,428
2001...................... 21,799 44,272 269 41,957 (b) 24,383
- -------------------
(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, 2003, 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
2003....................... $4,827 $13,444 $- $13,515 (Note) $4,756
2002....................... 5,237 10,804 - 11,214 (Note) 4,827
2001....................... 6,237 7,419 - 8,419 (Note) 5,237
- -------------------
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, 2003, 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
2003.......................... $5,825 $15,577 $- $16,052 (Note) $5,350
2002.......................... 8,895 14,117 - 17,187 (Note) 5,825
2001.......................... 5,100 22,913 - 19,118 (Note) 8,895
- -------------------
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, 2003, 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
2003.......................... $889 $2,122 $- $2,064 (Note) $947
2002.......................... 1,342 1,620 - 2,073 (Note) 889
2001.......................... 1,302 2,282 - 2,242 (Note) 1,342
- -------------------
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, 2003, 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
2003.......................... $718 $1,947 $135 $1,903 (Note) $897
2002.......................... 856 2,045 7 2,190 (Note) 718
2001.......................... 571 2,877 (165) 2,427 (Note) 856
- -------------------
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, 2003, 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
2003.......................... $682 $ 784 $- $825 (Note) $641
2002.......................... 500 1,137 - 955 (Note) 682
2001.......................... 407 978 - 885 (Note) 500
- -------------------
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, 2003, 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
2003.......................... $350 $ - $- $- $350
2002.......................... - 350 - - 350
2001.......................... - - - - -
S-8
EXHIBIT INDEX
The following exhibits indicated by an asterisk (*) preceding the
exhibit number are filed herewith. The balance of the exhibits have heretofore
been filed with the SEC as the exhibits and in the file numbers indicated and
are incorporated herein by reference. The exhibits marked with a pound sign (#)
are management contracts or compensatory plans or arrangements required to be
identified as such by Item 15 of Form 10-K.
(3) Articles of Incorporation and By-Laws
Southern Company
(a)1 - Composite Certificate of Incorporation of Southern
Company, reflecting all amendments thereto through January 5,
1994. (Designated in Registration No. 33-3546 as Exhibit 4(a),
in Certificate of Notification, File No. 70-7341, as Exhibit A
and in Certificate of Notification, File No. 70-8181, as
Exhibit A.)
(a)2 - By-laws of Southern Company as amended effective February
17, 2003, and as presently in effect. (Designated in Southern
Company's Form 10-Q for the quarter ended June 30, 2003, File
No. 1-3526, as Exhibit 3(a)1.)
Alabama Power
(b)1 - Charter of Alabama Power and amendments thereto through
February 17, 2004. (Designated in Registration Nos. 2-59634 as
Exhibit 2(b), 2-60209 as Exhibit 2(c), 2-60484 as Exhibit
2(b), 2-70838 as Exhibit 4(a)-2, 2-85987 as Exhibit 4(a)-2,
33-25539 as Exhibit 4(a)-2, 33-43917 as Exhibit 4(a)-2, in
Form 8-K dated February 5, 1992, File No. 1-3164, as Exhibit
4(b)-3, in Form 8-K dated July 8, 1992, File No. 1-3164, as
Exhibit 4(b)-3, in Form 8-K dated October 27, 1993, File No.
1-3164, as Exhibits 4(a) and 4(b), in Form 8-K dated November
16, 1993, File No. 1-3164, as Exhibit 4(a), in Certificate of
Notification, File No. 70-8191, as Exhibit A, in Alabama
Power's Form 10-K for the year ended December 31, 1997, File
No. 1-3164, as Exhibit 3(b)2, in Form 8-K dated August 10,
1998, File No. 1-3164, as Exhibit 4.4, in Alabama Power's Form
10-K for the year ended December 31, 2000, File No. 1-3164, as
Exhibit 3(b)2, in Alabama Power's Form 10-K for the year ended
December 31, 2001, File No. 1-3164, as Exhibit 3(b)2, in Form
8-K dated February 5, 2003, File No. 1-3164, as Exhibit 4.4,
in Alabama Power's Form 10-Q for the quarter ended March 31,
2003, File No 1-3164, as Exhibit 3(b)1 and in Form 8-K dated
February 5, 2004, File No. 1-3164 as Exhibit 4.4.)
(b)2 - By-laws of Alabama Power as amended effective April 25,
2003, and as presently in effect. (Designated in Alabama
Power's Form 10-Q for the quarter ended March 31, 2003, File
No 1-3164, as Exhibit 3(b)2.)
E-1
Georgia Power
(c)1 - Charter of Georgia Power and amendments thereto through
January 16, 2001. (Designated in Registration Nos. 2-63392 as
Exhibit 2(a)-2, 2-78913 as Exhibits 4(a)-(2) and 4(a)-(3),
2-93039 as Exhibit 4(a)-(2), 2-96810 as Exhibit 4(a)-2, 33-141
as Exhibit 4(a)-(2), 33-1359 as Exhibit 4(a)(2), 33-5405 as
Exhibit 4(b)(2), 33-14367 as Exhibits 4(b)-(2) and 4(b)-(3),
33-22504 as Exhibits 4(b)-(2), 4(b)-(3) and 4(b)-(4), in
Georgia Power's Form 10-K for the year ended December 31,
1991, File No. 1-6468, as Exhibits 4(a)(2) and 4(a)(3), in
Registration No. 33-48895 as Exhibits 4(b)-(2) and 4(b)-(3),
in Form 8-K dated December 10, 1992, File No. 1-6468 as
Exhibit 4(b), in Form 8-K dated June 17, 1993, File No.
1-6468, as Exhibit 4(b), in Form 8-K dated October 20, 1993,
File No. 1-6468, as Exhibit 4(b), in Georgia Power's Form 10-K
for the year ended December 31, 1997, File No. 1-6468, as
Exhibit 3(c)2 and in Georgia Power's Form 10-K for the year
ended December 31, 2000, File No. 1-6468, as Exhibit 3(c)2.)
(c)2 - By-laws of Georgia Power as amended effective February 19,
2003, and as presently in effect. (Designated in Georgia
Power's Form 10-K for the year ended December 31, 2002, File
No 1-6468, as Exhibit 3(c)2.)
Gulf Power
(d)1 - Restated Articles of Incorporation of Gulf Power and
amendments thereto through February 9, 2001. (Designated in
Registration No. 33-43739 as Exhibit 4(b)-1, in Form 8-K dated
January 15, 1992, File No. 0-2429, as Exhibit 1(b), in Form
8-K dated August 18, 1992, File No. 0-2429, as Exhibit 4(b)-2,
in Form 8-K dated September 22, 1993, File No. 0-2429, as
Exhibit 4, in Form 8-K dated November 3, 1993, File No.
0-2429, as Exhibit 4, in Gulf Power's Form 10-K for the year
ended December 31, 1997, File No. 0-2429, as Exhibit 3(d)2 and
in Gulf Power's Form 10-K for the year ended December 31,
2000, File No. 0-2429, as Exhibit 3(d)2.)
(d)2 - By-laws of Gulf Power as amended effective July 26, 2002,
and as presently in effect. (Designated in Gulf Power's Form
10-K for the year ended December 31, 2002, File No 0-2429, as
Exhibit 3(d)2.)
Mississippi Power
(e)1 - Articles of Incorporation of Mississippi Power, articles
of merger of Mississippi Power Company (a Maine corporation)
into Mississippi Power and articles of amendment to the
articles of incorporation of Mississippi Power through March
8, 2001. (Designated in Registration No. 2-71540 as Exhibit
4(a)-1, in Form U5S for 1987, File No. 30-222-2, as Exhibit
B-10, in Registration No. 33-49320 as Exhibit 4(b)-(1), in
Form 8-K dated August 5, 1992, File No. 0-6849, as Exhibits
4(b)-2 and 4(b)-3, in Form 8-K dated August 4, 1993, File No.
0-6849, as Exhibit 4(b)-3, in Form 8-K dated August 18, 1993,
File No. 0-6849, as Exhibit 4(b)-3, in Mississippi Power's
Form 10-K for the year ended December 31, 1997, File No.
0-6849, as Exhibit 3(e)2 and in Mississippi Power's Form 10-K
for the year ended December 31, 2000, File No. 0-6849, as
Exhibit 3(e)2.)
E-2
(e)2 - By-laws of Mississippi Power as amended effective February
28, 2001, and as presently in effect. (Designated in
Mississippi Power's Form 10-K for the year ended December 31,
2001, File No. 0-6849, as Exhibit 3(e)2.)
Savannah Electric
(f)1 - Charter of Savannah Electric and amendments thereto
through December 2, 1998. (Designated in Registration Nos.
33-25183 as Exhibit 4(b)-(1), 33-45757 as Exhibit 4(b)-(2), in
Form 8-K dated November 9, 1993, File No. 1-5072, as Exhibit
4(b) and in Savannah Electric's Form 10-K for the year ended
December 31, 1998, as Exhibit 3(f)2.)
(f)2 - By-laws of Savannah Electric as amended effective May 17,
2000, and as presently in effect. (Designated in Savannah
Electric's Form 10-K for the year ended December 31, 2000,
File No. 1-5072, as Exhibit 3(f)2.)
Southern Power
(g)1 - Certificate of Incorporation of Southern Power dated
January 8, 2001. (Designated in Registration No. 333-98553 as
Exhibit 3.1.)
(g)2 - Bylaws of Southern Power effective January 8, 2001.
(Designated in Registration No. 333-98553 as Exhibit 3.2.)
(4) Instruments Describing Rights of Security Holders, Including Indentures
Southern Company
(a)1 - Subordinated Note Indenture dated as of February 1, 1997,
among Southern Company, Southern Company Capital Funding, Inc.
and Deutsche Bank Trust Company Americas (formerly known as
Bankers Trust Company), as Trustee, and indentures
supplemental thereto dated as of February 4, 1997. (Designated
in Registration Nos. 333-28349 as Exhibits 4.1 and 4.2 and
333-28355 as Exhibit 4.2.)
(a)2 - Subordinated Note Indenture dated as of June 1, 1997,
among Southern Company, Southern Company Capital Funding, Inc.
and Deutsche Bank Trust Company Americas (formerly known as
Bankers Trust Company), as Trustee, and indentures
supplemental thereto through July 31, 2002. (Designated in
Southern Company's Form 10-K for the year ended December 31,
1997, File No. 1-3526, as Exhibit (4)(a)2, in Form 8-K dated
June 18, 1998, File No. 1-3526, as Exhibit 4.2, in Form 8-K
dated December 18, 1998, File No. 1-3526, as Exhibit 4.4 and
in Form 8-K dated July 24, 2002, File No. 1-3526, as Exhibit
4.4.)
(a)3 - Senior Note Indenture dated as of February 1, 2002, among
Southern Company, Southern Company Capital Funding, Inc. and
The Bank of New York, as Trustee, and indentures supplemental
thereto through those dated February 1, 2002. (Designated in
Form 8-K dated January 29, 2002, File No. 1-3526, as Exhibits
4.1 and 4.2 and in Form 8-K dated January 30, 2002, File No.
1-3526, as Exhibit 4.2.)
E-3
(a)4 - Amended and Restated Trust Agreement of Southern Company
Capital Trust I dated as of February 1, 1997. (Designated in
Registration No. 333-28349 as Exhibit 4.6.)
(a)5 - Amended and Restated Trust Agreement of Southern Company
Capital Trust II dated as of February 1, 1997. (Designated in
Registration No. 333-28355 as Exhibit 4.6.)
(a)6 - Amended and Restated Trust Agreement of Southern Company
Capital Trust VI dated as of July 1, 2002. (Designated in Form
8-K dated July 24, 2002, File No. 1-3526, as Exhibit 4.7-A.)
(a)7 - Capital Securities Guarantee Agreement relating to
Southern Company Capital Trust I dated as of February 1, 1997.
(Designated in Registration No. 333-28349 as Exhibit 4.10.)
(a)8 - Capital Securities Guarantee Agreement relating to
Southern Company Capital Trust II dated as of February 1,
1997. (Designated in Registration No. 333-28355 as Exhibit
4.10.)
(a)9 - Preferred Securities Guarantee Agreement relating to
Southern Company Capital Trust VI dated as of July 1, 2002.
(Designated in Form 8-K dated July 24, 2002, File No. 1-3526,
as Exhibit 4.11-A.)
Alabama Power
(b)1 - Indenture dated as of January 1, 1942, between Alabama
Power and JPMorgan Chase Bank (formerly The Chase Manhattan
Bank), as Trustee, and indentures supplemental thereto through
December 1, 1994. (Designated in Registration Nos. 2-59843 as
Exhibit 2(a)-2, 2-60484 as Exhibits 2(a)-3 and 2(a)-4, 2-60716
as Exhibit 2(c), 2-67574 as Exhibit 2(c), 2-68687 as Exhibit
2(c), 2-69599 as Exhibit 4(a)-2, 2-71364 as Exhibit 4(a)-2,
2-73727 as Exhibit 4(a)-2, 33-5079 as Exhibit 4(a)-2, 33-17083
as Exhibit 4(a)-2, 33-22090 as Exhibit 4(a)-2, in Alabama
Power's Form 10-K for the year ended December 31, 1990, File
No. 1-3164, as Exhibit 4(c), in Registration Nos. 33-43917 as
Exhibit 4(a)-2, 33-45492 as Exhibit 4(a)-2, 33-48885 as
Exhibit 4(a)-2, 33-48917 as Exhibit 4(a)-2, in Form 8-K dated
January 20, 1993, File No. 1-3164, as Exhibit 4(a)-3, in Form
8-K dated February 17, 1993, File No. 1-3164, as Exhibit
4(a)-3, in Form 8-K dated March 10, 1993, File No. 1-3164, as
Exhibit 4(a)-3, in Certificate of Notification, File No.
70-8069, as Exhibits A and B, in Form 8-K dated June 24, 1993,
File No. 1-3164, as Exhibit 4, in Certificate of Notification,
File No. 70-8069, as Exhibit A, in Form 8-K dated November 16,
1993, File No. 1-3164, as Exhibit 4(b), in Certificate of
Notification, File No. 70-8069, as Exhibits A and B, in
Certificate of Notification, File No. 70-8069, as Exhibit A,
in Certificate of Notification, File No. 70-8069, as Exhibit A
and in Form 8-K dated November 30, 1994, File No. 1-3164, as
Exhibit 4.)
E-4
(b)2 - Subordinated Note Indenture dated as of January 1, 1996,
between Alabama Power and JPMorgan Chase Bank (formerly The
Chase Manhattan Bank), as Trustee, and indenture supplemental
thereto dated as of January 1, 1996. (Designated in
Certificate of Notification, File No. 70-8461, as Exhibits E
and F.)
*(b)3 - Satisfaction and Discharge of Subordinated Note Indenture
dated as of April 30, 2003 by JPMorgan Chase Bank, as Trustee,
to Alabama Power related to discharging Alabama Power's
Subordinated Note Indenture dated as of January 1, 1996,
between Alabama Power and JPMorgan Chase Bank (formerly The
Chase Manhattan Bank), as Trustee, and indenture supplemental
thereto dated as of January 1, 1996.
(b)4 - Subordinated Note Indenture dated as of January 1, 1997,
between Alabama Power and JPMorgan Chase Bank (formerly The
Chase Manhattan Bank), as Trustee, and indentures supplemental
thereto through October 2, 2002. (Designated in Form 8-K dated
January 9, 1997, File No. 1-3164, as Exhibits 4.1 and 4.2, in
Form 8-K dated February 18, 1999, File No. 3164, as Exhibit
4.2 and , in Form 8-K dated September 26, 2002, File No. 3164,
as Exhibits 4.9-A and 4.9-B.)
(b)5 - Senior Note Indenture dated as of December 1, 1997,
between Alabama Power and JPMorgan Chase Bank (formerly The
Chase Manhattan Bank), as Trustee, and indentures supplemental
thereto through February 17, 2004. (Designated in Form 8-K
dated December 4, 1997, File No. 1-3164, as Exhibits 4.1 and
4.2, in Form 8-K dated February 20, 1998, File No. 1-3164, as
Exhibit 4.2, in Form 8-K dated April 17, 1998, File No.
1-3164, as Exhibit 4.2, in Form 8-K dated August 11, 1998,
File No. 1-3164, as Exhibit 4.2, in Form 8-K dated September
8, 1998, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated
September 16, 1998, File No. 1-3164, as Exhibit 4.2, in Form
8-K dated October 7, 1998, File No. 1-3164, as Exhibit 4.2, in
Form 8-K dated October 28, 1998, File No. 1-3164, as Exhibit
4.2, in Form 8-K dated November 12, 1998, File No. 1-3164, as
Exhibit 4.2, in Form 8-K dated May 19, 1999, File No. 1-3164,
as Exhibit 4.2, in Form 8-K dated August 13, 1999, File No.
1-3164, as Exhibit 4.2, in Form 8-K dated September 21, 1999,
File No. 1-3164, as Exhibit 4.2, in Form 8-K dated May 11,
2000, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated
August 22, 2001, File No. 1-3164, as Exhibits 4.2(a) and
4.2(b), in Form 8-K dated June 21, 2002, File No. 1-3164, as
Exhibit 4.2(a), in Form 8-K dated October 16, 2002, File No.
1-3164, as Exhibit 4.2(a), in Form 8-K dated November 20,
2002, File No. 1-3164, as Exhibit 4.2(a), in Form 8-K dated
December 6, 2002, File No. 1-3164, as Exhibit 4.2, in Form 8-K
dated February 11, 2003, File No. 1-3164, as Exhibits 4.2(a)
and 4.2(b), in Form 8-K dated March 12, 2003, File No. 1-3164,
as Exhibit 4.2, in Form 8-K dated April 15, 2003, File No.
1-3164, as Exhibit 4.2, in Form 8-K dated May 1, 2003, File
No. 1-3164, as Exhibit 4.2, in Form 8-K dated November 14,
2003, File No. 1-3164, as Exhibit 4.2 and in Form 8-K dated
February 10, 2004, File No. 1-3164, as Exhibit 4.2.)
(b)6 - Amended and Restated Trust Agreement of Alabama Power
Capital Trust IV dated as of September 1, 2002. (Designated in
Form 8-K dated September 26, 2002, File No. 1-3164, as Exhibit
4.12-A.)
E-5
(b)7 - Amended and Restated Trust Agreement of Alabama Power
Capital Trust V dated as of September 1, 2002. (Designated in
Form 8-K dated September 26, 2002, File No. 1-3164, as Exhibit
4.12-B.)
(b)8 - Guarantee Agreement relating to Alabama Power Capital
Trust IV dated as of September 1, 2002. (Designated in Form
8-K dated September 26, 2002, File No. 1-3164, as Exhibit
4.16-A.)
(b)9 - Guarantee Agreement relating to Alabama Power Capital
Trust V dated as of September 1, 2002. (Designated in Form 8-K
dated September 26, 2002, File No. 1-3164, as Exhibit 4.16-B.)
Georgia Power
(c)1 - Subordinated Note Indenture dated as of August 1, 1996,
between Georgia Power and JPMorgan Chase Bank (formerly The
Chase Manhattan Bank), as Trustee, and indentures supplemental
thereto through January 1, 1997. (Designated in Form 8-K dated
August 21, 1996, File No. 1-6468, as Exhibits 4.1 and 4.2 and
in Form 8-K dated January 9, 1997, File No. 1-6468, as Exhibit
4.2.)
(c)2 - Subordinated Note Indenture dated as of June 1, 1997,
between Georgia Power and JPMorgan Chase Bank (formerly The
Chase Manhattan Bank), as Trustee, and indentures supplemental
thereto through January 23, 2004. (Designated in Certificate
of Notification, File No. 70-8461, as Exhibits D and E, in
Form 8-K dated February 17, 1999, File No. 1-6468, as Exhibit
4.4, in Form 8-K dated June 13, 2002, File No. 1-6468, as
Exhibit 4.4, in Form 8-K dated October 30, 2002, File No.
1-6468, as Exhibit 4.4 and in Form 8-K dated January 15, 2004,
File No. 1-6468, as Exhibit 4.4.)
(c)3 - Senior Note Indenture dated as of January 1, 1998, between
Georgia Power and JPMorgan Chase Bank (formerly The Chase
Manhattan Bank), as Trustee, and indentures supplemental
thereto through February 17, 2004. (Designated in Form 8-K
dated January 21, 1998, File No. 1-6468, as Exhibits 4.1 and
4.2, in Forms 8-K each dated November 19, 1998, File No.
1-6468, as Exhibit 4.2, in Form 8-K dated March 3, 1999, File
No. 1-6469 as Exhibit 4.2, in Form 8-K dated February 15,
2000, File No. 1-6469 as Exhibit 4.2, in Form 8-K dated
January 26, 2001, File No. 1-6469 as Exhibits 4.2(a) and
4.2(b), in Form 8-K dated February 16, 2001, File No. 1-6469
as Exhibit 4.2, in Form 8-K dated May 1, 2001, File No.
1-6468, as Exhibit 4.2, in Form 8-K dated June 27, 2002, File
No. 1-6468, as Exhibit 4.2, in Form 8-K dated November 15,
2002, File No. 1-6468, as Exhibit 4.2, in Form 8-K dated
February 13, 2003, File No. 1-6468, as Exhibit 4.2, in Form
8-K dated February 21, 2003, File No. 1-6468, as Exhibit 4.2,
in Form 8-K dated April 10, 2003, File No. 1-6468, as Exhibits
4.1, 4.2 and 4.3, in Form 8-K dated September 8, 2003, File
No. 1-6468, as Exhibit 4.1, in Form 8-K dated September 23,
2003, File No. 1-6468, as Exhibit 4.1, in Form 8-K dated
January 12, 2004, File No. 1-6468, as Exhibits 4.1 and 4.2 and
in Form 8-K dated February 12, 2004, File No. 1-6468, as
Exhibit 4.1.)
(c)4 - Amended and Restated Trust Agreement of Georgia Power
Capital Trust IV dated as of February 1, 1999. (Designated in
Form 8-K dated February 17, 1999, as Exhibit 4.7-A)
E-6
(c)5 - Amended and Restated Trust Agreement of Georgia Power
Capital Trust V dated as of June 1, 2002. (Designated in Form
8-K dated June 13, 2002, as Exhibit 4.7-A.)
(c)6 - Amended and Restated Trust Agreement of Georgia Power
Capital Trust VI dated as of November 1, 2002. (Designated in
Form 8-K dated October 30, 2002, as Exhibit 4.7-A.)
(c)7 - Amended and Restated Trust Agreement of Georgia Power
Capital Trust VII dated as of January 1, 2004. (Designated in
Form 8-K dated January 15, 2004, as Exhibit 4.7-A.)
(c)8 - Guarantee Agreement relating to Georgia Power Capital
Trust IV dated as of February 1, 1999. (Designated in Form 8-K
dated February 17, 1999, as Exhibit 4.11-A.)
(c)9 - Guarantee Agreement relating to Georgia Power Capital
Trust V dated as of June 1, 2002. (Designated in Form 8-K
dated June 13, 2002, as Exhibit 4.11-A.)
(c)10 - Guarantee Agreement relating to Georgia Power Capital
Trust VI dated as of November 1, 2002. (Designated in Form 8-K
dated October 30, 2002, as Exhibit 4.11-A.)
(c)11 - Guarantee Agreement relating to Georgia Power Capital
Trust VII dated as of January 1, 2004. (Designated in Form 8-K
dated January 15, 2004, as Exhibit 4.11-A.)
Gulf Power
(d)1 - Indenture dated as of September 1, 1941, between Gulf
Power and JPMorgan Chase Bank (formerly The Chase Manhattan
Bank), as Trustee, and indentures supplemental thereto through
November 1, 1996. (Designated in Registration Nos. 2-4833 as
Exhibit B-3, 2-62319 as Exhibit 2(a)-3, 2-63765 as Exhibit
2(a)-3, 2-66260 as Exhibit 2(a)-3, 33-2809 as Exhibit 4(a)-2,
33-43739 as Exhibit 4(a)-2, in Gulf Power's Form 10-K for the
year ended December 31, 1991, File No. 0-2429, as Exhibit
4(b), in Form 8-K dated August 18, 1992, File No. 0-2429, as
Exhibit 4(a)-3, in Registration No. 33-50165 as Exhibit
4(a)-2, in Form 8-K dated July 12, 1993, File No. 0-2429, as
Exhibit 4, in Certificate of Notification, File No. 70-8229,
as Exhibit A, in Certificate of Notification, File No.
70-8229, as Exhibits E and F, in Form 8-K dated January 17,
1996, File No. 0-2429, as Exhibit 4, in Certificate of
Notification, File No. 70-8229, as Exhibit A, in Certificate
of Notification, File No. 70-8229, as Exhibit A and in Form
8-K dated November 6, 1996, File No. 0-2429, as Exhibit 4.)
E-7
(d)2 - Subordinated Note Indenture dated as of January 1, 1997,
between Gulf Power and JPMorgan Chase Bank (formerly The Chase
Manhattan Bank), as Trustee, and indentures supplemental
thereto through December 13, 2002. (Designated in Form 8-K
dated January 27, 1997, File No. 0-2429, as Exhibits 4.1 and
4.2, in Form 8-K dated July 28, 1997, File No. 0-2429, as
Exhibit 4.2, in Form 8-K dated January 13, 1998, File No.
0-2429, as Exhibit 4.2, in Form 8-K dated November 8, 2001,
File No. 0-2429, as Exhibit 4.2 and in Form 8-K dated December
5, 2002, File No. 0-2429, as Exhibit 4.2.)
(d)3 - Senior Note Indenture dated as of January 1, 1998, between
Gulf Power and JPMorgan Chase Bank (formerly The Chase
Manhattan Bank), as Trustee, and indentures supplemental
thereto through September 16, 2003. (Designated in Form 8-K
dated June 17, 1998, File No. 0-2429, as Exhibits 4.1 and 4.2,
in Form 8-K dated August 17, 1999, File No. 0-2429, as Exhibit
4.2, in Form 8-K dated July 31, 2001, File No. 0-2429, as
Exhibit 4.2, in Form 8-K dated October 5, 2001, File No.
0-2429, as Exhibit 4.2, in Form 8-K dated January 18, 2002,
File No. 0-2429, as Exhibit 4.2, in Form 8-K dated March 21,
2003, File No. 0-2429, as Exhibit 4.2, in Form 8-K dated July
10, 2003, File No. 0-2429, as Exhibits 4.1 and 4.2 and in Form
8-K dated September 5, 2003, File No. 0-2429, as Exhibit 4.1.)
(d)4 - Amended and Restated Trust Agreement of Gulf Power Capital
Trust III dated as of November 1, 2001. (Designated in Form
8-K dated November 8, 2001, File No. 0-2429, as Exhibit 4.5.)
(d)5 - Amended and Restated Trust Agreement of Gulf Power Capital
Trust IV dated as of December 1, 2002. (Designated in Form 8-K
dated December 5, 2002, File No. 0-2429, as Exhibit 4.5.)
(d)6 - Guarantee Agreement relating to Gulf Power Capital Trust
III dated as of November 1, 2001. (Designated in Form 8-K
dated November 8, 1998, File No. 0-2429, as Exhibit 4.8.)
(d)7 - Guarantee Agreement relating to Gulf Power Capital Trust
IV dated as of December 1, 2002. (Designated in Form 8-K dated
December 5, 2002, File No. 0-2429, as Exhibit 4.8.)
Mississippi Power
(e)1 - Indenture dated as of September 1, 1941, between
Mississippi Power and Deutsche Bank Trust Company Americas
(formerly known as Bankers Trust Company), as Successor
Trustee, and indentures supplemental thereto through December
1, 1995. (Designated in Registration Nos. 2-4834 as Exhibit
B-3, 2-62965 as Exhibit 2(b)-2, 2-66845 as Exhibit 2(b)-2,
2-71537 as Exhibit 4(a)-(2), 33-5414 as Exhibit 4(a)-(2),
33-39833 as Exhibit 4(a)-2, in Mississippi Power's Form 10-K
for the year ended December 31, 1991, File No. 0-6849, as
Exhibit 4(b), in Form 8-K dated August 5, 1992, File No.
0-6849, as Exhibit 4(a)-2, in Second Certificate of
Notification, File No. 70-7941, as Exhibit I, in Mississippi
Power's Form 8-K dated February 26, 1993, File No. 0-6849, as
Exhibit 4(a)-2, in Certificate of Notification, File No.
70-8127, as Exhibit A, in Form 8-K dated June 22, 1993, File
No. 0-6849, as Exhibit 1, in Certificate of Notification, File
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No. 70-8127, as Exhibit A, in Form 8-K dated March 8, 1994,
File No. 0-6849, as Exhibit 4, in Certificate of Notification,
File No. 70-8127, as Exhibit C and in Form 8-K dated December
5, 1995, File No. 0-6849, as Exhibit 4.)
(e)2 - Senior Note Indenture dated as of May 1, 1998 between
Mississippi Power and Deutsche Bank Trust Company Americas
(formerly known as Bankers Trust Company), as Trustee and
indentures supplemental thereto through April 29, 2003.
(Designated in Form 8-K dated May 14, 1998, File No. 0-6849,
as Exhibits 4.1, 4.2(a) and 4.2(b), in Form 8-K dated March
22, 2000, File No. 0-6849, as Exhibit 4.2, in Form 8-K dated
March 12, 2002, File No. 0-6849, as Exhibit 4.2 and in Form
8-K dated April 24, 2003, File No. 001-11229, as Exhibit 4.2.)
(e)3 - Subordinated Note Indenture dated as of February 1, 1997,
between Mississippi Power and Deutsche Bank Trust Company
Americas (formerly known as Bankers Trust Company), as
Trustee, and indenture supplemental thereto dated as of March
22, 2002. (Designated in Form 8-K dated February 20, 1997,
File No. 0-6849, as Exhibits 4.1 and 4.2 and in Form 8-K dated
March 15, 2002, File No. 0-6849, as Exhibit 4.5.)
(e)4 - Amended and Restated Trust Agreement of Mississippi Power
Capital Trust II dated as of March 1, 2002. (Designated in
Form 8-K dated March 15, 2002, File No. 0-6849, as Exhibit
4.5.)
(e)5 - Guarantee Agreement relating to Mississippi Power Capital
Trust II dated as of March 1, 2002. (Designated in Form 8-K
dated March 15, 2002, File No. 0-6849, as Exhibit 4.8.)
Savannah Electric
(f)1 - Indenture dated as of March 1, 1945, between Savannah
Electric and The Bank of New York, as Trustee, and indentures
supplemental thereto through May 1, 1996. (Designated in
Registration Nos. 33-25183 as Exhibit 4(a)-(1), 33-41496 as
Exhibit 4(a)-(2), 33-45757 as Exhibit 4(a)-(2), in Savannah
Electric's Form 10-K for the year ended December 31, 1991,
File No. 1-5072, as Exhibit 4(b), in Form 8-K dated July 8,
1992, File No. 1-5072, as Exhibit 4(a)-3, in Registration No.
33-50587 as Exhibit 4(a)-(2), in Form 8-K dated July 22, 1993,
File No. 1-5072, as Exhibit 4, in Form 8-K dated May 18, 1995,
File No. 1-5072, as Exhibit 4 and in Form 8-K dated May 23,
1996, File No. 1-5072, as Exhibit 4.)
(f)2 - Senior Note Indenture dated as of March 1, 1998 between
Savannah Electric and The Bank of New York, as Trustee and
indentures supplemental thereto through December 17, 2003.
(Designated in Form 8-K dated March 9, 1998, File No. 1-5072,
as Exhibits 4.1 and 4.2, in Form 8-K dated May 8, 2001, File
No. 1-5072, as Exhibits 4.2(a) and 4.2(b), in Form 8-K dated
March 4, 2002, File No. 1-5072, as Exhibit 4.2, in Form 8-K
dated November 4, 2002, File No. 1-5072, as Exhibit 4.2 and in
Form 8-K dated December 10, 2003, File No. 1-5072, as Exhibits
4.1 and 4.2.)
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(f)3 - Subordinated Note Indenture dated as of December 1, 1998,
between Savannah Electric and The Bank of New York, as
Trustee, and indenture supplemental thereto dated as of
December 9, 1998. (Designated in Form 8-K dated December 3,
1998, File No. 1-5072, as Exhibit 4.3 and 4.4.)
(f)4 - Amended and Restated Trust Agreement of Savannah Electric
Capital Trust I dated as of December 1, 1998. (Designated in
Form 8-K dated December 3, 1998, File No. 1-5072, as Exhibit
4.7.)
(f)5 - Guarantee Agreement relating to Savannah Electric Capital
Trust I dated as of December 1, 1998. (Designated in Form 8-K
dated December 3, 1998, File No. 1-5072, as Exhibit 4.11.)
Southern Power
(g)1 - Indenture dated as of June 1, 2002, between Southern Power
and The Bank of New York, as Trustee, and indentures
supplemental thereto through July 8, 2003. (Designated in
Registration No. 333-98553 as Exhibits 4.1 and 4.2 and in
Southern Power's Form 10-Q for the quarter ended June 30,
2003, File No. 333-98553, as Exhibit 4(g)1.)
(10) Material Contracts
Southern Company
(a)1 - Service contracts dated as of January 1, 1984, between SCS
and Alabama Power, Georgia Power, Gulf Power, Mississippi
Power, SEGCO and Southern Company and Amendment No. 1 dated as
of September 6, 1985 between SCS and Southern Company.
(Designated in Southern Company's Form 10-K for the year ended
December 31, 1984, File No. 1-3526, as Exhibit 10(a) and in
Southern Company's Form 10-K for the year ended December 31,
1985, File No. 1-3526, as Exhibit 10(a)(3).)
(a)2 - Service contract dated as of January 1, 2001, between SCS
and Southern Power. (Designated in Southern Company's Form
10-K for the year ended December 31, 2001, File No. 1-3526, as
Exhibit 10(a)(2).)
(a)3 - Service contract dated as of March 3, 1988, between SCS
and Savannah Electric. (Designated in Savannah Electric's Form
10-K for the year ended December 31, 1987, File No. 1-5072, as
Exhibit 10-p.)
(a)4 - Service contract dated as of January 15, 1991, between SCS
and Southern Nuclear. (Designated in Southern Company's Form
10-K for the year ended December 31, 1991, File No. 1-3526, as
Exhibit 10(a)(4).)
(a)5 - Service contract dated as of December 12, 1994, between
SCS and Mobile Energy Services Company, Inc. (Designated in
Southern Company's Form 10-K for the year ended December 31,
1994, File No. 1-3526, as Exhibit 10(a)58.)
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(a)6 - Interchange contract dated February 17, 2000, between
Alabama Power, Georgia Power, Gulf Power, Mississippi Power,
Savannah Electric, Southern Power and SCS. (Designated in
Southern Company's Form 10-K for the year ended December 31,
2000, File No. 1-3526, as Exhibit 10(a)6.)
(a)7 - Agreement dated as of January 27, 1959, Amendment No. 1
dated as of October 27, 1982 and Amendment No. 2 dated
November 4, 1993 and effective June 1, 1994, among SEGCO,
Alabama Power and Georgia Power. (Designated in Registration
No. 2-59634 as Exhibit 5(c), in Georgia Power's Form 10-K for
the year ended December 31, 1982, File No. 1-6468, as Exhibit
10(d)(2) and in Alabama Power's Form 10-K for the year ended
December 31, 1994, File No. 1-3164, as Exhibit 10(b)18.)
(a)8 - Joint Committee Agreement dated as of August 27, 1976,
among Georgia Power, OPC, MEAG and Dalton. (Designated in
Registration No. 2-61116 as Exhibit 5(d).)
(a)9 - Edwin I. Hatch Nuclear Plant Purchase and Ownership
Participation Agreement dated as of January 6, 1975, between
Georgia Power and OPC. (Designated in Form 8-K for January,
1975, File No. 1-6468, as Exhibit (b)(1).)
(a)10 - Edwin I. Hatch Nuclear Plant Operating Agreement dated as
of January 6, 1975, between Georgia Power and OPC. (Designated
in Form 8-K for January, 1975, File No. 1-6468, as Exhibit
(b)(3).)
(a)11 - Revised and Restated Integrated Transmission System
Agreement dated as of November 12, 1990, between Georgia Power
and OPC. (Designated in Georgia Power's Form 10-K for the year
ended December 31, 1990, File No. 1-6468, as Exhibit 10(g).)
(a)12 - Plant Hal Wansley Purchase and Ownership Participation
Agreement dated as of March 26, 1976, between Georgia Power
and OPC. (Designated in Certificate of Notification, File No.
70-5592, as Exhibit A.)
(a)13 - Plant Hal Wansley Operating Agreement dated as of March
26, 1976, between Georgia Power and OPC. (Designated in
Certificate of Notification, File No. 70-5592, as Exhibit B.)
(a)14 - Edwin I. Hatch Nuclear Plant Purchase and Ownership
Participation Agreement dated as of August 27, 1976, between
Georgia Power, MEAG and Dalton. (Designated in Form 8-K dated
as of June 13, 1977, File No. 1-6468, as Exhibit (b)(1).)
(a)15 - Edwin I. Hatch Nuclear Plant Operating Agreement dated as
of August 27, 1976, between Georgia Power, MEAG and Dalton.
(Designated in Form 8-K for February 1977, File No. 1-6468, as
Exhibit (b)(2).)
(a)16 - Alvin W. Vogtle Nuclear Units Number One and Two Purchase
and Ownership Participation Agreement dated as of August 27,
1976 and Amendment No. 1 dated as of January 18, 1977, among
Georgia Power, OPC, MEAG and Dalton. (Designated in Form U-1,
File No. 70-5792, as Exhibit B-1 and in Form 8-K for January
1977, File No. 1-6468, as Exhibit (B)(3).)
E-11
(a)17 - Alvin W. Vogtle Nuclear Units Number One and Two
Operating Agreement dated as of August 27, 1976, among Georgia
Power, OPC, MEAG and Dalton. (Designated in Form U-1, File No.
70-5792, as Exhibit B-2.)
(a)18 - Alvin W. Vogtle Nuclear Units Number One and Two
Purchase, Amendment, Assignment and Assumption Agreement dated
as of November 16, 1983, between Georgia Power and MEAG.
(Designated in Georgia Power's Form 10-K for the year ended
December 31, 1983, File No. 1-6468, as Exhibit 10(k)(4).)
(a)19 - Plant Hal Wansley Purchase and Ownership Participation
Agreement dated as of August 27, 1976, between Georgia Power
and MEAG. (Designated in Form 8-K dated as of July 5, 1977,
File No. 1-6468, as Exhibit (b)(2).)
(a)20 - Plant Hal Wansley Operating Agreement dated as of August
27, 1976, between Georgia Power and MEAG. (Designated in Form
8-K dated as of July 5, 1977, File No. 1-6468, as Exhibit
(b)(4).)
(a)21 - Nuclear Operating Agreement between Southern Nuclear and
Georgia Power dated as of July 1, 1993. (Designated in
Southern Company's Form 10-K for the year ended December 31,
1997, File No. 1-3526, as Exhibit 10(a)21.)
(a)22 - Pseudo Scheduling and Services Agreement between Georgia
Power and MEAG dated as of April 8, 1997. (Designated in
Southern Company's Form 10-K for the year ended December 31,
1997, File No. 1-3526, as Exhibit 10(a)22.)
(a)23 - Plant Hal Wansley Purchase and Ownership Participation
Agreement dated as of April 19, 1977, between Georgia Power
and Dalton. (Designated in Form 8-K dated as of June 13, 1977,
File No. 1-6468, as Exhibit (b)(3).)
(a)24 - Plant Hal Wansley Operating Agreement dated as of April
19, 1977, between Georgia Power and Dalton. (Designated in
Form 8-K dated as of June 13, 1977, File No. 1-6468, as
Exhibit (b)(7).)
(a)25 - Plant Robert W. Scherer Units Number One and Two Purchase
and Ownership Participation Agreement dated as of May 15,
1980, Amendment No. 1 dated as of December 30, 1985, Amendment
No. 2 dated as of July 1, 1986, Amendment No. 3 dated as of
August 1, 1988 and Amendment No. 4 dated as of December 31,
1990, among Georgia Power, OPC, MEAG and Dalton. (Designated
in Form U-1, File No. 70-6481, as Exhibit B-3, in Southern
Company's Form 10-K for the year ended December 31, 1987, File
No. 1-3526, as Exhibit 10(o)(2), in Southern Company's Form
10-K for the year ended December 31, 1989, File No. 1-3526, as
Exhibit 10(n)(2) and in Southern Company's Form 10-K for the
year ended December 31, 1993, File No. 1-3526, as Exhibit
10(a)54.)
(a)26 - Plant Robert W. Scherer Units Number One and Two
Operating Agreement dated as of May 15, 1980, Amendment No. 1
dated as of December 3, 1985 and Amendment No. 2 dated as of
December 31, 1990, among Georgia Power, OPC, MEAG and Dalton.
(Designated in Form U-1, File No. 70-6481, as Exhibit B-4, in
Southern Company's Form 10-K for the year ended December 31,
1987, File No. 1-3526, as Exhibit 10(o)(4) and in Southern
Company's Form 10-K for the year ended December 31, 1993, File
No. 1-3526, as Exhibit 10(a)55.)
E-12
(a)27 - Plant Robert W. Scherer Purchase, Sale and Option
Agreement dated as of May 15, 1980, between Georgia Power and
MEAG. (Designated in Form U-1, File No. 70-6481, as Exhibit
B-1.)
(a)28 - Plant Robert W. Scherer Purchase and Sale Agreement dated
as of May 16, 1980, between Georgia Power and Dalton.
(Designated in Form U-1, File No. 70-6481, as Exhibit B-2.)
(a)29 - Plant Robert W. Scherer Unit Number Three Purchase and
Ownership Participation Agreement dated as of March 1, 1984,
Amendment No. 1 dated as of July 1, 1986 and Amendment No. 2
dated as of August 1, 1988, between Georgia Power and Gulf
Power. (Designated in Form U-1, File No. 70-6573, as Exhibit
B-4, in Southern Company's Form 10-K for the year ended
December 31, 1987, as Exhibit 10(o)(2) and in Southern
Company's Form 10-K for the year ended December 31, 1989, as
Exhibit 10(n)(2).)
(a)30 - Plant Robert W. Scherer Unit Number Three Operating
Agreement dated as of March 1, 1984, between Georgia Power and
Gulf Power. (Designated in Form U-1, File No. 70-6573, as
Exhibit B-5.)
(a)31 - Plant Robert W. Scherer Unit No. Four Amended and
Restated Purchase and Ownership Participation Agreement by and
among Georgia Power, FP&L and JEA, dated as of December 31,
1990 and Amendment No. 1 dated as of June 15, 1994.
(Designated in Form U-1, File No. 70-7843, as Exhibit B-1 and
in Southern Company's Form 10-K for the year ended December
31, 1994, File No. 1-3526, as Exhibit 10(a)60.)
(a)32 - Plant Robert W. Scherer Unit No. Four Operating Agreement
by and among Georgia Power, FP&L and JEA, dated as of December
31, 1990 and Amendment No. 1 dated as of June 15, 1994.
(Designated in Form U-1, File No. 70-7843, as Exhibit B-2 and
in Southern Company's Form 10-K for the year ended December
31, 1994, File No. 1-3526, as Exhibit 10(a)61.)
(a)33 - Unit Power Sales Agreement dated July 19, 1988, between
FPC and Alabama Power, Georgia Power, Gulf Power, Mississippi
Power, Savannah Electric and SCS. (Designated in Savannah
Electric's Form 10-K for the year ended December 31, 1988,
File No. 1-5072, as Exhibit 10(d).)
(a)34 - Amended Unit Power Sales Agreement dated July 20, 1988,
between FP&L and Alabama Power, Georgia Power, Gulf Power,
Mississippi Power, Savannah Electric and SCS. (Designated in
Savannah Electric's Form 10-K for the year ended December 31,
1988, File No. 1-5072, as Exhibit 10(e).)
(a)35 - Amended Unit Power Sales Agreement dated August 17, 1988,
between JEA and Alabama Power, Georgia Power, Gulf Power,
Mississippi Power, Savannah Electric and SCS. (Designated in
Savannah Electric's Form 10-K for the year ended December 31,
1988, File No. 1-5072, as Exhibit 10(f).)
E-13
(a)36 - Rocky Mountain Pumped Storage Hydroelectric Project
Ownership Participation Agreement dated November 18, 1988,
between OPC and Georgia Power. (Designated in Georgia Power's
Form 10-K for the year ended December 31, 1988, File No.
1-6468, as Exhibit 10(x).)
(a)37 - Rocky Mountain Pumped Storage Hydroelectric Project
Operating Agreement dated November 18, 1988, between OPC and
Georgia Power. (Designated in Georgia Power's Form 10-K for
the year ended December 31, 1988, File No. 1-6468, as Exhibit
10(y).)
(a)38 - Purchase and Ownership Agreement for Joint Ownership
Interest in the James H. Miller, Jr. Steam Electric Generating
Plant Units One and Two dated November 18, 1988, between
Alabama Power and AEC. (Designated in Form U-1, File No.
70-7609, as Exhibit B-1.)
(a)39 - Operating Agreement for Joint Ownership Interest in the
James H. Miller, Jr. Steam Electric Generating Plant Units One
and Two dated November 18, 1988, between Alabama Power and
AEC. (Designated in Form U-1, File No. 70-7609, as Exhibit
B-2.)
(a)40 - Transmission Facilities Agreement dated February 25,
1982, Amendment No. 1 dated May 12, 1982 and Amendment No. 2
dated December 6, 1983, between Entergy Corporation (formerly
Gulf States) and Mississippi Power. (Designated in Mississippi
Power's Form 10-K for the year ended December 31, 1981, File
No. 0-6849, as Exhibit 10(f), in Mississippi Power's Form 10-K
for the year ended December 31, 1982, File No. 0-6849, as
Exhibit 10(f)(2) and in Mississippi Power's Form 10-K for the
year ended December 31, 1983, File No. 0-6849, as Exhibit
10(f)(3).)
(a)41 - Long Term Transaction Service Agreement between Georgia
Power and OPC dated as of February 26, 1999. (Designated in
Southern Company's Form 10-K for the year ended December 31,
1999, File No. 1-3526, as Exhibit 10(a)46.)
(a)42 - Revised and Restated Coordination Services Agreement
between and among Georgia Power, OPC and Georgia Systems
Operations Corporation dated as of September 10, 1997.
(Designated in Southern Company's Form 10-K for the year ended
December 31, 1997, File No. 1-3526, as Exhibit 10(a)48.)
(a)43 - Amended and Restated Nuclear Managing Board Agreement for
Plant Hatch and Plant Vogtle among Georgia Power, OPC, MEAG
and Dalton dated as of July 1, 1993. (Designated in Southern
Company's Form 10-K for the year ended December 31, 1993, File
No. 1-3526, as Exhibit 10(a)49.)
(a)44 - Integrated Transmission System Agreement, Power Sale and
Coordination Umbrella Agreement between Georgia Power and OPC
dated as of November 12, 1990. (Designated in Georgia Power's
Form 10-K for the year ended December 31, 1990, File No.
1-6468, as Exhibit 10(ff).)
E-14
(a)45 - Revised and Restated Integrated Transmission System
Agreement between Georgia Power and Dalton dated as of
December 7, 1990. (Designated in Georgia Power's Form 10-K for
the year ended December 31, 1990, File No. 1-6468, as Exhibit
10(gg).)
(a)46 - Revised and Restated Integrated Transmission System
Agreement between Georgia Power and MEAG dated as of December
7, 1990. (Designated in Georgia Power's Form 10-K for the year
ended December 31, 1990, File No. 1-6468, as Exhibit 10(hh).)
(a)47 - Long Term Transmission Service Agreement between Entergy
Power, Inc. and Alabama Power, Mississippi Power and SCS.
(Designated in Southern Company's Form 10-K for the year ended
December 31, 1992, File No. 1-3526, as Exhibit 10(a)53.)
(a)48 - Plant Scherer Managing Board Agreement dated as of
December 31, 1990 among Georgia Power, OPC, MEAG, Dalton, Gulf
Power, FP&L and JEA. (Designated in Southern Company's Form
10-K for the year ended December 31, 1993, File No. 1-3526, as
Exhibit 10(a)56.)
(a)49 - Plant McIntosh Combustion Turbine Purchase and Ownership
Participation Agreement between Georgia Power and Savannah
Electric dated as of December 15, 1992. (Designated in
Southern Company's Form 10-K for the year ended December 31,
1993, File No. 1-3526, as Exhibit 10(a)57.)
(a)50 - Plant McIntosh Combustion Turbine Operating Agreement
between Georgia Power and Savannah Electric dated as of
December 15, 1992. (Designated in Southern Company's Form 10-K
for the year ended December 31, 1993, File No. 1-3526, as
Exhibit 10(a)58.)
(a)51 - Operating Agreement for the Joseph M. Farley Nuclear
Plant between Alabama Power and Southern Nuclear dated as of
December 23, 1991. (Designated in Form U-1, File No. 70-7530,
as Exhibit B-7.)
(a)52 - Amended and Restated Credit Agreement among Southern
Power, Citibank N.A., as the administrative agent, and the
lenders listed therein dated as of April 17, 2003. (Designated
in Southern Company's Form 10-Q for the quarter ended March
31, 2003, File No. 1-3526, as Exhibit 10(a)1.)
(a)53 - Completion Guarantee among Southern Company, Southern
Power and Citibank, N.A., in its capacity as agent for the
Lenders under the Credit Facility dated as of November 15,
2001. (Designated in Registration No. 333-98553 as Exhibit
10.2(a).)
(a)54 - Completion Guarantee Supplement by Southern Company and
Southern Power dated as of April 22, 2002. (Designated in
Registration No. 333-98553 as Exhibit 10.2(b).)
E-15
(a)55 - Letter Amendment No. 1 to Completion Guarantee among
Southern Company, Southern Power and Citibank, N.A. in its
capacity as agent for the Lenders under the Credit Facility
dated as of April 17, 2003. (Designated in Southern Company's
Form 10-Q for the quarter ended March 31, 2003, File No.
1-3526, as Exhibit 10(a)2.)
(a)56 - Equity Contribution Agreement among Southern Company and
Citibank, N.A. in its capacity as agent for the Lenders under
the Credit Facility dated as of November 15, 2001. (Designated
in Registration No. 333-98553 as Exhibit 10.3(a).)
(a)57 - Letter Amendment No. 1 to Equity Contribution Agreement
among Southern Company, Southern Power and Citibank, N.A. in
its capacity as agent for the Lenders under the Credit
Facility dated as of April 17, 2003. (Designated in Southern
Company's Form 10-Q for the quarter ended March 31, 2003, File
No. 1-3526, as Exhibit 10(a)3.)
(a)58 - Equity Contribution Agreement Supplement by Southern
Company and Southern Power dated as of April 22, 2002.
(Designated in Registration No. 333-98553 as Exhibit 10.3(b).)
*(a)59 - Amended and Restated Operating Agreement between Southern
Power and Alabama Power effective December 1, 2002.
*(a)60 - Amended and Restated Operating Agreement between Southern
Power and Georgia Power effective December 1, 2002.
*(a)61 - Operating Agreement between Southern Power and Savannah
Electric effective January 1, 2003.
(a)62 - Interconnection Agreement by and between Southern Power
and Georgia Power for Plant Dahlberg dated as of July 31,
2001. (Designated in Registration No. 333-98553 as Exhibit
10.8.)
(a)63 - Interconnection Agreement by and between Southern Power
and Georgia Power for Wansley CC Units 6 and 7 dated as of May
10, 2001. (Designated in Registration No. 333-98553 as Exhibit
10.9.)
(a)64 - Interconnection Agreement by and between Southern Power
and Georgia Power for Goat Rock CC Unit 1 dated as of May 10,
2001. (Designated in Registration No. 333-98553 as Exhibit
10.10.)
(a)65 - Revised and Restated Interconnection Agreement by and
between Southern Power and Georgia Power for Goat Rock CC Unit
2 dated as of October 18, 2001. (Designated in Registration
No. 333-98553 as Exhibit 10.11.)
(a)66 - Interconnection Agreement by and between Southern Power
and Alabama Power for Autaugaville Combined Cycle Unit 1 dated
as of June 25, 2001. (Designated in Registration No. 333-98553
as Exhibit 10.12.)
E-16
(a)67 - Interconnection Agreement by and between Southern Power
and Alabama Power for Autaugaville Combined Cycle Unit 2 dated
as of June 25, 2001. (Designated in Registration No. 333-98553
as Exhibit 10.13.)
(a)68 - Purchased Power Agreement between Georgia Power and LG&E
Energy Marketing Inc. dated as of November 24, 1998.
(Designated in Registration No. 333-98553 as Exhibit 10.15.)
(a)69 - Purchased Power Agreement between Georgia Power and LG&E
Energy Marketing Inc. dated as of October 6, 1999. (Designated
in Registration No. 333-98553 as Exhibit 10.16.)
(a)70 - Assignment and Assumption Agreement by and between
Georgia Power and Southern Power dated as of July 31, 2001.
(Designated in Registration No. 333-98553 as Exhibit 10.17.)
(a)71 - Power Purchase Agreement between Southern Power and
Alabama Power dated as of June 1, 2001. (Designated in
Registration No. 333-98553 as Exhibit 10.18.)
(a)72 - Amended and Restated Power Purchase Agreement between
Southern Power and Georgia Power at Plant Autaugaville dated
as of August 6, 2001. (Designated in Registration No.
333-98553 as Exhibit 10.19.)
(a)73 - Contract for the Purchase of Firm Capacity and Energy
between Southern Power and Savannah Electric dated as of July
26, 2001. (Designated in Registration No. 333-98553 as Exhibit
10.20.)
(a)74 - Contract for the Purchase of Firm Capacity and Energy
between Southern Power and Georgia Power dated as of July 26,
2001. (Designated in Registration No. 333-98553 as Exhibit
10.21.)
(a)75 - Power Purchase Agreement between Southern Power and
Georgia Power at Plant Goat Rock dated as of March 30, 2001.
(Designated in Registration No. 333-98553 as Exhibit 10.22.)
(a)76 - Power Purchase Agreement between Southern Company -
Florida LLC and Kissimmee Utility Authority dated as of March
19, 2001. (Designated in Registration No. 333-98553 as Exhibit
10.23.)
(a)77 - Power Purchase Agreement between Southern Company -
Florida LLC and Florida Municipal Power Agency dated as of
March 19, 2001. (Designated in Registration No. 333-98553 as
Exhibit 10.24.)
(a)78 - Power Purchase Agreement between Southern Company -
Florida LLC and Orlando Utilities Commission dated as of March
19, 2001. (Designated in Registration No. 333-98553 as Exhibit
10.25.)
E-17
(a)79 - The Southern Company Employee Savings Plan, Amended and
Restated effective January 1, 2002 and Amendments one through
five thereto. (Designated in Southern Company's Form 10-K for
the year ended December 31, 2001, File No. 1-3526, as Exhibit
10(a)52, in Registration No. 333-96883, as Exhibit 10.29 and
in Southern Company's Form 10-Q for the quarter ended
September 30, 2003, File No.1-3526, as Exhibit 10(a)1.)
(a)80 - The Southern Company Employee Stock Ownership Plan,
Amended and Restated effective January 1, 2002 and Amendments
one through five thereto. (Designated in Southern Company's
Form 10-K for the year ended December 31, 2001, File No.
1-3526, as Exhibit 10(a)53, in Southern Company's Form 10-K
for the year ended December 31, 2002, File No. 1-3526, as
Exhibit 10(a)81 and in Southern Company's Form 10-Q for the
quarter ended September 30, 2003, File No. 1-3526, as Exhibit
10(a)2.)
# (a)81 - Southern Company Omnibus Incentive Compensation Plan,
Amended and Restated effective May 23, 2001. (Designated in
Form S-8, File No. 333-73462, as Exhibit 4(c).)
# (a)82 - The Deferred Compensation Plan for the Directors of The
Southern Company, Amended and Restated effective February 19,
2001. (Designated in Southern Company's Form 10-K for the year
ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)59.)
# (a)83 - The Southern Company Outside Directors Pension Plan.
(Designated in Southern Company's Form 10-K for the year ended
December 31, 1994, File No. 1-3526, as Exhibit 10(a)77.)
# (a)84 - The Southern Company Deferred Compensation Plan, Amended
and Restated effective February 23, 2001 and First Amendment
thereto. (Designated in Southern Company's Form 10-K for the
year ended December 31, 2000, File No. 1-3526, as Exhibit
10(a)61 and in Southern Company's Form 10-Q for the quarter
ended September 30, 2003, File No. 1-3526, as Exhibit 10(a)4.)
# (a)85 - The Southern Company Outside Directors Stock Plan and
First Amendment thereto. (Designated in Registration No.
33-54415 as Exhibit 4(c) and in Southern Company's Form 10-K
for the year ended December 31, 1995, File No. 1-3526, as
Exhibit 10(a)79.)
# (a)86 - Outside Directors Stock Plan for Subsidiaries of The
Southern Company, Amended and Restated effective January 1,
2000. (Designated in Southern Company's Form 10-K for the year
ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)63.)
(a)87 - The Southern Company Pension Plan, Amended and Restated
effective January 1, 2002 and First Amendment thereto.
(Designated in Southern Company's Form 10-K for the year ended
December 31, 2002, File No. 1-3526, as Exhibit 10(a)88 and in
Southern Company's Form 10-Q for the quarter ended June 30,
2003, File No. 1-3526, as Exhibit 10(a)4.)
E-18
# (a)88 - The Southern Company Supplemental Executive Retirement
Plan, Amended and Restated effective May 1, 2000. (Designated
in Southern Company's Form 10-K for the year ended December
31, 2001, File No. 1-3526, as Exhibit 10(a)62.)
# (a)89 - The Southern Company Supplemental Benefit Plan, Amended
and Restated effective May 1, 2000 and First Amendment
thereto. (Designated in Southern Company's Form 10-K for the
year ended December 31, 2000, File No. 1-3526, as Exhibit
10(a)64 and in Southern Company's Form 10-Q for the quarter
ended September 30, 2003, File No. 1-3526, as Exhibit 10(a)3.)
(a)90 - Southern Company Change in Control Severance Plan,
Amended and Restated effective May 1, 2003. (Designated in
Southern Company's Form 10-Q for the quarter ended June 30,
2003, File No. 1-3526, as Exhibit 10(a)1.)
# (a)91 - Southern Company Executive Change in Control Severance
Plan, Amended and Restated effective May 1, 2003. (Designated
in Southern Company's Form 10-Q for the quarter ended June 30,
2003, File No. 1-3526, as Exhibit 10(a)2.)
# (a)92 - Deferred Compensation Agreement between Southern Company,
Southern Nuclear and William G. Hairston III. (Designated in
Southern Company's Form 10-K for the year ended December 31,
1998, File No. 1-3526 as Exhibit 10(a)81.)
# (a)93 - Amended and Restated Change in Control Agreement between
Southern Company, Mississippi Power and Dwight H. Evans.
(Designated in Southern Company's Form 10-K for the year ended
December 31, 2000, File No. 1-3526, as Exhibit 10(a)81.)
# (a)94 - Amended and Restated Change in Control Agreement between
Southern Company, SCS and Henry Allen Franklin. (Designated in
Southern Company's Form 10-K for the year ended December 31,
2000, File No. 1-3526, as Exhibit 10(a)83.)
# (a)95 - Amended and Restated Change in Control Agreement between
Southern Company, Southern Nuclear and William G. Hairston,
III. (Designated in Southern Company's Form 10-K for the year
ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)84.)
# (a)96 - Amended and Restated Change in Control Agreement between
Southern Company, Savannah Electric and G. Edison Holland, Jr.
(Designated in Southern Company's Form 10-K for the year ended
December 31, 2000, File No. 1-3526, as Exhibit 10(a)86.)
# (a)97 - Amended and Restated Change in Control Agreement between
Southern Company, SCS and C. Alan Martin. (Designated in
Southern Company's Form 10-K for the year ended December 31,
2000, File No. 1-3526, as Exhibit 10(a)87.)
# (a)98 - Amended and Restated Change in Control Agreement between
Southern Company, SCS and Charles Douglas McCrary. (Designated
in Southern Company's Form 10-K for the year ended December
31, 2000, File No. 1-3526, as Exhibit 10(a)88.)
# (a)99 - Amended and Restated Change in Control Agreement between
Southern Company, Georgia Power and David M. Ratcliffe.
(Designated in Southern Company's Form 10-K for the year ended
December 31, 2000, File No. 1-3526, as Exhibit 10(a)89.)
E-19
# (a)100 - Amended and Restated Change in Control Agreement between
Southern Company, SCS and Stephen A. Wakefield. (Designated in
Southern Company's Form 10-K for the year ended December 31,
2000, File No. 1-3526, as Exhibit 10(a)90.)
# (a)101 - Southern Company Amended and Restated Change in Control
Benefit Plan Determination Policy, effective May 9, 2002.
(Designated in Southern Company's Form 10-K for the year ended
December 31, 2002, File No. 1-3526, as Exhibit 10(a)105.)
# (a)102 - Master Separation and Distribution Agreement dated as of
September 1, 2000 between Southern Company and Mirant.
(Designated in Southern Company's Form 10-K for the year ended
December 31, 2000, File No. 1-3526, as Exhibit 10(a)100.)
# (a)103 - Indemnification and Insurance Matters Agreement dated as
of September 1, 2000 between Southern Company and Mirant.
(Designated in Southern Company's Form 10-K for the year ended
December 31, 2000, File No. 1-3526, as Exhibit 10(a)101.)
# (a)104 - Tax Indemnification Agreement dated as of September 1,
2000 among Southern Company and its affiliated companies and
Mirant and its affiliated companies. (Designated in Southern
Company's Form 10-K for the year ended December 31, 2000, File
No. 1-3526, as Exhibit 10(a)102.)
# (a)105 - Southern Company Deferred Compensation Trust Agreement
as amended and restated effective January 1, 2001 between
Wachovia Bank, N.A., Southern Company, SCS, Alabama Power,
Georgia Power, Gulf Power, Mississippi Power, Savannah
Electric, Southern Communications, Energy Solutions and
Southern Nuclear. (Designated in Southern Company's Form 10-K
for the year ended December 31, 2000, File No. 1-3526, as
Exhibit 10(a)103.)
# (a)106 - Deferred Stock Trust Agreement for Directors of Southern
Company and its subsidiaries, dated as of January 1, 2000,
between Reliance Trust Company, Southern Company, Alabama
Power, Georgia Power, Gulf Power, Mississippi Power and
Savannah Electric. (Designated in Southern Company's Form 10-K
for the year ended December 31, 2000, File No. 1-3526, as
Exhibit 10(a)104.)
# (a)107 - Amended and Restated Deferred Cash Compensation Trust
Agreement for Directors of Southern Company and its
subsidiaries, effective September 1, 2001, between Wachovia
Bank, N.A., Southern Company, Alabama Power, Georgia Power,
Gulf Power, Mississippi Power and Savannah Electric.
(Designated in Southern Company's Form 10-K for the year ended
December 31, 2001, File No. 1-3526, as Exhibit 10(a)92.)
# (a)108 - Change in Control Agreement between Southern Company,
Mississippi Power and Michael D. Garrett. (Designated in
Southern Company's Form 10-K for the year ended December 31,
2002, File No. 1-3526, as Exhibit 10(a)112.)
# (a)109 - Change in Control Agreement between Southern Company,
Savannah Electric and Anthony R. James. (Designated in
Southern Company's Form 10-K for the year ended December 31,
2002, File No. 1-3526, as Exhibit 10(a)113.)
E-20
# (a)110 - Change in Control Agreement between Southern Company,
SCS and W. Paul Bowers. (Designated in Southern Company's Form
10-K for the year ended December 31, 2002, File No. 1-3526, as
Exhibit 10(a)114.)
# (a)111 - Change in Control Agreement between Southern Company,
Gulf Power and Thomas A. Fanning. (Designated in Southern
Company's Form 10-K for the year ended December 31, 2002, File
No. 1-3526, as Exhibit 10(a)115.)
# (a)112 - Deferred Compensation Agreement between Southern
Company, SCS and Christopher C. Womack dated May 31, 2002.
(Designated in Southern Company's Form 10-K for the year ended
December 31, 2002, File No. 1-3526, as Exhibit 10(a)118.)
# (a)113 - Supplemental Pension Agreement between Savannah
Electric, Gulf Power, SCS and G. Edison Holland, Jr. effective
February 22, 2002. (Designated in Southern Company's Form 10-K
for the year ended December 31, 2002, File No. 1-3526, as
Exhibit 10(a)119.)
# (a)114 - Amended and Restated Supplemental Pension Agreement
between Georgia Power, Southern Company, SCS and C. B. Harreld
dated September 17, 2003. (Designated in Southern Company's
Form 10-Q for the quarter ended September 30, 2003, File No.
1-3526, as Exhibit 10(a)5.)
# (a)115 - Southern Company Senior Executive Change in Control
Severance Plan effective May 1, 2003. (Designated in Southern
Company's Form 10-Q for the quarter ended June 30, 2003, File
No. 1-3526, as Exhibit 10(a)3.)
Alabama Power
(b)1 - Service contracts dated as of January 1, 1984, between SCS
and Alabama Power, Georgia Power, Gulf Power, Mississippi
Power, SEGCO and Southern Company and Amendment No. 1 dated as
of September 6, 1985 between SCS and Southern Company. See
Exhibit 10(a)1 herein.
(b)2 - Interchange contract dated February 17, 2000, between
Alabama Power, Georgia Power, Gulf Power, Mississippi Power,
Savannah Electric, Southern Power and SCS. See Exhibit 10(a)6
herein.
(b)3 - Agreement dated as of January 27, 1959, Amendment No. 1
dated as of October 27, 1982 and Amendment No. 2 dated
November 4, 1993 and effective June 1, 1994, among SEGCO,
Alabama Power and Georgia Power. See Exhibit 10(a)7 herein.
(b)4 - Unit Power Sales Agreement dated July 19, 1988, between
FPC and Alabama Power, Georgia Power, Gulf Power, Mississippi
Power, Savannah Electric and SCS. See Exhibit 10(a)33 herein.
(b)5 - Amended Unit Power Sales Agreement dated July 20, 1988,
between FP&L and Alabama Power, Georgia Power, Gulf Power,
Mississippi Power, Savannah Electric and SCS. See Exhibit
10(a)34 herein.
E-21
(b)6 - Amended Unit Power Sales Agreement dated August 17, 1988,
between JEA and Alabama Power, Georgia Power, Gulf Power,
Mississippi Power, Savannah Electric and SCS. See Exhibit
10(a)35 herein.
(b)7 - 1991 Firm Power Purchase Contract between Alabama Power
and AMEA. (Designated in Form U-1, File No. 70-7873, as
Exhibit B-1.)
(b)8 - Purchase and Ownership Agreement for Joint Ownership
Interest in the James H. Miller, Jr. Steam Electric Generating
Plant Units One and Two dated November 18, 1988, between
Alabama Power and AEC. See Exhibit 10(a)38 herein.
(b)9 - Operating Agreement for Joint Ownership Interest in the
James H. Miller, Jr. Steam Electric Generating Plant Units One
and Two dated November 18, 1988, between Alabama Power and
AEC. See Exhibit 10(a)39 herein.
(b)10 - Long Term Transmission Service Agreement between Entergy
Power, Inc. and Alabama Power, Mississippi Power and SCS. See
Exhibit 10(a)47 herein.
(b)11 - Operating Agreement for the Joseph M. Farley Nuclear
Plant between Alabama Power and Southern Nuclear dated as of
December 23, 1991. See Exhibit 10(a)51 herein.
*(b)12 - Amended and Restated Operating Agreement between Southern
Power and Alabama Power effective December 1, 2002. See
Exhibit 10(a)59 herein.
(b)13 - Interconnection Agreement by and between Southern Power
and Alabama Power for Autaugaville Combined Cycle Unit 1 dated
as of June 25, 2001. See Exhibit 10(a)66 herein.
(b)14 - Interconnection Agreement by and between Southern Power
and Alabama Power for Autaugaville Combined Cycle Unit 2 dated
as of June 25, 2001. See Exhibit 10(a)67 herein.
(b)15 - Power Purchase Agreement between Southern Power and
Alabama Power dated as of June 1, 2001. See Exhibit 10(a)71
herein.
(b)16 - The Southern Company Employee Savings Plan, Amended and
Restated effective January 1, 2002 and Amendments one through
five thereto. See Exhibit 10(a)79 herein.
(b)17 - The Southern Company Employee Stock Ownership Plan,
Amended and Restated effective January 1, 2002 and Amendments
one through five thereto. See Exhibit 10(a)80 herein.
# (b)18 - Southern Company Omnibus Incentive Compensation Plan,
Amended and Restated effective May 23, 2001. See Exhibit
10(a)81 herein.
# (b)19 - The Southern Company Deferred Compensation Plan, Amended
and Restated effective February 23, 2001 and First Amendment
thereto. See Exhibit 10(a)84 herein.
E-22
# (b)20 - The Southern Company Outside Directors Pension Plan. See
Exhibit 10(a)83 herein.
# (b)21 - Outside Directors Stock Plan for Subsidiaries of The
Southern Company, Amended and Restated effective January 1,
2000. See Exhibit 10(a)86 herein.
(b)22 - The Southern Company Pension Plan, Amended and Restated
effective January 1, 2002 and First Amendment thereto. See
Exhibit 10(a)87 herein.
# (b)23 - The Southern Company Supplemental Executive Retirement
Plan, Amended and Restated effective May 1, 2000. See Exhibit
10(a)88 herein.
# (b)24 - The Southern Company Supplemental Benefit Plan, Amended
and Restated effective May 1, 2000 and First Amendment
thereto. See Exhibit 10(a)89 herein.
(b)25 - Southern Company Change in Control Severance Plan,
Amended and Restated effective May 1, 2003. See Exhibit
10(a)90 herein.
# (b)26 - Southern Company Executive Change in Control Severance
Plan, Amended and Restated effective May 1, 2003. See Exhibit
10(a)91 herein.
# (b)27 - Deferred Compensation Plan for Directors of Alabama Power
Company, Amended and Restated effective January 1, 2001.
(Designated in Alabama Power's Form 10-K for the year ended
December 31, 2001, File No. 1-3164, as Exhibit 10(b)28.)
# (b)28 - Southern Company Amended and Restated Change in Control
Benefit Plan Determination Policy, effective May 9, 2002. See
Exhibit 10(a)101 herein.
# (b)29 - Southern Company Deferred Compensation Trust Agreement as
amended and restated effective January 1, 2001 between
Wachovia Bank, N.A., Southern Company, SCS, Alabama Power,
Georgia Power, Gulf Power, Mississippi Power, Savannah
Electric, Southern Communications, Energy Solutions and
Southern Nuclear. See Exhibit 10(a)105 herein.
# (b)30 - Deferred Stock Trust Agreement for Directors of Southern
Company and its subsidiaries, dated as of January 1, 2000,
between Reliance Trust Company, Southern Company, Alabama
Power, Georgia Power, Gulf Power, Mississippi Power and
Savannah Electric. See Exhibit 10(a)106 herein.
# (b)31 - Amended and Restated Deferred Cash Compensation Trust
Agreement for Directors of Southern Company and its
subsidiaries, effective September 1, 2001, between Wachovia
Bank, N.A., Southern Company, Alabama Power, Georgia Power,
Gulf Power, Mississippi Power and Savannah Electric. See
Exhibit 10(a)107 herein.
# (b)32 - Deferred Compensation Agreement between Alabama Power and
William B. Hutchins, III dated April 11, 2003. (Designated in
Alabama Power's Form 10-Q for the quarter ended March 31,
2003, File No. 1-3164, as Exhibit 10(b)1.)
E-23
# (b)33 - Amended and Restated Supplemental Pension Agreement among
SCS, Southern Nuclear, Alabama Power and James H. Miller, III.
(Designated in Alabama Power's Form 10-Q for the quarter ended
June 30, 2003, File No. 1-3164, as Exhibit 10(b)1.)
# (b)34 - Southern Company Senior Executive Change in Control
Severance Plan effective May 1, 2003. See Exhibit 10(a)115
herein.
Georgia Power
(c)1 - Service contracts dated as of January 1, 1984, between SCS
and Alabama Power, Georgia Power, Gulf Power, Mississippi
Power, SEGCO and Southern Company and Amendment No. 1 dated as
of September 6, 1985, between SCS and Southern Company. See
Exhibit 10(a)1 herein.
(c)2 - Interchange contract dated February 17, 2000, between
Alabama Power, Georgia Power, Gulf Power, Mississippi Power,
Savannah Electric, Southern Power and SCS. See Exhibit 10(a)6
herein.
(c)3 - Agreement dated as of January 27, 1959, Amendment No. 1
dated as of October 27, 1982 and Amendment No. 2 dated
November 4, 1993 and effective June 1, 1994, among SEGCO,
Alabama Power and Georgia Power. See Exhibit 10(a)7 herein.
(c)4 - Joint Committee Agreement dated as of August 27, 1976,
among Georgia Power, OPC, MEAG and Dalton. See Exhibit 10(a)8
herein.
(c)5 - Edwin I. Hatch Nuclear Plant Purchase and Ownership
Participation Agreement dated as of January 6, 1975, between
Georgia Power and OPC. See Exhibit 10(a)9 herein.
(c)6 - Edwin I. Hatch Nuclear Plant Operating Agreement dated as
of January 6, 1975, between Georgia Power and OPC. See Exhibit
10(a)10 herein.
(c)7 - Revised and Restated Integrated Transmission System
Agreement dated as of November 12, 1990, between Georgia Power
and OPC. See Exhibit 10(a)11 herein.
(c)8 - Plant Hal Wansley Purchase and Ownership Participation
Agreement dated as of March 26, 1976, between Georgia Power
and OPC. See Exhibit 10(a)12 herein.
(c)9 - Plant Hal Wansley Operating Agreement dated as of March
26, 1976, between Georgia Power and OPC. See Exhibit 10(a)13
herein.
(c)10 - Edwin I. Hatch Nuclear Plant Purchase and Ownership
Participation Agreement dated as of August 27, 1976, between
Georgia Power, MEAG and Dalton. See Exhibit 10(a)14 herein.
(c)11 - Edwin I. Hatch Nuclear Plant Operating Agreement dated as
of August 27, 1976, between Georgia Power, MEAG and Dalton.
See Exhibit 10(a)15 herein.
E-24
(c)12 - Alvin W. Vogtle Nuclear Units Number One and Two Purchase
and Ownership Participation Agreement dated as of August 27,
1976 and Amendment No. 1 dated as of January 18, 1977, among
Georgia Power, OPC, MEAG and Dalton. See Exhibit 10(a)16
herein.
(c)13 - Alvin W. Vogtle Nuclear Units Number One and Two
Operating Agreement dated as of August 27, 1976, among Georgia
Power, OPC, MEAG and Dalton. See Exhibit 10(a)17 herein.
(c)14 - Alvin W. Vogtle Nuclear Units Number One and Two
Purchase, Amendment, Assignment and Assumption Agreement dated
as of November 16, 1983, between Georgia Power and MEAG. See
Exhibit 10(a)18 herein.
(c)15 - Plant Hal Wansley Purchase and Ownership Participation
Agreement dated as of August 27, 1976, between Georgia Power
and MEAG. See Exhibit 10(a)19 herein.
(c)16 - Plant Hal Wansley Operating Agreement dated as of August
27, 1976, between Georgia Power and MEAG. See Exhibit 10(a)20
herein.
(c)17 - Nuclear Operating Agreement between Southern Nuclear and
Georgia Power dated as of July 1, 1993. See Exhibit 10(a)21
herein.
(c)18 - Pseudo Scheduling and Services Agreement between Georgia
Power and MEAG dated as of April 8, 1997. See Exhibit 10(a)22
herein.
(c)19 - Plant Hal Wansley Purchase and Ownership Participation
Agreement dated as of April 19, 1977, between Georgia Power
and Dalton. See Exhibit 10(a)23 herein.
(c)20 - Plant Hal Wansley Operating Agreement dated as of April
19, 1977, between Georgia Power and Dalton. See Exhibit
10(a)24 herein.
(c)21 - Plant Robert W. Scherer Units Number One and Two Purchase
and Ownership Participation Agreement dated as of May 15,
1980, Amendment No. 1 dated as of December 30, 1985, Amendment
No. 2 dated as of July 1, 1986, Amendment No. 3 dated as of
August 1, 1988 and Amendment No. 4 dated as of December 31,
1990, among Georgia Power, OPC, MEAG and Dalton. See Exhibit
10(a)25 herein.
(c)22 - Plant Robert W. Scherer Units Number One and Two
Operating Agreement dated as of May 15, 1980, Amendment No. 1
dated as of December 3, 1985 and Amendment No. 2 dated as of
December 31, 1990, among Georgia Power, OPC, MEAG and Dalton.
See Exhibit 10(a)26 herein.
(c)23 - Plant Robert W. Scherer Purchase, Sale and Option
Agreement dated as of May 15, 1980, between Georgia Power and
MEAG. See Exhibit 10(a)27 herein.
(c)24 - Plant Robert W. Scherer Purchase and Sale Agreement dated
as of May 16, 1980, between Georgia Power and Dalton. See
Exhibit 10(a)28 herein.
(c)25 - Plant Robert W. Scherer Unit Number Three Purchase and
Ownership Participation Agreement dated as of March 1, 1984,
Amendment No. 1 dated as of July 1, 1986 and Amendment No. 2
dated as of August 1, 1988, between Georgia Power and Gulf
Power. See Exhibit 10(a)29 herein.
E-25
(c)26 - Plant Robert W. Scherer Unit Number Three Operating
Agreement dated as of March 1, 1984, between Georgia Power and
Gulf Power. See Exhibit 10(a)30 herein.
(c)27 - Plant Robert W. Scherer Unit No. Four Amended and
Restated Purchase and Ownership Participation Agreement by and
among Georgia Power, FP&L and JEA dated as of December 31,
1990 and Amendment No. 1 dated as of June 15, 1994. See
Exhibit 10(a)31 herein.
(c)28 - Plant Robert W. Scherer Unit No. Four Operating Agreement
by and among Georgia Power, FP&L and JEA dated as of December
31, 1990 and Amendment No. 1 dated as of June 15, 1994. See
Exhibit 10(a)32 herein.
(c)29 - Unit Power Sales Agreement dated July 19, 1988, between
FPC and Alabama Power, Georgia Power, Gulf Power, Mississippi
Power, Savannah Electric and SCS. See Exhibit 10(a)33 herein.
(c)30 - Amended Unit Power Sales Agreement dated July 20, 1988,
between FP&L and Alabama Power, Georgia Power, Gulf Power,
Mississippi Power, Savannah Electric and SCS. See Exhibit
10(a)34 herein.
(c)31 - Amended Unit Power Sales Agreement dated August 17, 1988,
between JEA and Alabama Power, Georgia Power, Gulf Power,
Mississippi Power, Savannah Electric and SCS. See Exhibit
10(a)35 herein.
(c)32 - Rocky Mountain Pumped Storage Hydroelectric Project
Ownership Participation Agreement dated November 18, 1988,
between OPC and Georgia Power. See Exhibit 10(a)36 herein.
(c)33 - Rocky Mountain Pumped Storage Hydroelectric Project
Operating Agreement dated November 18, 1988, between OPC and
Georgia Power. See Exhibit 10(a)37 herein.
(c)34 - Long Term Transaction Service Agreement between Georgia
Power and OPC dated as of February 26, 1999. See Exhibit
10(a)41 herein.
(c)35 - Revised and Restated Coordination Services Agreement
between and among Georgia Power, OPC and Georgia Systems
Operations Corporation dated as of September 10, 1997. See
Exhibit 10(a)42 herein.
(c)36 - Amended and Restated Nuclear Managing Board Agreement for
Plant Hatch and Plant Vogtle among Georgia Power, OPC, MEAG
and Dalton dated as of July 1, 1993. See Exhibit 10(a)43
herein.
(c)37 - Integrated Transmission System Agreement, Power Sale and
Coordination Umbrella Agreement between Georgia Power and OPC
dated as of November 12, 1990. See Exhibit 10(a)44 herein.
(c)38 - Revised and Restated Integrated Transmission System
Agreement between Georgia Power and Dalton dated as of
December 7, 1990. See Exhibit 10(a)45 herein.
E-26
(c)39 - Revised and Restated Integrated Transmission System
Agreement between Georgia Power and MEAG dated as of December
7, 1990. See Exhibit 10(a)46 herein.
(c)40 - Plant Scherer Managing Board Agreement dated as of
December 31, 1990 among Georgia Power, OPC, MEAG, Dalton, Gulf
Power, FP&L and JEA. See Exhibit 10(a)48 herein.
(c)41 - Plant McIntosh Combustion Turbine Purchase and Ownership
Participation Agreement between Georgia Power and Savannah
Electric dated as of December 15, 1992. See Exhibit 10(a)49
herein.
(c)42 - Plant McIntosh Combustion Turbine Operating Agreement
between Georgia Power and Savannah Electric dated as of
December 15, 1992. See Exhibit 10(a)50 herein.
*(c)43 - Amended and Restated Operating Agreement between Southern
Power and Georgia Power dated effective December 1, 2002. See
Exhibit 10(a)60 herein.
(c)44 - Interconnection Agreement by and between Southern Power
and Georgia Power for Plant Dahlberg dated as of July 31,
2001. See Exhibit 10(a)62 herein.
(c)45 - Interconnection Agreement by and between Southern Power
and Georgia Power for Wansley CC Units 6 and 7 dated as of May
10, 2001. See Exhibit 10(a)63 herein.
(c)46 - Interconnection Agreement by and between Southern Power
and Georgia Power for Goat Rock CC Unit 1 dated as of May 10,
2001. See Exhibit 10(a)64 herein.
(c)47 - Revised and Restated Interconnection Agreement by and
between Southern Power and Georgia Power for Goat Rock CC Unit
2 dated as of October 18, 2001. See Exhibit 10(a)65 herein.
(c)48 - Purchased Power Agreement between Georgia Power and LG&E
Energy Marketing Inc. dated as of November 24, 1998. See
Exhibit 10(a)68 herein.
(c)49 - Purchased Power Agreement between Georgia Power and LG&E
Energy Marketing Inc. dated as of October 6, 1999. See Exhibit
10(a)69 herein.
(c)50 - Assignment and Assumption Agreement by and between
Georgia Power and Southern Power dated as of July 31, 2001.
See Exhibit 10(a)70 herein.
(c)51 - Amended and Restated Power Purchase Agreement between
Southern Power and Georgia Power at Plant Autaugaville dated
as of August 6, 2001. See Exhibit 10(a)72 herein.
(c)52 - Contract for the Purchase of Firm Capacity and Energy
between Southern Power and Georgia Power dated as of July 26,
2001. See Exhibit 10(a)74 herein.
(c)53 - Power Purchase Agreement between Southern Power and
Georgia Power at Plant Goat Rock dated as of March 30, 2001.
See Exhibit 10(a)75 herein.
E-27
(c)54 - The Southern Company Employee Savings Plan, Amended and
Restated effective January 1, 2002 and Amendments one through
five thereto. See Exhibit 10(a)79 herein.
(c)55 - The Southern Company Employee Stock Ownership Plan,
Amended and Restated effective January 1, 2002 and Amendments
one through five thereto. See Exhibit 10(a)80 herein.
# (c)56 - Southern Company Omnibus Incentive Compensation Plan,
Amended and Restated effective May 23, 2001. See Exhibit
10(a)81 herein.
# (c)57 - The Southern Company Deferred Compensation Plan, Amended
and Restated effective February 23, 2001 and First Amendment
thereto. See Exhibit 10(a)84 herein.
# (c)58 - The Southern Company Outside Directors Pension Plan. See
Exhibit 10(a)83 herein.
# (c)59 - Outside Directors Stock Plan for Subsidiaries of The
Southern Company, Amended and Restated effective January 1,
2000. See Exhibit 10(a)86 herein.
(c)60 - The Southern Company Pension Plan, Amended and Restated
effective January 1, 2002 and First Amendment thereto. See
Exhibit 10(a)87 herein.
# (c)61 - The Southern Company Supplemental Executive Retirement
Plan, Amended and Restated effective May 1, 2000. See Exhibit
10(a)88 herein.
# (c)62 - The Southern Company Supplemental Benefit Plan, Amended
and Restated effective May 1, 2000 and First Amendment
thereto. See Exhibit 10(a)89 herein.
(c)63 - Southern Company Change in Control Severance Plan,
Amended and Restated effective May 1, 2003. See Exhibit
10(a)90 herein.
# (c)64 - Southern Company Executive Change in Control Severance
Plan, Amended and Restated effective May 1, 2003. See Exhibit
10(a)91 herein.
# (c)65 - Amended and Restated Change in Control Agreement between
Southern Company, Georgia Power and David M. Ratcliffe. See
Exhibit 10(a)99 herein.
# (c)66 - Deferred Compensation Plan For Directors of Georgia Power
Company, Amended and Restated Effective January 13, 2003.
(Designated in Georgia Power's Form 10-K for the year ended
December 31, 2002, File No. 1.6468, as Exhibit 10(c)68.)
# (c)67 - Southern Company Amended and Restated Change in Control
Benefit Plan Determination Policy, effective May 9, 2002. See
Exhibit 10(a)101 herein.
# (c)68 - Southern Company Deferred Compensation Trust Agreement as
amended and restated effective January 1, 2001 between
Wachovia Bank, N.A., Southern Company, SCS, Alabama Power,
Georgia Power, Gulf Power, Mississippi Power, Savannah
Electric, Southern Communications, Energy Solutions and
Southern Nuclear. See Exhibit 10(a)105 herein.
E-28
# (c)69 - Deferred Stock Trust Agreement for Directors of Southern
Company and its subsidiaries, dated as of January 1, 2000,
between Reliance Trust Company, Southern Company, Alabama
Power, Georgia Power, Gulf Power, Mississippi Power and
Savannah Electric. See Exhibit 10(a)106 herein.
# (c)70 - Amended and Restated Deferred Cash Compensation Trust
Agreement for Directors of Southern Company and its
subsidiaries, effective September 1, 2001, between Wachovia
Bank, N.A., Southern Company, Alabama Power, Georgia Power,
Gulf Power, Mississippi Power and Savannah Electric. See
Exhibit 10(a)107 herein.
# (c)71 - Southern Company Senior Executive Change in Control
Severance Plan effective May 1, 2003. See Exhibit 10(a)115
herein.
Gulf Power
(d)1 - Service contracts dated as of January 1, 1984, between SCS
and Alabama Power, Georgia Power, Gulf Power, Mississippi
Power, SEGCO and Southern Company and Amendment No. 1 dated as
of September 6, 1985, between SCS and Southern Company. See
Exhibit 10(a)1 herein.
(d)2 - Interchange contract dated February 17, 2000, between
Alabama Power, Georgia Power, Gulf Power, Mississippi Power,
Savannah Electric, Southern Power and SCS. See Exhibit 10(a)6
herein.
(d)3 - Plant Robert W. Scherer Unit Number Three Purchase and
Ownership Participation Agreement dated as of March 1, 1984,
Amendment No. 1 dated as of July 1, 1986 and Amendment No. 2
dated as of August 1, 1988, between Georgia Power and Gulf
Power. See Exhibit 10(a)29 herein.
(d)4 - Plant Robert W. Scherer Unit Number Three Operating
Agreement dated as of March 1, 1984, between Georgia Power and
Gulf Power. See Exhibit 10(a)30 herein.
(d)5 - Plant Scherer Managing Board Agreement dated as of
December 31, 1990 among Georgia Power, OPC, MEAG, Dalton, Gulf
Power, FP&L and JEA. See Exhibit 10(a)48 herein.
(d)6 - Unit Power Sales Agreement dated July 19, 1988, between
FPC and Alabama Power, Georgia Power, Gulf Power, Mississippi
Power, Savannah Electric and SCS. See Exhibit 10(a)33 herein.
(d)7 - Amended Unit Power Sales Agreement dated July 20, 1988,
between FP&L and Alabama Power, Georgia Power, Gulf Power,
Mississippi Power, Savannah Electric and SCS. See Exhibit
10(a)34 herein.
(d)8 - Amended Unit Power Sales Agreement dated August 17, 1988,
between JEA and Alabama Power, Georgia Power, Gulf Power,
Mississippi Power, Savannah Electric and SCS. See Exhibit
10(a)35 herein.
E-29
(d)9 - Agreement between Gulf Power and AEC, effective August 1,
1985. (Designated in Gulf Power's Form 10-K for the year ended
December 31, 1985, File No. 0-2429, as Exhibit 10(g).)
(d)10 - The Southern Company Employee Savings Plan, Amended and
Restated effective January 1, 2002 and Amendments one through
five thereto. See Exhibit 10(a)79 herein.
(d)11 - The Southern Company Employee Stock Ownership Plan,
Amended and Restated effective January 1, 2002 and Amendments
one through five thereto. See Exhibit 10(a)80 herein.
# (d)12 - Southern Company Omnibus Incentive Compensation Plan,
Amended and Restated effective May 23, 2001. See Exhibit
10(a)81 herein.
# (d)13 - The Southern Company Deferred Compensation Plan, Amended
and Restated effective February 23, 2001 and First Amendment
thereto. See Exhibit 10(a)84 herein.
# (d)14 - The Southern Company Outside Directors Pension Plan. See
Exhibit 10(a)83 herein.
# (d)15 - Outside Directors Stock Plan for Subsidiaries of The
Southern Company, Amended and Restated effective January 1,
2000. See Exhibit 10(a)86 herein.
(d)16 - The Southern Company Pension Plan, Amended and Restated
effective January 1, 2002 and First Amendment thereto. See
Exhibit 10(a)87 herein.
# (d)17 - The Southern Company Supplemental Benefit Plan, Amended
and Restated effective May 1, 2000 and First Amendment
thereto. See Exhibit 10(a)89 herein.
(d)18 - Southern Company Change in Control Severance Plan,
Amended and Restated effective May 1, 2003. See Exhibit
10(a)90 herein.
# (d)19 - Southern Company Executive Change in Control Severance
Plan, Amended and Restated effective May 1, 2003. See Exhibit
10(a)91 herein.
# (d)20 - The Southern Company Supplemental Executive Retirement
Plan, Amended and Restated effective May 1, 2000. See Exhibit
10(a)88 herein.
# (d)21 - Supplemental Pension Agreement between Savannah Electric,
Gulf Power, SCS and G. Edison Holland, Jr. effective February
22, 2002. See Exhibit 10(a)113 herein.
# (d)22 - Deferred Compensation Plan For Directors of Gulf Power
Company, Amended and Restated Effective January 1, 2000 and
First Amendment thereto. (Designated in Gulf Power's Form 10-K
for the year ended December 31, 2000, File No. 0-2429 as
Exhibit 10(d)33.)
# (d)23 - Southern Company Amended and Restated Change in Control
Benefit Plan Determination Policy, effective May 9, 2002. See
Exhibit 10(a)101 herein.
E-30
# (d)24 - Southern Company Deferred Compensation Trust Agreement as
amended and restated effective January 1, 2001 between
Wachovia Bank, N.A., Southern Company, SCS, Alabama Power,
Georgia Power, Gulf Power, Mississippi Power, Savannah
Electric, Southern Communications, Energy Solutions and
Southern Nuclear. See Exhibit 10(a)105 herein.
# (d)25 - Deferred Stock Trust Agreement for Directors of Southern
Company and its subsidiaries, dated as of January 1, 2000,
between Reliance Trust Company, Southern Company, Alabama
Power, Georgia Power, Gulf Power, Mississippi Power and
Savannah Electric. See Exhibit 10(a)106 herein.
# (d)26 - Amended and Restated Deferred Cash Compensation Trust
Agreement for Directors of Southern Company and its
subsidiaries, effective September 1, 2001, between Wachovia
Bank, N.A., Southern Company, Alabama Power, Georgia Power,
Gulf Power, Mississippi Power and Savannah Electric. See
Exhibit 10(a)107 herein.
# (d)27 - Change in Control Agreement between Southern Company,
Gulf Power and Thomas A. Fanning. See Exhibit 10(a)111 herein.
# (d)28 - Southern Company Senior Executive Change in Control
Severance Plan effective May 1, 2003. See Exhibit 10(a)115
herein.
Mississippi Power
(e)1 - Service contracts dated as of January 1, 1984, between SCS
and Alabama Power, Georgia Power, Gulf Power, Mississippi
Power, SEGCO and Southern Company and Amendment No. 1 dated as
of September 6, 1985, between SCS and Southern Company. See
Exhibit 10(a)1 herein.
(e)2 - Interchange contract dated February 17, 2000, between
Alabama Power, Georgia Power, Gulf Power, Mississippi Power,
Savannah Electric, Southern Power and SCS. See Exhibit 10(a)6
herein.
(e)3 - Unit Power Sales Agreement dated July 19, 1988, between
FPC and Alabama Power, Georgia Power, Gulf Power, Mississippi
Power, Savannah Electric and SCS. See Exhibit 10(a)33 herein.
(e)4 - Amended Unit Power Sales Agreement dated July 20, 1988,
between FP&L and Alabama Power, Georgia Power, Gulf Power,
Mississippi Power, Savannah Electric and SCS. See Exhibit
10(a)34 herein.
(e)5 - Amended Unit Power Sales Agreement dated August 17, 1988,
between JEA and Alabama Power, Georgia Power, Gulf Power,
Mississippi Power, Savannah Electric and SCS. See Exhibit
10(a)35 herein.
(e)6 - Transmission Facilities Agreement dated February 25, 1982,
Amendment No. 1 dated May 12, 1982 and Amendment No. 2 dated
December 6, 1983, between Entergy Corporation (formerly Gulf
States) and Mississippi Power. See Exhibit 10(a)40 herein.
E-31
(e)7 - Long Term Transmission Service Agreement between Entergy
Power, Inc. and Alabama Power, Mississippi Power and SCS. See
Exhibit 10(a)47 herein.
(e)8 - The Southern Company Employee Savings Plan, Amended and
Restated effective January 1, 2002 and Amendments one through
five thereto. See Exhibit 10(a)79 herein.
(e)9 - The Southern Company Employee Stock Ownership Plan,
Amended and Restated effective January 1, 2002 and Amendments
one through five thereto. See Exhibit 10(a)80 herein.
# (e)10 - Southern Company Omnibus Incentive Compensation Plan,
Amended and Restated effective May 23, 2001. See Exhibit
10(a)81 herein.
# (e)11 - The Southern Company Deferred Compensation Plan, Amended
and Restated effective February 23, 2001 and First Amendment
thereto. See Exhibit 10(a)84 herein.
# (e)12 - The Southern Company Outside Directors Pension Plan. See
Exhibit 10(a)83 herein.
# (e)13 - Outside Directors Stock Plan for Subsidiaries of The
Southern Company, Amended and Restated effective January 1,
2000. See Exhibit 10(a)86 herein.
(e)14 - The Southern Company Pension Plan, Amended and Restated
effective January 1, 2002 and First Amendment thereto. See
Exhibit 10(a)87 herein.
# (e)15 - The Southern Company Supplemental Benefit Plan, Amended
and Restated effective May 1, 2000 and First Amendment
thereto. See Exhibit 10(a)89 herein.
(e)16 - Southern Company Change in Control Severance Plan,
Amended and Restated effective May 1, 2003. See Exhibit
10(a)90 herein.
# (e)17 - Southern Company Executive Change in Control Severance
Plan, Amended and Restated effective May 1, 2003. See Exhibit
10(a)91 herein.
# (e)18 - Amended and Restated Change in Control Agreement between
Southern Company, Mississippi Power and Dwight H. Evans. See
Exhibit 10(a)93 herein.
# (e)19 - The Southern Company Supplemental Executive Retirement
Plan, Amended and Restated effective May 1, 2000. See Exhibit
10(a)88 herein.
# (e)20 - Deferred Compensation Plan for Directors of Mississippi
Power Company, Amended and Restated Effective January 1, 2000
and Amendment Number One thereto. (Designated in Mississippi
Power's Form 10-K for the year ended December 31, 1999, File
No. 0-6849 as Exhibit 10(e)37 and in Mississippi Power's Form
10-K for the year December 31, 2000, File No. 0-6849 as
Exhibit 10(e)30.)
# (e)21 - Southern Company Amended and Restated Change in Control
Benefit Plan Determination Policy, effective May 9, 2002. See
Exhibit 10(a)101 herein.
E-32
# (e)22 - Southern Company Deferred Compensation Trust Agreement as
amended and restated effective January 1, 2001 between
Wachovia Bank, N.A., Southern Company, SCS, Alabama Power,
Georgia Power, Gulf Power, Mississippi Power, Savannah
Electric, Southern Communications, Energy Solutions and
Southern Nuclear. See Exhibit 10(a)105 herein.
# (e)23 - Deferred Stock Trust Agreement for Directors of Southern
Company and its subsidiaries, dated as of January 1, 2000,
between Reliance Trust Company, Southern Company, Alabama
Power, Georgia Power, Gulf Power, Mississippi Power and
Savannah Electric. See Exhibit 10(a)106 herein.
# (e)24 - Amended and Restated Deferred Cash Compensation Trust
Agreement for Directors of Southern Company and its
subsidiaries, effective September 1, 2001, between Wachovia
Bank, N.A., Southern Company, Alabama Power, Georgia Power,
Gulf Power, Mississippi Power and Savannah Electric. See
Exhibit 10(a)107 herein.
# (e)25 - Change in Control Agreement between Southern Company,
Mississippi Power and Michael D. Garrett. See Exhibit 10(a)108
herein.
# (e)26 - Southern Company Senior Executive Change in Control
Severance Plan effective May 1, 2003. See Exhibit 10(a)115
herein.
#*(e)27 - Separation Agreement between Henry E. Blakeslee and
Mississippi Power effective January 1, 2004.
#*(e)28 - Consulting Agreement between Henry E. Blakeslee and
Mississippi Power effective January 1, 2004.
Savannah Electric
(f)1 - Service contract dated as of March 3, 1988, between SCS
and Savannah Electric. See Exhibit 10(a)3 herein.
(f)2 - Interchange contract dated February 17, 2000, between
Alabama Power, Georgia Power, Gulf Power, Mississippi Power,
Savannah Electric, Southern Power and SCS. See Exhibit 10(a)6
herein.
(f)3 - Unit Power Sales Agreement dated July 19, 1988, between
FPC and Alabama Power, Georgia Power, Gulf Power, Mississippi
Power, Savannah Electric and SCS. See Exhibit 10(a)33 herein.
(f)4 - Amended Unit Power Sales Agreement dated July 20, 1988,
between FP&L and Alabama Power, Georgia Power, Gulf Power,
Mississippi Power, Savannah Electric and SCS. See Exhibit
10(a)34 herein.
(f)5 - Amended Unit Power Sales Agreement dated August 17, 1988,
between JEA and Alabama Power, Georgia Power, Gulf Power,
Mississippi Power, Savannah Electric and SCS. See Exhibit
10(a)35 herein.
E-33
(f)6 - Plant McIntosh Combustion Turbine Purchase and Ownership
Participation Agreement between Georgia Power and Savannah
Electric dated as of December 15, 1992. See Exhibit 10(a)49
herein.
(f)7 - Plant McIntosh Combustion Turbine Operating Agreement
between Georgia Power and Savannah Electric dated December 15,
1992. See Exhibit 10(a)50 herein.
(f)8 - Contract for the Purchase of Firm Capacity and Energy
between Southern Power and Savannah Electric dated as of July
26, 2001. See Exhibit 10(a)73 herein.
(f)9 - The Southern Company Employee Savings Plan, Amended and
Restated effective January 1, 2002 and Amendments one through
five thereto. See Exhibit 10(a)79 herein.
(f)10 - The Southern Company Employee Stock Ownership Plan,
Amended and Restated effective January 1, 2002 and Amendments
one through five thereto. See Exhibit 10(a)80 herein.
# (f)11 - Southern Company Omnibus Incentive Compensation Plan,
Amended and Restated effective May 23, 2001. See Exhibit
10(a)81 herein.
# (f)12 - Supplemental Executive Retirement Plan of Savannah
Electric, Amended and Restated effective October 26, 2000.
(Designated in Savannah Electric's Form 10-K for the year
ended December 31, 2000, File No. 1-5072 as Exhibit 10(f)13.)
# (f)13 - Deferred Compensation Plan for Key Employees of Savannah
Electric, Amended and Restated effective October 26, 2000.
(Designated in Savannah Electric's Form 10-K for the year
ended December 31, 2000, File No. 1-5072 as Exhibit 10(f)14.)
# (f)14 - The Southern Company Outside Directors Pension Plan. See
Exhibit 10(a)83 herein.
# (f)15 - Deferred Compensation Plan for Directors of Savannah
Electric, Amended and Restated effective October 26, 2000.
(Designated in Savannah Electric's Form 10-K for the year
ended December 31, 2000, File No. 1-5072 as Exhibit 10(f)18.)
# (f)16 - Outside Directors Stock Plan for Subsidiaries of The
Southern Company, Amended and Restated effective January 1,
2000. See Exhibit 10(a)86 herein.
(f)17 - The Southern Company Pension Plan, Amended and Restated
effective January 1, 2002 and First Amendment thereto. See
Exhibit 10(a)87 herein.
# (f)18 - The Southern Company Supplemental Benefit Plan, Amended
and Restated effective May 1, 2000 and First Amendment
thereto. See Exhibit 10(a)89 herein.
(f)19 - Southern Company Change in Control Severance Plan,
Amended and Restated effective May 1, 2003. See Exhibit
10(a)90 herein.
# (f)20 - Southern Company Executive Change in Control Severance
Plan, Amended and Restated effective May 1, 2003. See Exhibit
10(a)91 herein.
E-34
# (f)21 - Amended and Restated Change in Control Agreement between
Southern Company, Savannah Electric and G. Edison Holland, Jr.
See Exhibit 10(a)96 herein.
# (f)22 - The Southern Company Deferred Compensation Plan, Amended
and Restated effective February 23, 2001 and First Amendment
thereto. See Exhibit 10(a)84 herein.
# (f)23 - The Southern Company Supplemental Executive Retirement
Plan, Amended and Restated effective May 1, 2000. See Exhibit
10(a)88 herein.
# (f)24 - Supplemental Pension Agreement between Savannah Electric,
Gulf Power, SCS and G. Edison Holland, Jr. effective February
22, 2002. See Exhibit 10(a)113 herein.
# (f)25 - Southern Company Amended and Restated Change in Control
Benefit Plan Determination Policy, effective May 9, 2002. See
Exhibit 10(a)101 herein.
# (f)26 - Agreement for supplemental pension benefits between
Savannah Electric and William Miles Greer. (Designated in
Savannah Electric's Form 10-K for the year ended December 31,
2000, File No. 1-5072 as Exhibit 10(f)34.)
# (f)27 - Agreement crediting additional service between Savannah
Electric and William Miles Greer. (Designated in Savannah
Electric's Form 10-K for the year ended December 31, 2000,
File No. 1-5072 as Exhibit 10(f)35.)
# (f)28 - Southern Company Deferred Compensation Trust Agreement as
amended and restated effective January 1, 2001 between
Wachovia Bank, N.A., Southern Company, SCS, Alabama Power,
Georgia Power, Gulf Power, Mississippi Power, Savannah
Electric, Southern Communications, Energy Solutions and
Southern Nuclear. See Exhibit 10(a)105 herein.
# (f)29 - Deferred Stock Trust Agreement for Directors of Southern
Company and its subsidiaries, dated as of January 1, 2000,
between Reliance Trust Company, Southern Company, Alabama
Power, Georgia Power, Gulf Power, Mississippi Power and
Savannah Electric. See Exhibit 10(a)106 herein.
# (f)30 - Amended and Restated Deferred Cash Compensation Trust
Agreement for Directors of Southern Company and its
subsidiaries, effective September 1, 2001, between Wachovia
Bank, N.A., Southern Company, Alabama Power, Georgia Power,
Gulf Power, Mississippi Power and Savannah Electric. See
Exhibit 10(a)107 herein.
# (f)31 - Change in Control Agreement between Southern Company,
Savannah Electric and Anthony R. James. See Exhibit 10(a)109
herein.
# (f)32 - Southern Company Senior Executive Change in Control
Severance Plan effective May 1, 2003. See Exhibit 10(a)115
herein.
*(f)33 - Operating Agreement between Southern Power and Savannah
Electric effective January 1, 2003. See Exhibit 10(a)61
herein.
E-35
#*(f)34 - Savannah Electric and Power Company Change in Control
Plan Benefit Determination Policy, effective October 26, 2000.
Southern Power
(g)1 - Service contract dated as of January 1, 2001, between SCS
and Southern Power. See Exhibit 10(a)2 herein.
(g)2 - Interchange contract dated February 17, 2000, between
Alabama Power, Georgia Power, Gulf Power, Mississippi Power,
Savannah Electric, Southern Power and SCS. See Exhibit 10(a)6
herein.
(g)3 - Amended and Restated Credit Agreement among Southern
Power, Citibank N.A., as the administrative agent, and the
lenders listed therein dated as of April 17, 2003. See Exhibit
10(a)52 herein.
(g)4 - Completion Guarantee among Southern Company, Southern
Power and Citibank, N.A., in its capacity as agent for the
Lenders under the Credit Facility dated as of November 15,
2001. See Exhibit 10(a)53 herein.
(g)5 - Letter Amendment No. 1 to Completion Guarantee among
Southern Company, Southern Power and Citibank, N.A. in its
capacity as agent for the Lenders under the Credit Facility
dated as of April 17, 2003. See Exhibit 10(a)55 herein.
(g)6 - Completion Guarantee Supplement by Southern Company and
Southern Power dated as of April 22, 2002. See Exhibit 10(a)54
herein.
(g)7 - Equity Contribution Agreement among Southern Company and
Citibank, N.A. in its capacity as agent for the Lenders under
the Credit Facility dated as of November 15, 2001. See Exhibit
10(a)56 herein.
(g)8 - Letter Amendment No. 1 to Equity Contribution Agreement
among Southern Company, Southern Power and Citibank, N.A. in
its capacity as agent for the Lenders under the Credit
Facility dated as of April 17, 2003. See Exhibit 10(a)57
herein.
(g)9 - Equity Contribution Agreement Supplement by Southern
Company and Southern Power dated as of April 22, 2002. See
Exhibit 10(a)58 herein.
*(g)10 - Amended and Restated Operating Agreement between Southern
Power and Alabama Power effective December 1, 2002. See
Exhibit 10(a)59 herein.
*(g)11 - Amended and Restated Operating Agreement between Southern
Power and Georgia Power effective December 1, 2002. See
Exhibit 10(a)60 herein.
*(g)12 - Operating Agreement between Southern Power and Savannah
Electric effective January 1, 2003. See Exhibit 10(a)61
herein.
(g)13 - Interconnection Agreement by and between Southern Power
and Georgia Power for Plant Dahlberg dated as of July 31,
2001. See Exhibit 10(a)62 herein.
E-36
(g)14 - Interconnection Agreement by and between Southern Power
and Georgia Power for Wansley CC Units 6 and 7 dated as of May
10, 2001. See Exhibit 10(a)63 herein.
(g)15 - Interconnection Agreement by and between Southern Power
and Georgia Power for Goat Rock CC Unit 1 dated as of May 10,
2001. See Exhibit 10(a)64 herein.
(g)16 - Revised and Restated Interconnection Agreement by and
between Southern Power and Georgia Power for Goat Rock CC Unit
2 dated as of October 18, 2001. See Exhibit 10(a)65 herein.
(g)17 - Interconnection Agreement by and between Southern Power
and Alabama Power for Autaugaville Combined Cycle Unit 1 dated
as of June 25, 2001. See Exhibit 10(a)66 herein.
(g)18 - Interconnection Agreement by and between Southern Power
and Alabama Power for Autaugaville Combined Cycle Unit 2 dated
as of June 25, 2001. See Exhibit 10(a)67 herein.
(g)19 - Purchased Power Agreement between Georgia Power and LG&E
Energy Marketing Inc. dated as of November 24, 1998. See
Exhibit 10(a)68 herein.
(g)20 - Purchased Power Agreement between Georgia Power and LG&E
Energy Marketing Inc. dated as of October 6, 1999. See Exhibit
10(a)69 herein.
(g)21 - Assignment and Assumption Agreement by and between
Georgia Power and Southern Power dated as of July 31, 2001.
See Exhibit 10(a)70 herein.
(g)22 - Power Purchase Agreement between Southern Power and
Alabama Power dated as of June 1, 2001. See Exhibit 10(a)71
herein.
(g)23 - Amended and Restated Power Purchase Agreement between
Southern Power and Georgia Power at Plant Autaugaville dated
as of August 6, 2001. See Exhibit 10(a)72 herein.
(g)24 - Contract for the Purchase of Firm Capacity and Energy
between Southern Power and Savannah Electric dated as of July
26, 2001. See Exhibit 10(a)73 herein.
(g)25 - Contract for the Purchase of Firm Capacity and Energy
between Southern Power and Georgia Power dated as of July 26,
2001. See Exhibit 10(a)74 herein.
(g)26 - Power Purchase Agreement between Southern Power and
Georgia Power at Plant Goat Rock dated as of March 30, 2001.
See Exhibit 10(a)75 herein.
(g)27 - Power Purchase Agreement between Southern Company -
Florida LLC and Kissimmee Utility Authority dated as of March
19, 2001. See Exhibit 10(a)76 herein.
(g)28 - Power Purchase Agreement between Southern Company -
Florida LLC and Florida Municipal Power Agency dated as of
March 19, 2001. See Exhibit 10(a)77 herein.
E-37
(g)29 - Power Purchase Agreement between Southern Company -
Florida LLC and Orlando Utilities Commission dated as of March
19, 2001. See Exhibit 10(a)78 herein.
(14) Code of Ethics
Southern Company
*(a) - The Southern Company Code of Ethics.
Alabama Power
*(b) - The Southern Company Code of Ethics. See Exhibit 14(a)
herein.
Georgia Power
*(c) - The Southern Company Code of Ethics. See Exhibit 14(a)
herein.
Gulf Power
*(d) - The Southern Company Code of Ethics. See Exhibit 14(a)
herein.
Mississippi Power
*(e) - The Southern Company Code of Ethics. See Exhibit 14(a)
herein.
Savannah Electric
*(f) - The Southern Company Code of Ethics. See Exhibit 14(a)
herein.
Southern Power
*(g) - The Southern Company Code of Ethics. See Exhibit 14(a)
herein.
(21) Subsidiaries of Registrants
Southern Company
*(a) - Subsidiaries of Registrant.
Alabama Power
*(b) - Subsidiaries of Registrant. See Exhibit 21(a) herein.
E-38
Georgia Power
*(c) - Subsidiaries of Registrant. See Exhibit 21(a) herein.
Gulf Power
*(d) - Subsidiaries of Registrant. See Exhibit 21(a) herein.
Mississippi Power
*(e) - Subsidiaries of Registrant. See Exhibit 21(a) herein.
Savannah Electric
*(f) - Subsidiaries of Registrant. See Exhibit 21(a) herein.
Southern Power
*(g) - Subsidiaries of Registrant. See Exhibit 21(a) herein.
(23) Consents of Experts and Counsel
Southern Company
*(a)1 - Consent of Deloitte & Touche LLP.
*(a)2 - Notice Regarding Consent of Arthur Andersen LLP.
Alabama Power
*(b)1 - Consent of Deloitte & Touche LLP.
*(b)2 - Notice Regarding Consent of Arthur Andersen LLP. See
Exhibit 23(a)2 herein.
Georgia Power
*(c)1 - Consent of Deloitte & Touche LLP.
*(c)2 - Notice Regarding Consent of Arthur Andersen LLP. See
Exhibit 23(a)2 herein.
Gulf Power
*(d)1 - Consent of Deloitte & Touche LLP.
*(d)2 - Notice Regarding Consent of Arthur Andersen LLP. See
Exhibit 23(a)2 herein.
Mississippi Power
*(e)1 - Consent of Deloitte & Touche LLP.
*(e)2 - Notice Regarding Consent of Arthur Andersen LLP. See
Exhibit 23(a)2 herein.
E-39
Savannah Electric
*(f)1 - Consent of Deloitte & Touche LLP.
*(f)2 - Notice Regarding Consent of Arthur Andersen LLP. See
Exhibit 23(a)2 herein.
(24) Powers of Attorney and Resolutions
Southern Company
*(a) - Power of Attorney and resolution.
Alabama Power
*(b) - Power of Attorney and resolution.
Georgia Power
*(c) - Power of Attorney and resolution.
Gulf Power
*(d) - Power of Attorney and resolution.
Mississippi Power
*(e) - Power of Attorney and resolution.
Savannah Electric
*(f) - Power of Attorney and resolution.
Southern Power
*(g) - Power of Attorney and resolution.
(31) Section 302 Certifications
Southern Company
*(a)1 - Certificate of Southern Company's Chief Executive Officer
required by Section 302 of the Sarbanes-Oxley Act of 2002.
*(a)2 - Certificate of Southern Company's Chief Financial Officer
required by Section 302 of the Sarbanes-Oxley Act of 2002.
E-40
Alabama Power
*(b)1 - Certificate of Alabama Power's Chief Executive Officer
required by Section 302 of the Sarbanes-Oxley Act of 2002.
*(b)2 - Certificate of Alabama Power's Chief Financial Officer
required by Section 302 of the Sarbanes-Oxley Act of 2002.
Georgia Power
*(c)1 - Certificate of Georgia Power's Chief Executive Officer
required by Section 302 of the Sarbanes-Oxley Act of 2002.
*(c)2 - Certificate of Georgia Power's Chief Financial Officer
required by Section 302 of the Sarbanes-Oxley Act of 2002.
Gulf Power
*(d)1 - Certificate of Gulf Power's Chief Executive Officer
required by Section 302 of the Sarbanes-Oxley Act of 2002.
*(d)2 - Certificate of Gulf Power's Chief Financial Officer
required by Section 302 of the Sarbanes-Oxley Act of 2002.
Mississippi Power
*(e)1 - Certificate of Mississippi Power's Chief Executive Officer
required by Section 302 of the Sarbanes-Oxley Act of 2002.
*(e)2 - Certificate of Mississippi Power's Chief Financial Officer
required by Section 302 of the Sarbanes-Oxley Act of 2002.
Savannah Electric
*(f)1 - Certificate of Savannah Electric's Chief Executive Officer
required by Section 302 of the Sarbanes-Oxley Act of 2002.
*(f)2 - Certificate of Savannah Electric's Chief Financial Officer
required by Section 302 of the Sarbanes-Oxley Act of 2002.
Southern Power
*(g)1 - Certificate of Southern Power's Chief Executive Officer
required by Section 302 of the Sarbanes-Oxley Act of 2002.
*(g)2 - Certificate of Southern Power's Chief Financial Officer
required by Section 302 of the Sarbanes-Oxley Act of 2002.
E-41
(32) Section 906 Certifications
Southern Company
*(a) - Certificate of Southern Company's Chief Executive Officer
and Chief Financial Officer required by Section 906 of the
Sarbanes-Oxley Act of 2002.
Alabama Power
*(b) - Certificate of Alabama Power's Chief Executive Officer and
Chief Financial Officer required by Section 906 of the
Sarbanes-Oxley Act of 2002.
Georgia Power
*(c) - Certificate of Georgia Power's Chief Executive Officer and
Chief Financial Officer required by Section 906 of the
Sarbanes-Oxley Act of 2002.
Gulf Power
*(d) - Certificate of Gulf Power's Chief Executive Officer and
Chief Financial Officer required by Section 906 of the
Sarbanes-Oxley Act of 2002.
Mississippi Power
*(e) - Certificate of Mississippi Power's Chief Executive Officer
and Chief Financial Officer required by Section 906 of the
Sarbanes-Oxley Act of 2002.
Savannah Electric
*(f) - Certificate of Savannah Electric's Chief Executive Officer
and Chief Financial Officer required by Section 906 of the
Sarbanes-Oxley Act of 2002.
Southern Power
*(g) - Certificate of Southern Power's Chief Executive Officer and
Chief Financial Officer required by Section 906 of the
Sarbanes-Oxley Act of 2002.
E-42