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ALABAMA POWER CO - Annual Report: 2004 (Form 10-K)

SOUTHERN COMPANY
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

þ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 2004
OR
o 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 listed 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 Securities2
 
       

 
       
Class A preferred, cumulative, $25 stated capital
  Alabama Power Company
5.20% Series
  5.83% Series    
5.30% Series
       
 
       
Senior Notes
       
5 5/8% Series AA
       
 
       

 
       
Senior Notes
      Georgia Power Company
5.90% Series O
  6% Series R    
5.75% Series T
  6% Series W    
 
       
Mandatorily redeemable preferred securities,
$25 liquidation amount
7 1/8% Trust Preferred Securities3
5 7/8% Trust Preferred Securities4
 
       

 
       
Senior Notes
      Gulf Power Company
5.25% Series H
  5.75% Series I    
5.875% Series J
       
 
       
Mandatorily redeemable preferred securities,
$25 liquidation amount
7.375% Trust Preferred Securities5


1   As of December 31, 2004.
 
2   Issued by Southern Company Capital Trust VI and guaranteed by The Southern Company.
 
3   Issued by Georgia Power Capital Trust V and guaranteed by Georgia Power Company.
 
4   Issued by Georgia Power Capital Trust VII 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
5.25% Series
       
 
       
Mandatorily redeemable preferred securities,
$25 liquidation amount
7.20% Trust Originated Preferred Securities6
 
       

 
       
Preferred stock, non-cumulative, $25 par value
  Savannah Electric and Power Company
6% Series
       
 
       
Senior Notes
       
5.75% Series G
       

Securities registered pursuant to Section 12(g) of the Act: 7

             
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)
 
           

 
           
Preferred stock, cumulative, $100 stated value
  Georgia Power Company
$4.60 Series (1954)
           
 
           

 
           
Preferred stock, cumulative, $100 par value
  Gulf Power Company
4.64% Series
  5.44% Series        
5.16% Series
           
 
           

 
           
Preferred stock, cumulative, $100 par value
  Mississippi Power Company
4.40% Series
  4.60% Series        
4.72% Series
           
 
           


6   Issued by Mississippi Power Capital Trust II and guaranteed by Mississippi Power Company.
 
7   As of December 31, 2004.

 


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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 þ No o

      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. o

      Indicate by check mark whether the registrant is an accelerated filer (as defined by Rule 12b-2 of the Securities Exchange Act of 1934).

         
Registrant   Yes   No
The Southern Company
  x    
Alabama Power Company
      x
Georgia Power Company
      x
Gulf Power Company
      x
Mississippi Power Company
      x
Savannah Electric and Power Company
      x
Southern Power Company
      x

      Aggregate market value of voting and non-voting stock held by non-affiliates of The Southern Company at June 30, 2004: $21.5 billion. All of the common stock of the other registrants is held by The Southern Company. A description of each registrant’s common stock follows:

             
    Description of   Shares Outstanding
Registrant   Common Stock   at January 31, 2005
The Southern Company
  Par Value $5 Per Share     742,831,334  
Alabama Power Company
  Par Value $40 Per Share     8,250,000  
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 2005 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 2005 Annual Meetings of Shareholders are incorporated by reference into PART III.

      Southern Power meets the conditions set forth in General Instructions I(1)(a) and (b) of Form 10-K and is therefore filing this Form 10-K with the reduced disclosure format specified in General Instructions I(2)(b) and (c) of Form 10-K.

      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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        Page
 
       
       
 
       
Item 1      
      I-2
      I-2
      I-2
      I-3
      I-3
      I-11
      I-12
      I-13
      I-14
      I-17
      I-18
      I-20
      I-22
Item 2     I-23
Item 3     I-26
Item 4     I-27
      I-28
      I-30
      I-31
      I-33
      I-34
 
       
       
 
       
Item 5     II-1
Item 6     II-2
Item 7     II-2
Item 7A     II-2
Item 8     II-3
Item 9     II-4
Item 9A     II-5
Item 9B     II-6
 
       
       
 
       
Item 10     III-1
Item 11     III-3
Item 12     III-9
Item 13     III-11
Item 14     III-12
 
       
       
 
       
Item 15     IV-1
      IV-2

 


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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
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
JEA  
Jacksonville Electric Authority
KUA  
Kissimmee Utility Authority
MEAG  
Municipal Electric Authority of Georgia
Mirant  
Mirant Corporation
Mississippi Power  
Mississippi Power Company
Moody’s  
Moody’s Investors Service
NRC  
Nuclear Regulatory Commission
OPC  
Oglethorpe Power Corporation
OUC  
Orlando Utilities Commission
PPA  
Power Purchase Agreement
Progress Energy  
Florida Power Corporaton, d/b/a Progress Energy Florida, Inc.
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

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DEFINITIONS
(continued)

     
     
RFP  
Request for Proposal
RTO  
Regional Transmission Organization
RUS  
Rural Utility Service (formerly Rural Electrification Administration)
S&P  
Standard and Poor’s, 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
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, SouthernLINC Wireless, Southern Company GAS and other subsidiaries
Southern Holdings  
Southern Company Holdings, Inc.
SouthernLINC Wireless  
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

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CAUTIONARY STATEMENT REGARDING
FORWARD-LOOKING INFORMATION

      This Annual Report on Form 10-K contains forward-looking statements. Forward-looking statements include, among other things, statements concerning the strategic goals for Southern Company’s wholesale business, retail sales growth, storm damage cost recovery, environmental regulations and expenditures, projections for postretirement benefit trust contributions, completion of construction projects and estimated construction and other expenditures. 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 similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:

•   the impact of recent and future federal and state regulatory change, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, and also changes in environmental, 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;
 
•   current and future litigation, regulatory investigations, proceedings or inquiries, including the pending EPA civil actions against certain Southern Company subsidiaries, IRS audits and Mirant related matters;
 
•   the effects, extent and timing of the entry of additional competition in the markets in which Southern Company’s subsidiaries operate;
 
•   variations in demand for electricity and gas, including those relating to weather, the general economy and population and business growth (and declines);
 
•   available sources and costs of fuels;
 
•   ability to control costs;
 
•   investment performance of Southern Company’s employee benefit plans;
 
•   advances in technology;
 
•   state and federal rate regulations and the impact of pending and future rate cases and negotiations;
 
•   the performance of projects undertaken by the non-utility businesses and the success of efforts to invest in and develop new opportunities;
 
•   internal restructuring or other restructuring options that may be pursued;
 
•   potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to Southern Company or its subsidiaries;
 
•   the ability of counterparties of Southern Company and its subsidiaries to make payments as and when due;
 
•   the ability to obtain new short- and long-term contracts with neighboring utilities;
 
•   the direct or indirect effect on Southern Company’s business resulting from terrorist incidents and the threat of terrorist incidents;
 
•   interest rate fluctuations and financial market conditions and the results of financing efforts, including Southern Company’s and its subsidiaries’ credit ratings;
 
•   the ability of Southern Company and its subsidiaries to obtain additional generating capacity at competitive prices;
 
•   catastrophic events such as fires, earthquakes, explosions, floods, hurricanes or other similar occurrences;
 
•   the direct or indirect effects on Southern Company’s business resulting from incidents similar to the August 2003 power outage in the Northeast;
 
•   the effect of accounting pronouncements issued periodically by standard setting bodies; and
 
•   other factors discussed elsewhere herein and in other reports filed by the registrants from time to time with the SEC.

Southern Company and its subsidiaries expressly disclaim any obligation to update any forward-looking statements.

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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 SouthernLINC Wireless, Southern Company GAS, Southern Nuclear, SCS, Southern Telecom, Southern Holdings and other direct and indirect subsidiaries. SouthernLINC Wireless provides digital wireless communications services to the 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 synthetic fuels and leveraged leases and various other energy-related businesses.

      Alabama Power and Georgia Power each own 50% of the outstanding common stock of SEGCO. SEGCO is an operating public utility company that owns electric generating units with an aggregate capacity of 1,019,680 kilowatts at Plant Gaston on the Coosa River near Wilsonville, Alabama. 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.

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      See 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 on Southern Company’s website, 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 BUSINESS — “Territory Served by the Utilities” in Item 1 herein for additional information.

      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 reliable 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, SouthernLINC Wireless 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 BUSINESS — “Regulation — Atomic Energy Act of 1954” in Item 1 herein for additional information.

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

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FERC. Southern Power has attempted to insulate itself from significant fuel supply, fuel transportation and electric transmission risks by making such risks the responsibility of the counterparties to the PPAs. However, Southern Power’s overall profit will depend on the parameters of the wholesale market and its efficient operation of its wholesale generating assets. At December 31, 2004, Southern Power had approximately 4,775 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 12.2% market share as of December 31, 2004.

      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, which provides energy services.

      In 1996, SouthernLINC Wireless 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.

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, 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

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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.

Certain 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 in regulated and unregulated electric 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.

Deregulation or restructuring in the electric industry may result in increased competition and unrecovered costs which could negatively impact Southern Company’s earnings and the value of its assets.

      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

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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.

Potential changes to the criteria used by the FERC for approval of market-based contracts may negatively impact the retail operating companies’ and Southern Power’s ability to charge market-based rates.

Each of the retail operating companies and Southern Power have authorization from the FERC to sell power to nonaffiliates at market-based prices. The retail operating companies and Southern Power 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, the retail operating companies and Southern Power, and found Southern Company and others to be “pivotal suppliers” in their retail service territories 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. In April 2004, the FERC issued an order that abandoned the SMA test and adopted a new interim analysis for measuring generation market power. This new interim approach requires utilities to submit a pivotal supplier screen and a wholesale market share screen. If the applicant does not pass both screens, there will be a rebuttable presumption regarding generation market power. The FERC’s order also sets forth procedures for rebutting these presumptions and addresses mitigation measures for those entities that are found to have market power. In the absence of specific mitigation measures, the order includes several cost-based mitigation measures that would apply by default. The FERC also initiated a new rulemaking proceeding that, among other things, will adopt a final methodology for assessing generation market power.

      In July 2004, the FERC denied Southern Company’s request for rehearing, along with a number of others, and reaffirmed the interim tests that it adopted in April 2004. In August 2004, Southern Company submitted a filing to the FERC that included results showing that Southern Company passed the pivotal supplier screen for all markets and the wholesale market share screen for all markets except the Southern Company retail service territory. Southern Company also submitted other analyses to demonstrate that it lacks generation market power. On December 17, 2004, the FERC initiated a proceeding to assess Southern Company’s generation dominance within its retail service territory. The ability to charge market-based rates in other markets is not at issue. As directed by this order, on February 15, 2005, Southern Company submitted additional information related to generation dominance in its retail service territory. Any new market-based rate transactions in the Southern Company retail service territory entered into after February 27, 2005 will be subject to refund to the level of the default cost-based rates, pending the outcome of the proceeding. Southern Company, along with other utilities, has also filed an appeal of the FERC’s April and July 2004 orders with the U.S. Court of Appeals for the District of Columbia Circuit. The FERC has asked the court to dismiss the appeal on the grounds that it is premature.

      In the event that the FERC’s default mitigation measures are ultimately applied, Southern Power and the retail operating companies may be required to charge cost-based rates for certain wholesale sales in the Southern Company retail service territory, which may be lower than negotiated market-based rates. The final outcome of this matter will depend on

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the form in which the final methodology for assessing generation market power and mitigation rules may be ultimately adopted and cannot be determined at this time.

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 $1.1 billion through 2004 with an additional $500 million committed through 2007 for the states of Alabama and Georgia.

      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. 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 condition 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. In addition, Georgia Power is a party to a civil suit regarding alleged violations of the Clean Air Act at four units of Plant Wansley. Attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel for New York City filed a complaint in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. A nearly identical complaint was filed by three environmental groups in the same court. The complaints allege that the companies’ emissions of carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs assert is a public nuisance. An adverse outcome in any one of these cases could require substantial capital expenditures that cannot be determined at this time and/or 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

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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.

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:

  •   operator error and breakdown or failure of equipment or processes;
 
  •   operating limitations that may be imposed by environmental or other regulatory requirements;
 
  •   labor disputes;
 
  •   terrorist attacks;
 
  •   fuel supply interruptions; and
 
  •   catastrophic events such as fires, earthquakes, explosions, floods, hurricanes 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.

      In addition, Southern Company’s non-utility businesses depend on the successful operation of their respective facilities. For example, SouthernLINC Wireless’ business could be adversely impacted in the event of a break-down of its telecommunications facilities.

Through its subsidiaries, 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 has been sold to purchasers under PPAs having initial terms of five to 15 years. In addition, the retail operating companies also enter into PPAs with non-affiliated parties. Southern Company’s revenues are dependent on the continued performance by the purchasers of their obligations under the PPAs. Even though Southern Power and the retail operating companies have a rigorous credit evaluation, the failure of one of the purchasers to perform its obligations could have a negative impact on Southern Company’s earnings. Although these credit evaluations take into account the possibility of default by a purchaser, Southern Company’s actual exposure to a default by a purchaser may be greater than the credit evaluation predicts. Neither Southern Power nor the retail operating companies can predict whether the PPAs 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, a replacement PPA cannot be assured.

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.

      Certain of the retail operating companies and Southern Power are in the process of constructing new generating facilities. Southern Company 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:

  •   shortages and inconsistent quality of equipment, materials and labor;
 
  •   work stoppages;
 
  •   permits, approvals and other regulatory matters;
 
  •   adverse weather conditions;
 
  •   unforeseen engineering problems;
 
  •   environmental and geological conditions;
 
  •   delays or increased costs to interconnect its facilities to transmission grids;
 
  •   unanticipated cost increases; and
 
  •   attention to other projects.

      If a retail operating company or Southern Power is unable to complete the development or construction of a

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facility, or if a retail operating company or Southern Power decides to delay or cancel construction of a facility, it 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 the results of operations and financial position of a retail operating company or Southern Power. Furthermore, if construction projects are not completed according to specification, a retail operating company or 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. Significant portions of the retail operating companies’ existing facilities were constructed many years ago. Older generation equipment, even if maintained in accordance with good engineering practices, may require significant capital expenditures to maintain efficiency, to comply with changing environmental requirements or to provide reliable operations.

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, 2004. 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, in some cases, 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.

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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 through retail fuel cost recovery or in its PPAs. Among the factors that could influence power prices and fuel costs are:

  •   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;
 
  •   demand for energy and the extent of additional supplies of energy available from current or new competitors;
 
  •   liquidity in the general wholesale electricity market;
 
  •   weather conditions impacting demand for electricity;
 
  •   seasonality;
 
  •   transmission or transportation constraints or inefficiencies;
 
  •   availability of competitively priced alternative energy sources;
 
  •   forced or unscheduled plant outages for us, our competitors or third party providers;
 
  •   the financial condition of market participants;
 
  •   the economy in the service territory and in general, including the impact of economic conditions on industrial and commercial demand for electricity;
 
  •   natural disasters, wars, embargos, acts of terrorism and other catastrophic events; and
 
  •   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. In the absence of actively quoted market prices and pricing information from external sources, the valuation of these financial instruments can involve management’s judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the value of the reported fair value of these contracts.

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.

Southern Company may not be able to obtain adequate supply of coal, which could limit its ability to operate its facilities.

      The retail operating companies are dependent on coal for much of their electric generating capacity. Each retail operating company has coal supply contracts in place; however, there can be no assurance that the counterparties to these agreements will fulfill their obligations to supply coal to the retail operating companies. The suppliers under these agreements may experience financial or technical problems which inhibit their ability to fulfill their obligations to the retail operating companies. In addition, the suppliers under these agreements may not be required to supply coal to the retail operating companies under certain circumstances, such as in the event of a natural disaster.

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If the retail operating companies are unable to obtain their coal requirements under these contracts, the retail operating companies may be required to purchase their coal requirements at higher prices, which may not be fully recoverable through rates.

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 under long-term PPAs. 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 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:

  •   an economic downturn;
 
  •   the bankruptcy of an unrelated energy company;
 
  •   capital market conditions generally;
 
  •   market prices for electricity and gas;
 
  •   terrorist attacks or threatened attacks on Southern Company’s facilities or unrelated energy companies;
 
  •   war or threat of war; or
 
  •   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.

      The September 11, 2001 terrorist attacks, the continuing threat of terrorism and the related military action by the United States have affected the nation’s economy and financial markets. 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

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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 2005 through 2007 by the retail operating companies, Southern Power and other subsidiaries are estimated as follows:

                         
 
    2005   2006   2007
    (in millions)
Alabama Power
  $ 902     $ 921     $ 1,018  
Georgia Power
    911       1,067       1,210  
Gulf Power
    154       112       103  
Mississippi Power
    88       95       90  
Savannah Electric
    52       39       34  
Southern Power
    57       147       718  
Other subsidiaries
    67       79       67  
 
   
 
  $ 2,231     $ 2,460     $ 3,240  
 
   

      Also included in the foregoing construction expenditure estimates are the estimates for environmental expenditures. See MANAGEMENT’S DISCUSSION AND ANALYSIS — FINANCIAL CONDITION AND LIQUIDITY — “Capital Requirements and Contractual Obligations” of Southern Company and each retail operating company in Item 7 herein for additional information on estimated environmental expenditures.

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Estimated construction costs in 2005 are expected to be apportioned approximately as follows: (in millions)

                                                         
 
    Southern                        
    Company   Alabama   Georgia   Gulf   Mississippi   Savannah   Southern
    System*   Power   Power   Power   Power   Electric   Power
 
   
New generation
  $ 89     $     $ 49     $     $     $ 10     $ 31  
Other generating
                                                       
facilities including associated plant substations
    770       387       240       82       29       6       26  
New business
    402       141       199       26       23       12        
Transmission
    337       111       191       11       15       9        
Joint line and substation
    39             34       5                    
Distribution
    253       130       71       22       15       13        
Nuclear fuel
    142       78       64                          
General plant
    199       55       63       8       6       2        
 
   
 
  $ 2,231     $ 902     $ 911     $ 154     $ 88     $ 52     $ 57  
 
   

      *These amounts include the retail operating companies and Southern Power (as detailed in the table above) as well as the amounts for the other subsidiaries. See BUSINESS — “Other Business” in Item 1 herein for additional information.

      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; environmental regulations; changes in existing nuclear plants to meet new regulatory requirements; changes in FERC rules and transmission regulations; increasing cost 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.

      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 BUSINESS — “Rate Matters — Integrated Resource Planning” in Item 1 herein and Note 3 to the financial statements under “Plant McIntosh Construction Project” of Southern Company, Georgia Power and Savannah Electric and Note 2 to the financial statements of Southern Power in Item 8 herein under “Plant McIntosh Construction Project” for additional information regarding the acquisition by Georgia Power and Savannah Electric of the Plant McIntosh construction project and the withdrawal of the PPAs with Southern Power for Plant McIntosh’s capacity.

      See BUSINESS — “Regulation — Environmental Statutes and Regulations” in Item 1 herein for additional information with respect to certain existing and proposed environmental requirements and PROPERTIES — “Jointly-Owned Facilities” in Item 2 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.

Financing Programs

See each of the registrant’s MANAGEMENT’S DISCUSSION AND ANALYSIS — FINANCIAL CONDITION AND LIQUIDITY in Item 7 herein, Note 6 to the financial statements of Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power and Savannah Electric and Note 5 to the financial statements of Southern Power in Item 8 herein for information concerning financing programs.

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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 2002 through 2004 are shown below:

                                                 
            Coal     Nuclear     Hydro     Gas     Oil  
            %     %     %     %     %  
 
           
Alabama Power
                                               
 
    2002       62       19       6       13       *  
 
    2003       64       19       8       9       *  
 
    2004       65       19       6       10       *  
Georgia Power
                                               
 
    2002       78       21       1       *       *  
 
    2003       75       22       3       *       *  
 
    2004       76       22       2       *       *  
Gulf Power
                                               
 
    2002       82       **     * *     18       *  
 
    2003       87       **     * *     13       *  
 
    2004       84       **     * *     16       *  
Mississippi Power
                                               
 
    2002       57       **     * *     43       *  
 
    2003       74       **     * *     26       *  
 
    2004       69       **     * *     31       *  
Savannah Electric
                                               
 
    2002       91       **     * *     8       1  
 
    2003       94       **     * *     4       2  
 
    2004       96       **     * *     3       1  
SEGCO
                                               
 
    2002       100       **     * *     *       *  
 
    2003       100       **     * *     *       *  
 
    2004       100       **     * *     *       *  
Southern Power
                                               
 
    2002       **     **     * *     100       *  
 
    2003       **     **     * *     99       1  
 
    2004       **     **     * *     100       *  
Southern Company system — weighted average
                                               
 
    2002       69       16       3       12       *  
 
    2003       71       16       4       9       *  
 
    2004       69       16       3       12       *  
 

  * Less than 0.5%.
** Not applicable.

      The average costs of fuel in cents per net kilowatt-hour generated for 2002 through 2004 are shown below:

                                                 
    2002     2003     2004                          
 
   
 
                                               
Alabama Power
    1.44       1.54       1.69                          
 
                                               
Georgia Power
    1.42       1.46       1.55                          
 
                                               
Gulf Power
    2.08       2.11       2.32                          
 
                                               
Mississippi Power
    2.03       1.95       2.47                          
 
                                               
Savannah Electric
    2.44       2.38       2.57                          
 
                                               
SEGCO
    1.53       1.54       1.60                          
 
                                               
Southern Power
    3.17       3.79       4.36                          
 
                                               
Southern Company system — weighted average
    1.58       1.66       1.87                          
 

      The retail operating companies have long-term agreements in place from which they expect to receive approximately 85.7% of their coal burn requirements in 2005. These agreements cover remaining terms up to 8 years. In 2004, the weighted average sulfur content of all coal burned by the retail operating companies was 0.74% sulfur. This sulfur level, along with banked and purchased sulfur dioxide allowances, allowed the retail operating companies to remain within limits set by the Phase II acid rain requirements of the Clean Air Act. In 2004, Southern Company purchased approximately $45 million in sulfur dioxide and nitrogen oxide emission allowances. As additional environmental regulations are proposed that impact the utilization of coal, the retail operating companies’ fuel mix will be monitored to ensure that the retail operating companies remain in compliance with applicable laws and regulations. Additionally, Southern Company and the retail operating companies will continue to evaluate the need to purchase additional emission allowances, and the timing of capital expenditures for emission control equipment. See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Statutes and Regulations” of Southern Company and each of the retail operating companies in Item 7 herein for information on the Clean Air Act.

      The retail operating companies, Southern Power and Southern Company GAS also have long-term agreements

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in place for their natural gas burn requirements. For 2005, the retail operating companies, Southern Power and Southern Company GAS have contracted for 103 billion cubic feet of natural gas supply. These agreements cover remaining terms up to 14 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 are generally reflected in fuel adjustment clauses contained in rate schedules. See BUSINESS — “Rate Matters — Rate Structure” in Item 1 herein for additional information.

      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 Alabama Power and Georgia Power 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. Construction of an on-site dry storage facility at Plant Farley is in progress and scheduled for operation in 2005. The onsite storage facility is expected to provide adequate spent fuel storage through 2015 for both units. Also, the facility will be able to be expanded to provide storage through 2025. Sufficient pool storage capacity for spent fuel is available at Plant Vogtle to maintain full-core discharge capability for both units into 2015. Construction of an on-site dry storage facility at Plant Vogtle is expected to begin in sufficient time to maintain pool full-core discharge capability. 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.

      The Energy Act established 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 ending in 2008. 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. See Note 1 to the financial statements of Southern Company, Alabama Power and Georgia Power under the heading “Fuel Costs” in Item 8 herein for additional information.

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 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 owns coal reserves near its Gorgas Steam Electric Generating Plant and uses the output of coal from the reserves in its generating plants. 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 transmission, distribution and sale of such electricity within the State of Georgia at retail in over 600 communities, as well as in rural areas,

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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, see MANAGEMENT’S DISCUSSION AND ANALYSIS — RESULTS OF OPERATIONS of each of the retail operating companies 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 8.16% 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 PROPERTIES — “Jointly-Owned Facilities” in Item 2 herein for details of Alabama Power’s joint-ownership with AEC of a portion of Plant Miller.

      Mississippi Power has an interchange agreement with SMEPA, a generating and transmitting cooperative, pursuant to which various services are provided, including the furnishing of protective capacity by Mississippi Power to SMEPA.

      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. In January 2005, three of these organizations began obtaining their power from

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TVA, one from Southern Power under a 15-year agreement and one from other sources. OPC has a wholesale power contract with the remaining 38 of these cooperative organizations. OPC and these cooperative organizations utilize 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 their power supply obligations. Georgia Power, OPC, and Georgia Systems Operations Corporation have entered into a new control area compact agreement that will replace current coordination service agreements among the parties in 2005 pending acceptance by the FERC.

      Pursuant to an agreement entered into in April 1999, OPC will purchase 250 megawatts of capacity from Georgia Power through March 2006. In April 2006, AEC will start purchasing such capacity for a 10-year term. In January 2005, 30 electric cooperative organizations served by OPC began purchasing a total of 700 megawatts of capacity from Georgia Power under individual contracts for 10-year terms. Also, on January 1, 2005, one of the electric cooperatives began purchasing 25 megawatts of peaking capacity from Georgia Power under a 10-year contract. Another of the electric cooperatives will purchase 50 megawatts and 75 megawatts of peaking capacity from Georgia Power beginning April 1, 2006 and June 1, 2010, respectively. See PROPERTIES — “Jointly-Owned Facilities” in Item 2 herein for additional information.

      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 the financial statements of Alabama Power under “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 entered into a power supply agreement pursuant to which it will purchase 134 megawatts from Georgia Power for a 15-year term. In addition, another municipally-owned electric distribution system’s full requirements are served under a market-based contract by Georgia Power. See PROPERTIES — “Jointly-Owned Facilities” in Item 2 herein for additional information.

      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 PROPERTIES — “Jointly-Owned Facilities” in Item 2 herein for additional information.

      See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Other Matters” of Gulf Power and MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Power Sales Agreements” of Southern Power in Item 8 herein for information concerning certain PPAs entered into during 2004.

      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.

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      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 (451 municipalities, including Atlanta, Columbus, Macon, Augusta, Athens, Rome and Valdosta, to Georgia Power; 115 to electric cooperatives; and 50 to publicly-owned systems). Areas outside of such municipal limits were either to be assigned or to be declared open for customer choice of supplier by action of the Georgia PSC pursuant to standards set forth in the Act. Consistent with such standards, the Georgia PSC has assigned substantially all of the land area in the state to a supplier. Notwithstanding such assignments, the Act provides that any new customer locating outside of 1973 municipal limits and having a connected load of at least 900 kilowatts may receive electric service from the supplier of its choice. See BUSINESS — “Competition” in Item 1 herein for additional information.

      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 BUSINESS — “Competition” in Item 1 herein for additional information.

      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 375,000 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.

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.

      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 2004, Alabama Power purchased approximately 178 million kilowatt-hours from such companies at a cost of $5.2 million.

      Georgia Power currently has contracts in effect with nine small power producers whereby Georgia Power purchases their excess generation. During 2004, Georgia Power purchased 10 million kilowatt-hours from such companies at a cost of $0.6 million. Georgia Power has PPAs for electricity with two cogeneration facilities. Payments are subject to reductions for failure to meet minimum capacity output. During 2004, Georgia Power purchased 79 million kilowatt-hours at a cost of $53 million from these facilities. See Note 7 to the financial statements for Georgia Power herein under “Purchased Power Commitments” in Item 8 for additional 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 2004, Gulf Power purchased 31 million kilowatt-hours from such companies for $591,000.

      Mississippi Power currently has a cogeneration agreement in effect with one of its industrial customers. Under the terms of this contract, Mississippi Power purchases any excess generation. During 2004,

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Mississippi Power purchased approximately 12 million kilowatt-hours of excess generation at a cost of $300,000.

      During 2004, 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 2004, Savannah Electric purchased a total of 34 million kilowatt-hours from the six suppliers at a cost of approximately $1.3 million.

      The competition for retail energy sales among competing suppliers of energy is influenced by various factors, including price, availability, technological advancements and reliability. These factors are, in turn, affected by, among other influences, regulatory, political and environmental considerations, taxation and supply.

      The 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 BUSINESS — “Territory Served by the Utilities” in Item 1 herein for additional 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 PSCs, 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 BUSINESS — “Territory Served by the Utilities” and “Rate Matters” in Item 1 herein for additional information.

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 1,662,400 kilowatts and 18 existing Georgia Power generating stations having an aggregate installed capacity of 1,074,696 kilowatts.

      In December 2002, Georgia Power filed a relicensing application for the Middle Chattahoochee Project with the FERC. On December 27, 2004, the FERC issued a new 30-year license for the Middle Chattahoochee Project. This project consists of the Goat Rock, Oliver and North Highlands facilities. In 2003, Georgia Power started the relicensing process for the Morgan Falls project and is currently working on developing study plans for the facility with license participants. 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 eight projects expire in 2007.

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      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 PROPERTIES — “Jointly-Owned Facilities” in Item 2 herein for additional information.

      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.

      See Notes 1 and 9 to the financial statements of Southern Company, Alabama Power and Georgia Power in Item 8 herein for information on nuclear decommissioning costs and nuclear insurance.

FERC Matters

See Southern Company’s, Alabama Power’s, Georgia Power’s, Gulf Power’s, Mississippi Power’s, Savannah Electric’s and Southern Power’s, MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “FERC and State PSC Matters,” “FERC and Alabama PSC Matters,” “FERC and Georgia PSC Matters,” “FERC and Florida PSC Matters,” “FERC and Mississippi PSC Matters,” “FERC and Georgia PSC Matters” and “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. See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters” of Southern Company and each of the retail operating companies in Item 7 herein for additional information about the Clean Air Act and other environmental issues, including the litigation brought under the New Source Review provisions of the Clean Air Act.

      Additionally, each retail operating company and SEGCO has incurred costs for environmental remediation of various sites. See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL - “Environmental Remediation Reserves” of Southern Company and each of the retail operating companies in Item 7 herein for

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information regarding 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 “Environmental Matters — Environmental Remediation,” 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.

      See 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 IRPs 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 constructions costs and purchase power costs will be recoverable through rates.

      In July 2001, the Georgia PSC approved Georgia Power’s 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 at Plant Franklin. The purchase of the full 570 megawatts from the first unit began in 2003 with the purchase of approximately 250 megawatts beginning earlier in June 2002. The purchase of the full 610 megawatts from the second unit began in 2004 with the purchase of approximately 300 megawatts beginning earlier in June 2003. Also, an upgrade of 12 megawatts was approved for the existing Goat Rock hydro units 1 and 2. Additionally, this certification included approval of a 15-year PPA with Southern Power for 615 megawatts of gas-fired combined cycle generation at Plant Harris in Alabama.

      In December 2002, the Georgia PSC certified the Duke Energy (Murray) generating facility. The Duke Energy (Murray) PPA provides for the purchase by Georgia Power of the full 620 megawatts of output for seven years beginning in June 2005.

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      On January 30, 2004, Georgia Power and Savannah Electric filed the 2004 IRP with the Georgia PSC and received Georgia PSC approval of the 2004 IRP on July 9, 2004. Through the approval of the 2004 IRP, Georgia Power de-certified the Atkinson combustion turbine units 5A and 5B totaling approximately 80 megawatts of capacity. Georgia Power and Savannah Electric will issue an RFP in July 2005 for approximately 1,200 megawatts to meet their future supply-side capacity needs for 2009 and beyond. Additionally, Georgia Power and Savannah Electric will each continue a residential load management program which was certified by the Georgia PSC for up to 40 megawatts of equivalent supply-side capacity. Georgia Power will continue to utilize approximately 8 megawatts of capacity from existing qualifying facilities under firm contracts and continue to add additional resources as ordered by the Georgia PSC.

      In May 2004, the Georgia PSC ordered Georgia Power and Savannah Electric to purchase the McIntosh combined cycle generating facility from Southern Power and place it into their respective rate bases. The McIntosh resource was previously certified as a PPA by the Georgia PSC in the 2002 supply-side certification. The McIntosh units will produce a combined 1,240 megawatts of which Georgia Power’s portion is 1,040 megawatts and Savannah Electric’s portion is 200 megawatts. This new generation is expected to be available by June 2005. See Note 3 to the financial statements of Southern Company, Georgia Power and Savannah Electric under “Plant McIntosh Construction Project” in Item 8 herein for additional information.

Environmental Cost Recovery Plans

On October 5, 2004, the Alabama PSC approved a specific rate mechanism for the recovery of Alabama Power’s retail costs associated with environmental laws, regulations or other such mandates. The rate mechanism began operation in January 2005 and provides for the recovery of these costs pursuant to a factor that will be calculated annually. Environmental costs to be recovered include operation and maintenance expense, depreciation and a return on invested capital. See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNING POTENTIAL — “FERC and State PSC Matters” and “FERC and Alabama PSC Matters,” respectively, in Item 7 herein and Note 3 to the financial statements of Southern Company and Alabama Power in Item 8 herein for a discussion on Alabama PSC rate matters.

      The Florida Legislature has adopted legislation for an Environmental Cost Recovery Clause, 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. See Note 3 to the financial statements of Gulf Power in Item 8 herein under “Environmental Remediation” for additional information.

      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 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. 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 1994 ECO Plan order. Mississippi Power filed its 2005 ECO Plan in January 2005, which, if approved as filed, will result in an increase in customer prices. See Note 3 to the financial statements of Mississippi Power under “Environmental Compliance Overview Plan” for additional information.

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Employee Relations

The Southern Company system had a total of 25,648 employees on its payroll at December 31, 2004.

         
 
    Employees
    at
    December 31, 2004
Alabama Power
    6,745  
Georgia Power
    8,731  
Gulf Power
    1,336  
Mississippi Power
    1,283  
Savannah Electric
    563  
SCS
    3,300  
Southern Nuclear
    3,094  
Southern Power
    *  
Other
    590  
 
Total
    25,642  
 

* 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 five-year contract extending to August 15, 2009. 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. Negotiations are expected to begin in early May 2005 for a new agreement which is expected to be in effect for the next three years beginning July 1, 2005.

      Gulf Power has an agreement with the IBEW covering wages and working conditions, which is in effect through August 15, 2005. Negotiations for a new agreement are scheduled to begin June 6, 2005. The term of the new agreement is subject to negotiation.

      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. 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 10-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, 2004, 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  
 
         
 
           
McIntosh
  Effingham County, GA     163,117  
Kraft
  Port Wentworth, GA     281,136  
Riverside
  Savannah, GA     79,778  
 
         
Savannah Electric Total
        524,031  
 
         
 
           
Gaston Units 1-4
  Wilsonville, AL        
SEGCO Total
        1,000,000  (7)
 
         
Total Fossil Steam
        21,230,243  
 
         
 
           
NUCLEAR STEAM
           
Farley
  Dothan, AL        
Alabama Power Total
        1,720,000  
 
         
 
           
Hatch
  Baxley, GA     899,612  (8)
Vogtle
  Augusta, GA     1,060,240  (9)
 
         
Georgia Power Total
        1,959,852  
 
         
Total Nuclear Steam
        3,679,852  
 
         
 
           
COMBUSTION TURBINES
           
Greene County
  Demopolis, AL        
Alabama Power Total
        720,000  
 
         
 
           
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     158,400  
Wansley
  Carrollton, GA     26,322  
Wilson
  Augusta, GA     354,100  
 
         
Georgia Power Total
        1,784,589  
 
         
 
           
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 5&6
  Effingham County, GA     160,000  
 
         
Savannah Electric Total
        241,100  
 
         

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        Nameplate  
Generating Station   Location   Capacity  
        (Kilowatts)  
Dahlberg
  Jackson County, GA        
Southern Power Total
        756,000  
 
         
 
           
Gaston (SEGCO)
  Wilsonville, AL     19,680   (7)
 
         
Total Combustion Turbines
        3,801,821  
 
         
 
           
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
        545,500  
 
         
 
           
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
        6,705,277  
 
         
 
           
HYDROELECTRIC FACILITIES
           
 
           
Weiss
  Leesburg, AL     87,750  
Henry
  Ohatchee, AL     72,900  
Logan Martin
  Vincent, AL     135,000  
Lay
  Clanton, AL     177,000  
Mitchell
  Verbena, AL     170,000  
Jordan
  Wetumpka, AL     100,000  
Bouldin
  Wetumpka, AL     225,000  
Harris
  Wedowee, AL     132,000  
Martin
  Dadeville, AL     175,000  
Yates
  Tallassee, AL     47,000  
Thurlow
  Tallassee, AL     81,000  
Lewis Smith
  Jasper, AL     157,500  
Bankhead
  Holt, AL     53,985  
Holt
  Holt, AL     48,000  
 
         
Alabama Power Total
        1,662,135  
 
         
 
           
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
        2,739,871  
 
         
 
           
Total Generating Capacity
        38,621,710  
 
         


Notes:
(1)   See PROPERTIES — “Jointly-Owned Facilities” in Item 2 herein for additional information.
 
(2)   Owned by Alabama Power and Mississippi Power as tenants in common in the proportions of 60% and 40%, respectively.
 
(3)   Capacity shown is Alabama Power’s portion (91.84%) of total plant capacity.
 
(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 BUSINESS in Item 1 herein for additional information.
 
(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

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units of the retail operating companies, Southern Power and SEGCO are owned in fee by the respective companies. It is the opinion of management of each such company that its operating properties are adequately maintained and are substantially in good operating condition.

      Mississippi Power owns a 79-mile length of 500-kilovolt transmission line which is leased to Entergy Gulf States. The line, completed in 1984, extends from Plant Daniel to the Louisiana state line. Entergy Gulf States is paying a use fee over a 40-year period covering all expenses and the amortization of the original $57 million cost of the line. At December 31, 2004, the unamortized portion of this cost was approximately $26.2 million.

      The all-time maximum demand on the retail operating companies, Southern Power and SEGCO was 34,414,100 kilowatts and occurred on July 14, 2004. 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 20.2%. See SELECTED FINANCIAL DATA in Item 6 herein for additional information on peak demands.

Jointly-Owned Facilities

Alabama Power, Georgia Power and Southern Power have undivided interests in certain generating plants and other related facilities to or from non-affiliated parties. The percentages of ownership are as follows:

                                                                                                 
            Percentage Ownership  
    Total     Alabama             Georgia                                     Southern                    
    Capacity     Power     AEC     Power     OPC     MEAG     DALTON     FPC     Power     OUC     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 Mountain
    848                   25.4       74.6                                            
Intercession City, FL
    143                   33.3                         66.7                          
Plant Stanton 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 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 Georgia PSC’s disallowances 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.

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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, to second liens pursuant to pollution control bonds of Gulf Power and to excepted encumbrances as defined therein. See Note 6 to the financial statements of Southern Company, Alabama Power, Gulf Power, Mississippi Power and Savannah Electric under “Assets Subject to Lien” and Note 7 to the financial statements of Mississippi Power under “Operating Leases — Plant Daniel Combined Cycle Generating Units” in Item 8 herein for additional information. The retail operating companies own the fee interests in certain of their principal plants as tenants in common. See PROPERTIES — “Jointly-Owned Facilities” in Item 2 herein for additional information. 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.

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)
 
    See “New Source Review Actions” in Note 3 to Southern Company’s and each retail operating company’s financial statements in Item 8 herein for information.
 
(2)   Cooper et al. v. Georgia Power, Southern Company, SCS and Energy Solutions
(Superior Court of Fulton County, Georgia)
 
    See “Race Discrimination Litigation” in Note 3 to Southern Company and Georgia Power financial statements in Item 8 herein for information.
 
(3)   Environmental Remediation
 
    See “Environmental Remediation” in Note 3 to Southern Company’s, Georgia Power’s, Gulf Power’s and Mississippi Power’s financial statements in Item 8 herein for information related to environmental remediation.
 
(4)   In re: Mirant Corporation, et al.
(U.S. Bankruptcy Court for the Northern District of Texas)
 
    See “Mirant Bankruptcy” in Note 3 to Southern Company’s financial statements in Item 8 herein for information.

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(5)   In re: Mirant Corporation Securities Litigation
(United States District Court for the Northern District of Georgia)
 
    See “Mirant Securities Litigation” in Note 3 to Southern Company’s financial statements in Item 8 herein for information.
 
(6)   In re: Mirant Corporation ERISA Litigation
(United States District Court for the Northern District of Georgia)
 
    See “Southern Company Employee Savings Plan Litigation” in Note 3 to Southern Company’s financial statements in Item 8 herein for information.
 
(7)   Sierra Club, et al. v. Georgia Power
(United States District Court for the Northern District of Georgia)
 
    See “Plant Wansley Environmental Litigation” in Note 3 to Southern Company’s and Georgia Power’s financial statements in Item 8 herein for information.
 
(8)   Right of Way Litigation
 
    See “Right of Way Litigation” in Note 3 to Southern Company’s, Georgia Power’s, Gulf Power’s, Mississippi Power’s and Savannah Electric’s financial statements in Item 8 herein for information.
 
(9)   Jerry A. Carter v. Gulf Power
 
    See “Personal Injury Litigation” in Note 3 to Gulf Power’s financial statements in Item 8 herein for information.

See Note 3 to each registrant’s financial statements in Item 8 herein for descriptions of additional legal and administrative proceedings discussed therein.

Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.

      None.

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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, 2004.

David M. Ratcliffe
Chairman, President, Chief Executive Officer and Director
Age 56
Elected in 1999. President since April 2004; Chairman and Chief Executive Officer since July 2004. Previously served as Chief Executive Officer of Georgia Power from June 1999 to April 2004; and President of Georgia Power from June 1999 to December 2003.

Dwight H. Evans
Executive Vice President
Age 56
Elected in 2001. Executive Vice President since May 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 47
Elected in 2003. Executive Vice President, Chief Financial Officer and Treasurer since April 2003. Previously served as President, Chief Executive Officer and Director of Gulf Power from 2002 to April 2003; and Executive Vice President, Treasurer and Chief Financial Officer of Georgia Power from 1999 to 2002.

Michael D. Garrett
Executive Vice President
Age 55
Elected in 2004. Executive Vice President since January 1, 2004. He also serves as President and Director of Georgia Power since January 1, 2004 and Chief Executive Officer of Georgia Power since April 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.

Leonard J. Haynes
Executive Vice President and Chief Marketing Officer
Age 54
Elected in 2001. Executive Vice President and Chief Marketing Officer since May 2001. Previously served as Senior Vice President of Georgia Power from October 1998 to May 2001.

G. Edison Holland, Jr.
Executive Vice President
Age 52
Elected in 2001. Executive Vice President since 2001. Previously served as President and Chief Executive Officer of Savannah Electric from 1997 until 2001.

Charles D. McCrary
Executive Vice President
Age 53
Elected in 1998. Executive Vice President of Southern Company since February 2002; 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; and Vice President of Southern Company from February 1998 to April 2001.

W. Paul Bowers (1)
Executive Vice President of SCS and President and Chief Executive Officer of Southern Power.
Age 48
Elected in 2001. Executive Vice President of SCS and President and Chief Executive Officer of Southern Power since May 2001. Previously served as Senior Vice President and Chief Marketing Officer of Southern Company from March 2000 to May 2001; and 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.

J. Barnie Beasley
President and Chief Executive Officer of Southern Nuclear.
Age 53
Elected in 2004. President and Chief Executive Officer of Southern Nuclear since September 2004. Previously served as Executive Vice President of Southern Nuclear from January 2004 to September 2004; and Vice President from July 1998 through December 2003.

(1) Mr. Bowers has resigned as President and Chief Executive Officer of Southern Power, effective March 17, 2005.

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      The officers of Southern Company were elected for a term running from the first meeting of the directors following the last annual meeting (May 26, 2004) for one year until the first board meeting after the next annual meeting or until their successors are elected and have qualified.

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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, 2004.

Charles D. McCrary
President, Chief Executive Officer and Director
Age 53
Elected in 2001. President, Chief Executive Officer and Director since October 2001; 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; and Vice President of Southern Company from February 1998 to April 2001.

Art P. Beattie
Executive Vice President, Chief Financial Officer and Treasurer
Age 50
Elected in 2004. Elected Executive Vice President, Chief Financial Officer and Treasurer in November 2004, effective February 1, 2005. Previously served as Vice President and Comptroller of Alabama Power from 1998 to February 1, 2005.

C. Alan Martin
Executive Vice President
Age 56
Elected in 1999. Executive Vice President of the Customer Service Organization since 2001. Previously served as Executive Vice President of External Affairs from January 2000 to April 2001.

Steven R. Spencer
Executive Vice President
Age 49
Elected in 2001. Executive Vice President of External Affairs since 2001. Previously served as Senior Vice President of External Affairs from July 2000 to April 2001; and Vice President of Southern Company’s External Affairs organization from 1998 to 2000.

Jerry L. Stewart
Senior Vice President
Age 55
Elected in 1999. Senior Vice President of Fossil and Hydro Generation since 1999.

      The officers of Alabama Power were elected for a term running from the last annual meeting of the directors (April 23, 2004) for one year until the next annual meeting or until their successors are elected and have qualified, except for Mr. Beattie whose election was effective on the date indicated.

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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, 2004.

Michael D. Garrett
Chief Executive Officer, President and Director
Age 55
Elected in 2003. Chief Executive Officer since April 2004; President and Director since 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 56
Elected in 1995. Executive Vice President of External Affairs since 1995.

Mickey A. Brown
Executive Vice President
Age 57
Elected in 2001. Executive Vice President of the Customer Service Organization since January 10, 2005. Previously served as Senior Vice President of Distribution from 2001 to 2005; Vice President, Distribution from 2000 to 2001; and Vice President, Northern Region from 1993 to 2000.

C. B. Harreld (1)
Executive Vice President, Chief Financial Officer, Treasurer and Assistant Secretary
Age 60
Elected in 2003. 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.

Cliff S. Thrasher (2)
Executive Vice President, Chief Financial Officer and Treasurer
Age 55
Elected in 2005. Currently serves as 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.

Judy M. Anderson
Senior Vice President
Age 56
Elected in 2001. Senior Vice President of Charitable Giving since 2001. Previously served as Vice President and Corporate Secretary of Georgia Power from 1989 to 2001.

Richard L. Holmes
Senior Vice President
Age 53
Elected in 2003. Senior Vice President of Metro Division, Diversity and Corporate Relations since February 2005. Previously served as Senior Vice President of Corporate Services from 2003 to 2005. Vice President of Corporate Services from 2002 to 2003; Vice President of Region Operations from 2000 to 2002; and Assistant to the President and Chief Executive Officer from 1999 to 2000.

Douglas E. Jones
Senior Vice President
Age 46
Elected in 2005. Senior Vice President since January 10, 2005. Previously served as Executive Vice President of Southern Power from January 2004 to January 2005; 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.

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James H. Miller, III
Senior Vice President
Age 55
Elected in 2004. Senior Vice President and General Counsel since March 2004. Previously served as Vice President and Associate General Counsel for SCS and Senior Vice President, General Counsel and Assistant Secretary of Southern Power from 2001 to 2004; and Senior Vice President, Alabama Power - Birmingham Division from 1999 to 2001.

Leslie R. Sibert
Vice President
Age 42
Elected in 2001. Vice President, Transmission since 2001. Previously served as Decatur Region Manager from 1999 to 2001.

Christopher C. Womack
Senior Vice President
Age 46
Elected in 2001. Senior Vice President of Fossil and Hydro since 2001. Previously served as Vice President and Chief People Officer of Southern Company from 1998 to 2001.

(1) Mr. Harreld was elected Executive Vice President of SCS and Chief Financial Officer of Southern Company’s transmission business unit, effective March 17, 2005 and resigned from Georgia Power effective as of such date.

(2) Mr. Thrasher was elected Executive Vice President, Chief Financial Officer and Treasurer, effective March 17, 2005.

      The officers of Georgia Power were elected for a term running from the last annual meeting of the directors (May 19, 2004) 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 January 10, 2005, and Mr. Thrasher whose election will be effective on March 17, 2005.

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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, 2004.

Susan N. Story
President, Chief Executive Officer and Director
Age 44
Elected in 2003. President, Chief Executive Officer and Director since 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 56
Elected in 1989. Vice President of Customer Operations since 1996.

P. Bernard Jacob
Vice President
Age 50
Elected in 2003. Vice President of External Affairs and Corporate Services since 2003. Previously served as Director of Information Resources 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 51
Elected in 2000. Vice President, Chief Financial Officer and Comptroller since July 27, 2001. Previously served as Comptroller and Chief Financial Officer from 2000 to 2001 and Comptroller from 1992 to 2000.

Penny M. Manuel
Vice President
Age 42
Elected in 2005. Vice President and Senior Production Officer since February 21, 2005. Previously served as Director, Human Resources, for Southern Company Generation from 2002 until February 2005; Vice President and Chief Information Officer, Alabama Power, and Regional Chief Information Officer for Southern Nuclear and SCS from 2001 until 2002; Manager, Business Technology Requirements, Southern Company Generation from 2000 to 2001; and Manager, Integrated Resource Planning, Alabama Power from 1999 to 2000.

      The officers of Gulf Power were elected for a term running from the last annual meeting of the directors (July 22, 2004) for one year until the next annual meeting or until their successors are elected and have qualified, except for Ms. Manuel whose election was effective as shown above.

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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, 2004.

Anthony J. Topazi
President, Chief Executive Officer and Director
Age 54
Elected in 2003. President, Chief Executive Officer and Director since January 1, 2004. Previously served as Executive Vice President of Southern Company Generation and Energy Marketing from November 2000 to December 2004; Senior Vice President of Southern Power from November 2002 to December 2004; Vice President of Southern Power from 2001 until November 2002 and Vice President of SCS — Fuel Services from 1999 to November 2000.

John W. Atherton
Vice President
Age 44
Elected in 2004. Vice President of External Affairs since January 2005. Previously served as the Director of Economic Development from September 2003 to January 2005; Manager, Sales and Marketing Services from April 2002 to August 2003; and Manager, State Legislative Affairs from August 1996 to April 2002.

Kimberly D. Flowers
Vice President
Age 40
Elected in 2005. Vice President and Senior Production Officer effective March 5, 2005. Previously served as Plant Manager, Plant Bowen, Georgia Power from November 2000 until March 2005.

Bobby J. Kerley
Vice President
Age 51
Elected in 2003. 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; and Transmission Lines Manager, Corporate Headquarters from March 1997 to January 2001.

Michael W. Southern (1)
Vice President, Treasurer and
Chief Financial Officer
Age 52
Elected in 1995. Vice President, Treasurer and Chief Financial Officer since 2001. Previously served as Vice President, Secretary, Treasurer and Chief Financial Officer from 1995 to 2001.

Frances Turnage (2)
Comptroller
Age 56
Elected in 2005. Comptroller since 1993.

Gene L. Ussery, Jr. (3)
Vice President
Age 55
Elected in 2000. Vice President of Power Generation and Delivery since September 2000; 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. Southern was elected Senior Vice President, Comptroller and Chief Financial Officer of Southern Power, effective March 17, 2005, and has resigned from Mississippi Power effective as of such date.

(2) Ms. Turnage was elected Vice President, Treasurer and Chief Financial Officer, effective March 17, 2005.

(3) Mr. Ussery was elected Vice President of Georgia Power effective February 16, 2005, and has resigned from Mississippi Power effective March 5, 2005.

      The officers of Mississippi Power were elected for a term running from the last annual meeting of the directors (April 28, 2004) for one year until the next annual meeting or until their successors are elected and have qualified, except for Mr. Atherton whose election was effective January 1, 2005, Ms. Flowers whose election will be effective as shown above and Ms. Turnage whose election will be effective March 17, 2005.

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PART II

Item 5. MARKET FOR REGISTRANTS’ COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

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  
2004
               
First Quarter
  $ 30.87     $ 29.10  
Second Quarter
    30.59       27.86  
Third Quarter
    30.65       28.86  
Fourth Quarter
    33.92       29.95  
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  
 

       There is no market for the other registrants’ common stock, all of which is owned by Southern Company.

(b)   Number of Southern Company’s common stockholders of record at December 31, 2004:

     125,975

       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     2004     2003  
            (in thousands)  
Southern Company
  First   $ 257,506     $ 245,745  
 
  Second     258,318       247,324  
 
  Third     264,051       255,042  
 
  Fourth     264,859       256,334  
Alabama Power
  First     109,325       107,550  
 
  Second     109,325       107,550  
 
  Third     109,325       107,550  
 
  Fourth     109,325       107,550  
Georgia Power
  First     141,375       141,450  
 
  Second     141,375       141,450  
 
  Third     141,375       141,450  
 
  Fourth     141,375       141,450  
Gulf Power
  First     17,500       17,550  
 
  Second     17,500       17,550  
 
  Third     17,500       17,550  
 
  Fourth     17,500       17,550  
Mississippi Power
  First     16,550       16,500  
 
  Second     16,550       16,500  
 
  Third     16,550       16,500  
 
  Fourth     16,550       16,500  
Savannah Electric
  First     5,800       5,750  
 
  Second     5,800       5,750  
 
  Third     5,800       5,750  
 
  Fourth     5,800       5,750  
 

     In 2003 and 2004, Southern Power paid $77 million and $320 million, respectively, in dividends to Southern Company.

     The dividend paid per share of Southern Company’s common stock was 34.25¢ for the first and second quarters of 2003 and 35¢ for the third and fourth quarters of 2003 and the first two quarters of 2004 and 35.75¢ for the last two quarters of 2004.

     The amount of dividends on their common stock that may be paid by the subsidiary registrants (except Alabama

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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 under “Common Stock Dividend Restrictions,” “Dividend Restrictions,” “Dividend Restrictions” and “Common Stock Dividend Restrictions,” respectively, 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, 2004 were as follows:

                 
 
    Retained     Restricted  
    Earnings     Amount  
    (in millions)  
Alabama Power
  $ 1,341     $  
Georgia Power
    2,103        
Gulf Power
    160       127  
Mississippi Power
    216       118  
Savannah Electric
    108       68  
Southern Power
    122        
Consolidated
    5,839       313  
 
Item 6. SELECTED FINANCIAL DATA

Item 6.  SELECTED FINANCIAL DATA

     Southern Company. See “SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA,” contained herein at pages II-71 and II-72.

     Alabama Power. See “SELECTED FINANCIAL AND OPERATING DATA,” contained herein at pages II-119 and II-120.

     Georgia Power. See “SELECTED FINANCIAL AND OPERATING DATA,” contained herein at pages II-174 and II-175.

     Gulf Power. See “SELECTED FINANCIAL AND OPERATING DATA,” contained herein at pages II-220 and II-221.

     Mississippi Power. See “SELECTED FINANCIAL AND OPERATING DATA,” contained herein at pages II-266 and II-267.

     Savannah Electric. See “SELECTED FINANCIAL AND OPERATING DATA,” contained herein at pages II-314 and II-315.

     Southern Power. See “SELECTED FINANCIAL AND OPERATING DATA,” contained herein at page II-344.

Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION

Item 7.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION

     Southern Company. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION,” contained herein at pages II-11 through II-34.

     Alabama Power. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION,” contained herein at pages II-75 through II-92.

     Georgia Power. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION,” contained herein at pages II-123 through II-142.

     Gulf Power. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION,” contained herein at pages II-178 through II-195.

     Mississippi Power. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION,” contained herein at pages II-224 through II-240.

     Savannah Electric. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION,” contained herein at pages II-270 through II-286.

     Southern Power. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION,” contained herein at pages II-318 through II-329.

Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Item 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     See MANAGEMENT’S DISCUSSION AND ANALYSIS — FINANCIAL CONDITION AND LIQUIDITY – “Market Price Risk” of each of the registrants in Item 7 herein and Note 1 of each of the registrant’s financial statements in Item 8 herein under “Financial Instruments.” See also Note 6 to the financial statements of Southern Company and each retail operating company and Note 5 to the financial statements of Southern Power in Item 8 herein under “Financial Instruments.”

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Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Item 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO 2004 FINANCIAL STATEMENTS

         
    Page  
The Southern Company and Subsidiary Companies:
       
Management’s Report on Internal Control Over Financial Reporting
  II-8  
Reports of Independent Registered Public Accounting Firm -
       
Internal Control over Financial Reporting
  II-9  
Consolidated Financial Statements
  II-10
Consolidated Statements of Income for the Years Ended December 31, 2004, 2003, and 2002
  II-35
Consolidated Statements of Cash Flows for the Years Ended December 31, 2004, 2003, and 2002
  II-36
Consolidated Balance Sheets at December 31, 2004 and 2003
  II-37
Consolidated Statements of Capitalization at December 31, 2004 and 2003
  II-39
Consolidated Statements of Common Stockholders’ Equity for the Years Ended December 31, 2004, 2003, and 2002
  II-41
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2004, 2003, and 2002
  II-41
Notes to Financial Statements
  II-42
Alabama Power:
       
Report of Independent Registered Public Accounting Firm
  II-74
Statements of Income for the Years Ended December 31, 2004, 2003, and 2002
  II-93
Statements of Cash Flows for the Years Ended December 31, 2004, 2003, and 2002
  II-94
Balance Sheets at December 31, 2004 and 2003
  II-95
Statements of Capitalization at December 31, 2004 and 2003
  II-97
Statements of Common Stockholder’s Equity for the Years Ended December 31, 2004, 2003, and 2002
  II-99
Statements of Comprehensive Income for the Years Ended December 31, 2004, 2003, and 2002
  II-99
Notes to Financial Statements
  II-100
Georgia Power:
       
Report of Independent Registered Public Accounting Firm
  II-122
Statements of Income for the Years Ended December 31, 2004, 2003, and 2002
  II-143
Statements of Cash Flows for the Years Ended December 31, 2004, 2003, and 2002
  II-144
Balance Sheets at December 31, 2004 and 2003
  II-145
Statements of Capitalization at December 31, 2004 and 2003
  II-147
Statements of Common Stockholder’s Equity for the Years Ended December 31, 2004, 2003, and 2002
  II-148
Statements of Comprehensive Income for the Years Ended December 31, 2004, 2003, and 2002
  II-148
Notes to Financial Statements
  II-149
Gulf Power:
       
Report of Independent Registered Public Accounting Firm
  II-177
Statements of Income for the Years Ended December 31, 2004, 2003, and 2002
  II-196
Statements of Cash Flows for the Years Ended December 31, 2004, 2003, and 2002
  II-197
Balance Sheets at December 31, 2004 and 2003
  II-198
Statements of Capitalization at December 31, 2004 and 2003
  II-200
Statements of Common Stockholder’s Equity for the Years Ended December 31, 2004, 2003, and 2002
  II-201

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    Page  
Statements of Comprehensive Income for the Years Ended December 31, 2004, 2003, and 2002
  II-201
Notes to Financial Statements
  II-202
Mississippi Power:
       
Report of Independent Registered Public Accounting Firm
  II-223
Statements of Income for the Years Ended December 31, 2004, 2003, and 2002
  II-241
Statements of Cash Flows for the Years Ended December 31, 2004, 2003, and 2002
  II-242
Balance Sheets at December 31, 2004 and 2003
  II-243
Statements of Capitalization at December 31, 2004 and 2003
  II-245
Statements of Common Stockholder’s Equity for the Years Ended December 31, 2004, 2003, and 2002
  II-246
Statements of Comprehensive Income for the Years Ended December 31, 2004, 2003, and 2002
  II-246
Notes to Financial Statements
  II-247
Savannah Electric:
       
Report of Independent Registered Public Accounting Firm
  II-269
Statements of Income for the Years Ended December 31, 2004, 2003, and 2002
  II-287
Statements of Cash Flows for the Years Ended December 31, 2004, 2003, and 2002
  II-288
Balance Sheets at December 31, 2004 and 2003
  II-289
Statements of Capitalization at December 31, 2004 and 2003
  II-291
Statements of Common Stockholder’s Equity for the Years Ended December 31, 2004, 2003, and 2002
  II-292
Statements of Comprehensive Income for the Years Ended December 31, 2004, 2003, and 2002
  II-292
Notes to Financial Statements
  II-293
Southern Power:
       
Report of Independent Registered Public Accounting Firm
  II-317
Statements of Income for the Years Ended December 31, 2004, 2003, and 2002
  II-330
Statements of Cash Flows for the Years Ended December 31, 2004, 2003, and 2002
  II-331
Balance Sheets at December 31, 2004 and 2003
  II-332
Statements of Common Stockholder’s Equity for the Years Ended December 31, 2004, 2003, and 2002
  II-334
Statements of Comprehensive Income for the Years Ended December 31, 2004, 2003, and 2002
  II-334
Notes to Financial Statements
  II-335
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

Item 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

     None.

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Item 9A. CONTROLS AND PROCEDURES

Item 9A.  CONTROLS AND PROCEDURES

Disclosure Controls And Procedures.

Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power and Southern Power

     As of the end of the period covered by this annual report, Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power and Southern Power conducted separate evaluations under the supervision and with the participation of each company’s management, including the Chief Executive Officer and 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 these 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 their company (including its consolidated subsidiaries, if any) required to be included in periodic filings with the SEC.

Savannah Electric

     As of the end of the period covered by this annual report, Savannah Electric conducted an evaluation under the supervision and with the participation of its management, including the Chief Executive Officer and 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 this evaluation, the Chief Executive and Chief Financial Officer concluded that the disclosure controls and procedures were not effective in alerting them in a timely manner to material information relating to Savannah Electric required to be included in periodic filings with the SEC, because of an internal control weakness described below.

     In connection with the review and preparation of the financial statements of Savannah Electric for the year ended December 31, 2004, errors in Savannah Electric’s estimates of unbilled revenues for the years ended December 31, 2003 and 2002, and periods prior to 2002 were identified. The errors also affect Savannah Electric’s previously issued financial statements for the quarters ended March 31, June 30 and September 30, 2004 and 2003. Savannah Electric’s financial statements have been restated to reflect adjustments to Savannah Electric’s financial information previously reported. See Note 9 to the financial statements of Savannah Electric in Item 8 herein.

     Unbilled revenues represent an estimate of the kilowatt-hour sales of electricity delivered to customers, but not yet billed. Components of the unbilled revenue estimates include total kilowatt-hour territorial supply, total kilowatt-hours billed, total electricity lost in delivery (line losses) and customer usage. These components are affected by a number of factors including weather, generation patterns, power delivery volume and other operational constraints.

     The errors in Savannah Electric’s estimates were identified through comparisons of Savannah Electric’s unbilled revenue account balance at December 31, 2004 to the billed kilowatt-hour sales recorded in January 2005 made in connection with Savannah Electric’s 2004 audit. Savannah Electric analyzed the unbilled revenue calculations for the years 1999 through 2004 to determine the timing and source of the errors, which primarily relate to the estimates of line losses. For the years through 2002, line losses were understated and total unbilled revenues were overstated. However, in 2003, Savannah Electric revised its methodology of estimating line losses, which had the effect of overstating the line losses, and, thus, understating total unbilled revenues during 2003 and 2004. Since Savannah Electric’s calculation of unbilled revenues utilized a net change methodology, the cumulative effect of each of these errors was carried forward from period to period.

     Management believes Savannah Electric’s failure to identify these errors would constitute a material weakness in internal control over financial reporting under standards adopted by the Public Company Accounting Oversight Board. Deloitte & Touche LLP and the management of Savannah Electric discussed these adjustments and the internal control deficiency with Southern Company’s Audit Committee. Management has revised its process and controls related to estimating unbilled revenues to utilize a gross change methodology that reverses each period’s estimate in total in the following period.

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Internal Control Over Financial Reporting.

     (a) Management’s Annual Report on Internal Control Over Financial Reporting.

     (1) Southern Company

     Southern Company’s Management’s Report on Internal Control Over Financial Reporting is included on page II-8 of this Form 10-K.

     (2) Retail operating companies and Southern Power

     Not applicable because these companies are not accelerated filers.

     (b) Attestation Report of the Registered Public Accounting Firm.

     (1) Southern Company

     The report of Deloitte & Touche LLP, Southern Company’s independent registered public accounting firm, regarding management’s assessment of Southern Company’s internal control over financial reporting and the effectiveness of Southern Company’s internal control over financial reporting is included on page II-9 of this Form 10-K.

     (2) Retail operating companies and Southern Power

     Not applicable because these companies are not accelerated filers.

     (c) Changes in internal controls.

Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power and Southern Power

     There have been no changes in Southern Company’s, Alabama Power’s, Georgia Power’s, Gulf Power’s, Mississippi Power’s or Southern Power’s internal control 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 2004 that have materially affected or are reasonably likely to materially affect Southern Company’s, Alabama Power’s, Georgia Power’s, Gulf Power’s, Mississippi Power’s or Southern Power’s internal control over financial reporting.

Savannah Electric

     There have been no changes in Savannah Electric’s internal control 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 2004 that have materially affected or are reasonably likely to materially affect Savannah Electric’s internal control over financial reporting. However, as described above in this Item 9A under Savannah Electric’s “Disclosure Controls and Procedures,” Savannah Electric made changes to its process and controls related to estimating unbilled revenues during the first quarter of 2005.

Item 9B. OTHER INFORMATION

Item 9B.  OTHER INFORMATION

     None.

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THE SOUTHERN COMPANY

AND SUBSIDIARY COMPANIES
 
 
FINANCIAL SECTION
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

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MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Southern Company and Subsidiary Companies 2004 Annual Report

Southern Company’s management is responsible for establishing and maintaining an adequate system of internal control over financial reporting as required by the Sarbanes-Oxley Act of 2002 and as defined in Exchange Act Rule 13a-15(f). A control system can provide only reasonable, not absolute, assurance that the objectives of the control system are met.

     Under management’s supervision, an evaluation of the design and effectiveness of Southern Company’s internal control over financial reporting was conducted based on the framework in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation, management concluded that Southern Company’s internal control over financial reporting was effective as of December 31, 2004.

     Deloitte & Touche LLP, an independent registered public accounting firm, as auditors of Southern Company’s financial statements, has issued an attestation report on management’s assessment of the effectiveness of Southern Company’s internal control over financial reporting as of December 31, 2004. Deloitte & Touche LLP’s report, which expresses unqualified opinions on management’s assessment and on the effectiveness of Southern Company’s internal control over financial reporting, is included herein.

 

/s/ David M. Ratcliffe
David M. Ratcliffe
Chairman, President, and Chief Executive Officer

 

/s/ Thomas A. Fanning
Thomas A. Fanning
Executive Vice President, Chief Financial Officer,
and Treasurer

February 28, 2005

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Internal Control over Financial Reporting

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of Southern Company

We have audited management’s assessment, included in the accompanying Management Report (page II-8), that Southern Company (the “Company”) maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

     We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

     A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

     Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

     In our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

     We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2004 of the Company and our report dated February 28, 2005 expressed an unqualified opinion on those financial statements.

 

/s/ Deloitte & Touche LLP
Atlanta, Georgia
February 28, 2005

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Consolidated Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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 (the “Company”) as of December 31, 2004 and 2003, 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, 2004. 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 the standards of the Public Company Accounting Oversight Board (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-35 to II-70) present fairly, in all material respects, the financial position of Southern Company and Subsidiary Companies at December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.

     As discussed in Note 1 to the financial statements, in 2003 the Southern Company changed its method of accounting for asset retirement obligations.

     We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 28, 2005 expressed an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reporting and an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

 

/s/ Deloitte & Touche LLP
Atlanta, Georgia
February 28, 2005

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION
Southern Company and Subsidiary Companies 2004 Annual Report

OVERVIEW

Business Activities

Southern Company’s primary business is 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.

     Many factors affect the opportunities, challenges, and risks of Southern Company’s electricity business. 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 more stringent environmental standards. In 2004, Alabama Power, Georgia Power, and Mississippi Power each completed retail rate proceedings that should help provide future earnings stability. These regulatory actions will also enable the recovery of substantial capital investments to facilitate the continued reliability of the transmission and distribution network and to continue environmental improvements at the generating plants. Appropriately balancing environmental expenditures with customer prices will continue to challenge the Company for the foreseeable future.

     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. Southern Power continued executing its regional strategy in 2004 by signing several wholesale contracts with major utilities, as well as with cooperatives and municipal suppliers in the Southeast. Southern Company’s average wholesale contract now extends more than 13 years, with the average Southern Power market-based contract extending more than 11 years. These contracts reduce remarketing risk until the middle of the next decade. However, the Company continues to face regulatory challenges related to transmission and market power issues at the national level.

     Southern Company’s other business activities include investments in synthetic fuels and leveraged lease projects, telecommunications, energy-related services, and natural gas marketing. Management continues to evaluate the contribution by each of these activities to total shareholder return and may pursue acquisitions and dispositions accordingly.

Key Performance Indicators

In striving to maximize shareholder value while providing low-cost energy to more than 4 million customers, Southern Company focuses on several key indicators. These indicators include customer satisfaction, peak season equivalent forced outage rate (Peak Season EFOR), return on equity (ROE), and earnings per share (EPS). Southern Company’s financial success is directly tied to the satisfaction of its customers. Key elements of ensuring customer satisfaction include outstanding service, high reliability, and competitive prices. Management uses nationally recognized customer satisfaction surveys and reliability indicators to evaluate the Company’s results. Peak Season EFOR is an indicator of plant availability and efficient generation fleet operations during the months when generation needs are greatest. The rate is calculated by dividing the number of hours of forced outages by total generation hours. ROE is a performance standard used by both the investment community and many regulatory agencies. EPS is a major component of the Company’s efforts to increase returns to shareholders through dividend growth. Southern Company’s 2004 results compared with its targets for each of these indicators are reflected in the following chart.

             
Key     2004     2004
Performance     Target     Actual
Indicator     Performance     Performance
Customer     Top quartile     Top quartile
Satisfaction     in national      
      and regional      
      surveys      
             
Peak Season EFOR
    3.00% or less     1.22%
             
ROE
    14.5%     15.4%
             
EPS
    $1.94 - $1.99     $2.07

     See RESULTS OF OPERATIONS herein for additional information on the Company’s financial performance. The strong financial performance achieved in 2004 reflects the focus that management places on these indicators as well as the commitment shown by employees in achieving or exceeding management’s expectations.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2004 Annual Report

Earnings

Southern Company’s financial performance in 2004 was the Company’s best ever and again a leader in the electric utility industry. Net income of $1.53 billion in 2004 increased 3.9 percent over the prior year. Net income was $1.47 billion in 2003 and $1.32 billion in 2002, reflecting increases over the prior year of 11.8 percent and 17.6 percent, respectively. Basic EPS was $2.07 in 2004, $2.03 in 2003, and $1.86 in 2002. Dilution — which factors in additional shares related to stock options — decreased EPS by 1 cent each year.

Dividends

Southern Company has paid dividends on its common stock since 1948. Dividends paid per share on common stock were $1.415 in 2004, $1.385 in 2003, and $1.355 in 2002. In January 2005, Southern Company declared a quarterly dividend of 35.75 cents per share. This is the 229th 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 to achieve and maintain a payout of 70 percent of net income. The actual payout ratio was 68.2 percent for 2004.

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 electricity business is as follows:

                                 
            Increase (Decrease)  
    Amount     from Prior Year  
    2004     2004     2003     2002  
    (in millions)  
Electric operating revenues
  $ 11,465     $ 718     $ 541     $ 291  
 
Fuel
    3,395       397       212       209  
Purchased power
    643       170       24       (269 )
Other operation and maintenance
    3,008       150       106       253  
Depreciation and amortization
    908       (64 )     (16 )     (155 )
Taxes other than income taxes
    624       40       29       22  
 
Total electric operating expenses
    8,578       693       355       60  
 
Operating income
    2,887       25       186       231  
Other income, net
    23       21       20       (41 )
Interest expenses
    614       19       10       (24 )
Income taxes
    875       30       68       75  
 
Net income
  $ 1,421     $ (3 )   $ 128     $ 139  
 

Revenues

Details of electric operating revenues are as follows:

                         
    2004     2003     2002  
    (in millions)  
Retail — prior year
  $ 8,875     $ 8,728     $ 8,440  
Change in —
                       
Base rates
    41       75       33  
Sales growth
    216       104       98  
Weather
    48       (135 )     158  
Fuel and other cost recovery clauses
    552       103       (1 )
 
Retail — current year
    9,732       8,875       8,728  
 
Sales for resale —
                       
Within service area
    504       444       443  
Outside service area
    837       914       725  
 
Total sales for resale
    1,341       1,358       1,168  
 
Other electric operating revenues
    392       514       310  
 
Electric operating revenues
  $ 11,465     $ 10,747     $ 10,206  
 
Percent change
    6.7 %     5.3 %     2.9 %
 

     Retail revenues increased $857 million in 2004, $147 million in 2003, and $288 million in 2002. The significant factors driving these changes are shown in the preceding table. Electric rates for the retail operating companies include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased energy costs. Under these provisions, fuel revenues generally equal fuel expenses — including the fuel component of purchased energy — and do not affect net income. Certain of the retail operating companies also have clauses to recover other costs, such as environmental and new plant additions.

     Sales for resale revenues within the service area increased $60 million in 2004 due to continued customer growth in the Southeast and new contracts with utilities within the service area. Sales for resale were flat in 2003 and increased $104 million in 2002, primarily as a result of hotter than normal weather.

     Revenues from energy sales for resale outside the service area decreased $77 million in 2004 and increased $189 million in 2003. 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 types of sales. Neighboring utilities that depend heavily on gas-

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2004 Annual Report

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 2004, however, coal prices also increased, resulting in a lower marginal price differential that reduced demand. In addition, mild summer weather throughout the Southeast also reduced demand. In 2003, Southern Company entered into several new contracts with neighboring utilities. In addition, milder weather in Southern Company’s service territory, compared with the rest of the Southeast and combined with higher gas prices, resulted in increases in both customer demand and available generation. In 2002, revenues from energy sales for resale outside the service area were down $111 million from 2001, resulting from the expiration of certain short-term energy sales contracts.

     Southern Company’s average wholesale contract now extends more than 13 years. As a result, the Company has significantly reduced its remarketing risk until the middle of the next decade. Under unit power sales contracts, principally sales to Florida utilities, 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:

                         
    2004     2003     2002  
    (in millions)  
Unit power —
                       
Capacity
  $ 185     $ 182     $ 175  
Energy
    213       211       198  
Other long term —
                       
Capacity
    78       76       73  
Energy
    361       445       279  
 
Total
  $ 837     $ 914     $ 725  
 

     In May 2003, Mississippi Power and Southern Power entered into agreements with Dynegy, Inc. (Dynegy) that terminated all capacity sales contracts with subsidiaries of Dynegy. The termination payments from Dynegy resulted in an increase in other electric revenues of $135 million in 2003.

Energy Sales

Changes in revenues are influenced heavily by the volume of energy sold each year. Kilowatt-hour sales for 2004 and the percent change by year were as follows:

                                 
(billions of   Amount     Percent Change  
kilowatt-hours)   2004     2004     2003     2002  
 
Residential
    49.7       3.9 %     (1.9 )%     9.5 %
Commercial
    50.0       3.4       0.3       2.8  
Industrial
    56.4       3.6       1.0       1.8  
Other
    1.0       0.8       (0.2 )     2.3  
 
Total retail
    157.1       3.6       (0.2 )     4.5  
Sales for resale —
                               
Within service area
    11.4       6.6       (1.3 )     15.6  
Outside service area
    23.9       (20.1 )     37.4       1.5  
 
Total
    192.4       0.1       4.2       4.7  
 

     Energy sales in 2004 were strong across all retail customer classes as a result of an improved economy in the Southeast and customer growth of 1.5 percent. Residential energy sales in 2003 reflected a decrease in customer demand as a result of very mild weather partially offset by customer growth of 1.6 percent. In 2003, 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. Energy sales to retail customers are projected to increase at an average annual rate of 1.88 percent during the period 2005 through 2010.

     Sales to customers outside the service area under contracts and opportunity sales decreased by 6.0 billion kilowatt-hours in 2004, increased by 8.1 billion kilowatt-hours in 2003, and were flat in 2002. The decrease in 2004 as compared with 2003 is due to the increased availability of coal-fired generation in 2003 resulting from weather-related lower retail demand coupled with higher natural gas prices, which increased the wholesale market demand for opportunity sales. Unit power energy sales increased 1.9 percent in 2004 and 4.0 percent in 2003 and decreased 3.3 percent in 2002. Fluctuations in oil and natural gas prices, which are the primary fuel sources for unit power sales customers, influence changes in these sales. However, these fluctuations in energy sales under long-term contracts have a minimal effect on earnings because the energy is generally sold at variable cost.

Electric Operating Expenses

Electric operating expenses in 2004 were $8.6 billion, an increase of $693 million over 2003 expenses. Production costs, including fuel and purchased power expenses, exceeded the prior year by $624 million as a result of increased sales, a 12.7 percent increase in the

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2004 Annual Report

average unit cost of fuel, and maintenance costs that were deferred from 2003. Non-production operation and maintenance costs increased by $93 million due to additional administrative and general expenses of $106 million, primarily related to employee benefits, nuclear security, and property insurance, as well as increased transmission and distribution expenses of $49 million primarily related to expenditures that were deferred from 2003. These increases were partially offset by a $60 million regulatory liability related to Plant Daniel that was expensed in 2003. Depreciation and amortization expenses declined by $64 million in 2004, primarily as a result of amortization of the Plant Daniel regulatory liability and a Georgia Power regulatory liability related to the levelization of certain purchased power costs that reduced amortization expense by $17 million and $90 million, respectively, from the prior year. See FUTURE EARNINGS POTENTIAL - “FERC and State PSC Matters — Mississippi Power Retail Rate Filing” herein and Note 3 to the financial statements under “Georgia Power Retail Rate Activity” for more information on these regulatory adjustments. These reductions were partially offset by a higher depreciable plant base. Taxes other than income taxes increased $40 million as a result of additional plant in service and a higher property tax base.

     In 2003, electric operating expenses were $7.9 billion, an increase of $355 million over 2002 expenses. Production costs exceeded the prior year by $209 million as a result of increased sales and a 5.1 percent increase in the average unit cost of fuel. Non-production operation and maintenance costs increased by $133 million over the prior year. This increase in expenses was primarily driven by additional administrative and general expenses of $46 million, primarily due to higher property insurance and employee benefits, customer service expenses of $14 million, and the $60 million Plant Daniel regulatory liability discussed previously. Taxes other than income taxes increased $29 million in 2003 as a result of additional generating facilities and a higher property tax base. The $16 million decrease in depreciation and amortization in 2003 was primarily due to a $49 million reduction in amortization of the previously discussed Georgia Power purchased power regulatory liability and was partially offset by a higher depreciable plant base.

     In 2002, electric operating expenses were $7.5 billion, an increase of $60 million over 2001 expenses. Production costs exceeded 2001 costs by $87 million as a result of increased sales. Non-production operation and maintenance costs also increased in 2002 by $106 million due to additional administrative and general expenses of $56 million and transmission and distribution expenses of $37 million. Taxes other than income taxes increased $22 million in 2002 due to higher property taxes related to commercial operation of new generating plants. 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.

Fuel and Purchased Power Expenses

Fuel costs constitute the single largest expense for the 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:

                         
    2004     2003     2002  
Total generation
(billions of kilowatt-hours)
    188       189       183  
Sources of generation
(percent) —
                       
Coal
    69       71       69  
Nuclear
    16       16       16  
Gas
    12       9       12  
Hydro
    3       4       3  
Average cost of fuel per net kilowatt-hour generated
(cents)
    1.87       1.66       1.58  
Average cost of purchased power per net kilowatt-hour
(cents)
    4.48       3.86       4.17  
 

     Fuel and purchased power expenses were $4.0 billion in 2004, an increase of $567 million or 16.3 percent above 2003 costs. This increase was attributed to higher average unit fuel cost.

     Fuel and purchased power expenses were $3.5 billion in 2003, an increase of $236 million or 7.3 percent above the prior year costs. This increase was primarily attributed to higher average 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 expenses were $3.2 billion, a decrease of $60 million or 1.8 percent below the prior year costs. An additional 8.9

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2004 Annual Report

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.

     A significant upward trend in the cost of coal and natural gas has emerged since 2003, and volatility in these markets is expected to continue. Increased coal prices have been influenced by a worldwide increase in demand as a result of rapid economic growth in China as well as by increases in mining costs. Higher natural gas prices in the United States are the result of slightly lower gas supplies despite increased drilling activity. Natural gas supply interruptions, such as those caused by the 2004 hurricanes, result in an immediate market response, however, the impact of this price volatility may be reduced by imports of natural gas and liquefied natural gas. Fuel expenses generally do not affect net income, since they are offset by fuel revenues under the retail operating companies’ fuel cost recovery provisions. Likewise, Southern Power’s purchase power agreements (PPAs) generally provide that the purchasers are responsible for substantially all of the cost of fuel.

Electric Other Income and (Expense)

Total interest charges and other financing costs increased by $19 million in 2004 as a result of a lower percentage of interest costs capitalized as Southern Power projects reached completion in 2003. This increase was partially offset by the refinancing of higher cost debt at the retail operating companies in 2003. Total interest charges and other financing costs declined by $24 million in 2002 as a result of 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-related 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 various energy-related projects, including synthetic fuels and leveraged lease projects that receive tax benefits, which contribute significantly to the economic results of these investments; SouthernLINC Wireless 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 GAS is a retail gas marketer serving customers in the State of Georgia.

     A condensed income statement for Southern Company’s other business activities follows:

                                 
            Increase (Decrease)  
    Amount     from Prior Year  
    2004     2004     2003     2002  
    (in millions)  
Operating revenues
  $ 437     $ (2 )   $ 131     $ 68  
 
Operation and maintenance
    447       8       98       79  
Depreciation and amortization
    47       (8 )     (4 )     29  
Taxes other than income taxes
    3       1              
 
Total operating expenses
    497       1       94       108  
 
Operating income
    (60 )     (3 )     37       (40 )
Equity in losses of unconsolidated subsidiaries
    (97 )     (2 )     (3 )     (31 )
Leveraged lease income
    70       4       8       (1 )
Other income, net
    (7 )     (14 )     7       (10 )
Interest expenses
    83       (21 )     5       (36 )
Income taxes
    (288 )     (55 )     16       (105 )
 
Net income
  $ 111     $ 61     $ 28     $ 59  
 

     Southern Company’s non-electric revenues were flat in 2004 and increased $131 million in 2003 and $68 million in 2002. The increases are primarily the result of Southern Company GAS beginning operations in August 2002 and increasing its revenues $5 million in 2004 and $101 million in 2003. SouthernLINC Wireless revenues also increased $6 million, $8 million, and $32 million in 2004, 2003, and 2002, respectively, as a result of increased wireless subscribers. A decrease in operating revenues in the energy-related services business offset the 2004 increases. Revenues from a subsidiary that primarily provides fuel transportation services related to synthetic fuel products were $115 million in 2004, increasing by $21 million, $37 million, and $26 million in 2004, 2003 and 2002, respectively, as a result of increased production at the synthetic fuel facilities. Most of these service revenues are ultimately included in the cost of the synthetic fuel purchased by Alabama Power and

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2004 Annual Report

Georgia Power and, therefore, have no significant effect on consolidated revenues. See Note 1 to the financial statements under “Related Party Transactions” for additional information.

     Operation and maintenance expenses for these other businesses increased by $8 million in 2004 when compared with the prior year as a result of a $12.6 million bad debt reserve related to additional federal income taxes and interest Southern Company paid on behalf of Mirant. See FUTURE EARNINGS POTENTIAL — “Other Matters — Mirant Related Matters” herein and Note 3 to the financial statements under “Mirant Related Matters — Mirant Bankruptcy” for additional information. The more significant increases in 2004 and 2003 were primarily driven by Southern Company GAS increases in purchased gas expenses of $3 million and $78 million, respectively, following the inception of its operations in August 2002. In 2002, expenses also increased $19 million as a result of additional SouthernLINC Wireless subscribers and $30 million as a result of increased production at the synthetic fuel facilities.

     The increase in depreciation expense in 2002 reflects a $16 million charge related to the impairment of assets under certain customer contracts for energy-related services as well as the impact of property additions at SouthernLINC Wireless.

     The increases in equity in losses of unconsolidated subsidiaries in 2002 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 $146 million in 2004, $120 million in 2003, and $108 million in 2002. Additionally in 2004, a $37 million reserve related to these tax credits was reversed following the settlement of an Internal Revenue Service (IRS) audit. See FUTURE EARNINGS POTENTIAL — “Income Tax Matters — Synthetic Fuel Tax Credits” herein and Note 3 to the financial statements under “Income Tax Matters — Synthetic Fuel Tax Credits” for additional information.

     The decrease in other income in 2004 as compared with 2003 reflects a $15 million gain for a Southern Telecom contract settlement during 2003. The gain in 2003 was partially offset by an increase of $7 million in charitable contributions above the amount in 2002 made by the parent company.

     Interest expenses for 2004 decreased $21 million as a result of the parent company’s redemption of preferred securities in 2003. This decrease was partially offset by an increase in outstanding long-term debt in 2004. Interest expense in 2002 reflects lower interest rates and reduced amounts of debt outstanding for the parent company.

Effects of Inflation

The retail operating companies and Southern Power are subject to rate regulation and are party to long-term contracts, respectively, that are based on the recovery of historical costs. In addition, the income tax laws are based on historical costs. Therefore, inflation creates an economic loss because the Company is recovering its 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 retail operating companies operate as vertically integrated companies providing electricity to customers within their service areas in the southeastern United States. Prices for electricity provided to retail customers are set by state public service commissions (PSC) under cost-based regulatory principles. Retail rates and earnings are reviewed and adjusted periodically within certain limitations based on ROE. See ACCOUNTING POLICIES — “Application of Critical Accounting Policies and Estimates — Electric Utility Regulation” herein and Note 3 to the financial statements for additional information about these and other regulatory matters.

     The results of operations for the past three years are not necessarily indicative of future earnings potential. The level of Southern Company’s future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Southern

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Southern Company and Subsidiary Companies 2004 Annual Report

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 more stringent 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.

     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 has constructed new generating capacity only 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.

     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 in the U.S. District Court for the Northern District of Georgia against certain Southern Company subsidiaries, including Alabama Power and Georgia Power, alleging that these subsidiaries had violated the New Source Review (NSR) provisions of the Clean Air Act and related state laws at five coal-fired generating facilities. Through subsequent amendments and other legal procedures, the EPA added Savannah Electric as a defendant to the original action and added allegations regarding two additional generating facilities owned by Alabama Power. 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 were effectively stayed in the spring of 2001 pending the appeal of a similar NSR action against the Tennessee Valley Authority before the U.S. Court of Appeals for the Eleventh Circuit. In June 2004, following the final resolution of that appeal, the U.S. District Court for the Northern District of Alabama lifted the stay in the action against Alabama Power, placing the case back onto the court’s active docket. At this time, no party to the case against Georgia Power and Savannah Electric has sought to reopen that case, which remains administratively closed in the U.S. District Court for the Northern District of Georgia. See Note 3 to the financial statements under “Environmental Matters —  New Source Review Actions” for additional information.

     Southern Company believes that the retail operating companies complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $32,500 per day, per violation at each generating unit, depending on the date of the alleged violation. 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

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financial condition if such costs are not recovered through regulated rates.

     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 (RMRR) exclusion. A coalition of states and environmental organizations has filed petitions for review of these revisions with the U.S. Court of Appeals for the District of Columbia Circuit. The October 2003 RMRR rules have been stayed by the Court of Appeals pending its review of the rules. In any event, the final regulations must also be adopted by the individual states to apply to facilities in the Southern Company system. The effect of these final regulations, related legal challenges, and potential state rulemakings cannot be determined at this time.

Carbon Dioxide Litigation

On July 21, 2004, attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel for New York City filed a complaint in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. A nearly identical complaint was filed by three environmental groups in the same court. The complaints allege that the companies’ emissions of carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs assert is a public nuisance. Under common law public and private nuisance theories, the plaintiffs seek a judicial order (1) holding each defendant jointly and severally liable for creating, contributing to, and/or maintaining global warming and (2) requiring each of the defendants to cap its emissions of carbon dioxide and then reduce those emissions by a specified percentage each year for at least a decade. Plaintiffs have not, however, requested that damages be awarded in connection with their claims. Southern Company believes these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. Southern Company and the other defendants have filed motions to dismiss both lawsuits. Southern Company intends to vigorously defend against these claims. While the outcome of these matters cannot be determined at this time, an adverse judgment in either of these actions could result in substantial capital expenditures.

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 for the Northern District of 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 liability phase of the case has concluded with the court ruling in favor of Georgia Power in part and the plaintiffs in part. Georgia Power has filed a petition for review of the decision with the U.S. Court of Appeals for the Eleventh Circuit. The district court case has been administratively closed pending that appeal. If necessary, the district court will hold a separate trial which will address civil penalties and possible injunctive relief requested by the plaintiffs. See Note 3 to the financial statements under “Environmental Matters — Plant Wansley Environmental Litigation” for additional information. The ultimate outcome of this matter cannot currently be determined; however, an adverse outcome could require substantial capital expenditures that cannot be determined at this time and could possibly require the 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

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 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 discussed under FINANCIAL CONDITION AND LIQUIDITY — “Capital Requirements and Contractual Obligations” herein. There is no assurance, however, that all such costs will, in fact, be recovered.

     Compliance with the 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

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nitrogen oxide emissions and resulted in total construction expenditures of approximately $400 million through 2000. Some of these previous 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, 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 totaled approximately $1.1 billion through 2004 with an additional $500 million committed through 2007 for these two states. These expenditures include costs associated with the regional nitrogen oxide reduction rules discussed below. See Note 3 to the financial statements under “Alabama Power Retail Regulatory Matters” for information regarding Alabama Power’s recovery of costs associated with environmental laws and regulations.

     In addition, 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 in 2006 at a cost of approximately $138 million, of which $44 million remains to be spent. Gulf Power’s costs have been approved under its environmental cost recovery clause. See Note 1 to the financial statements under “Environmental Cost Recovery” for additional information.

     To help 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, were required to comply with the reduction requirements by May 31, 2004. However, as a result of litigation challenging the rule, the courts required the EPA to complete a separate rulemaking before the requirements could be applied in Georgia. In April 2004, the EPA published final regional nitrogen oxide reduction rules applicable to Georgia, specifying a May 1, 2007 compliance date. However, in October 2004, the EPA announced that it would stay implementation of the rule as it relates to Georgia, while it initiates rulemakings to address issues raised in a petition for reconsideration filed by a coalition of Georgia industries. The impact of the nitrogen oxide reduction rules will depend on the outcome of the petition for reconsideration and/or any subsequent development and approval of Georgia’s state implementation plan and cannot be determined at this time.

     In March 2004, the EPA redesignated the Birmingham, Alabama, area from nonattainment to attainment under the one-hour ozone standard. In addition, in September 2003 the EPA reclassified the Atlanta area from a “serious” to a “severe” nonattainment area for the one-hour standard effective January 1, 2004. However, based on the last three years of data, the State of Georgia believes that the Atlanta area has attained the one-hour standard and is in the process of applying for redesignation from the EPA.

     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 and included development of an eight-hour ozone standard, as opposed to the previous one-hour ozone standard. 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. On April 30, 2004, the EPA published its eight-hour ozone nonattainment designations and a portion of the rules implementing the new eight-hour ozone standard. Areas within the Southern Company’s service area that have been designated as nonattainment under the eight-hour ozone standard include Birmingham, Macon (Georgia), and a 20-county area within metropolitan Atlanta. Under the implementation provisions of the new rule, the EPA announced that the one-hour ozone standard will be revoked on June 15, 2005 and that areas classified as “severe” nonattainment areas under the one-hour standard, such as Atlanta, will not be required to impose emissions fees if those areas fail to come into attainment with the one-hour standard. With respect to the eight-hour nonattainment areas, state implementation plans, including new emission control regulations necessary to bring those areas

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into attainment, could be required as early as 2007. These state implementation plans could require reductions in nitrogen oxide emissions from power plants. The impact of the eight-hour designations and the new standard will depend on the development and implementation of applicable state implementation plans and therefore cannot be determined at this time.

     On December 17, 2004, the EPA issued its final “nonattainment” designations for the fine particulate national ambient air quality standard. Several areas within Southern Company’s service area in Alabama and Georgia were included in the EPA’s final particulate matter designations. The EPA plans to propose a fine particulate matter implementation rule in 2005 and finalize the implementation rule in 2006. State implementation plans addressing the nonattainment designations may be required by 2008 and could require reductions in sulfur dioxide emissions and further reductions in nitrogen oxide emissions from power plants. The impact of the fine particulate designations will depend on the development and implementation of applicable state implementation plans and therefore cannot be determined at this time.

     In January 2004, the EPA issued a proposed Clean Air Interstate Rule (CAIR) 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 in 2005. If finalized, the rule could modify or supplant other state requirements for attainment of the fine particulate matter standard and the eight-hour ozone standard, as well as other air quality regulations. 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.

     The Company has developed and maintains an environmental compliance strategy for the installation of additional control technologies and the purchase of emission allowances to assure continued compliance with current sulfur dioxide and nitrogen oxide emission regulations. Additional expenses associated with these regulations are anticipated to be incurred each year to maintain current and future compliance. Because the Company’s compliance strategy is impacted by factors such as changes to existing environmental laws and regulations, increases in the cost of emissions allowances, and any changes in the Company’s fuel mix, future environmental compliance costs 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 and to implement emission reduction requirements that make progress toward remedying current visibility impairment in certain natural areas. 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 implementation plans in 2008 that contain emission reduction strategies for implementing BART and for achieving sufficient progress toward the Clean Air Act’s visibility improvement goal. In response to litigation, the EPA proposed revised rules in May 2004, which it plans to finalize in April 2005. The impact of these regulations will depend on the promulgation of final rules and implementation of those rules by the states, and, therefore, it is not possible to determine the effect of these rules on the Company at this time.

     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 March 2005, and compliance could be required as early as 2008. Because the regulations have not been finalized, the impact on the Company cannot be determined at this time.

     Major bills to amend the Clean Air Act to impose more stringent emissions limitations on power plants, including the Bush Administration’s Clear Skies Act, have been re-proposed in 2005. The Clear Skies Act is expected to further limit power plant emissions of sulfur dioxide, nitrogen oxides, and mercury and to supplement the proposed CAIR and mercury regulatory programs. Other proposals to limit emissions of carbon dioxide have also been introduced. The cost impacts of such legislation would depend upon the specific requirements enacted and cannot be determined at this time.

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     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. In July 2004, the EPA published final rules that 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 and the actual limits established by the regulatory agencies.

     Georgia Power is installing cooling towers at additional facilities under the Clean Water Act to cool water prior to discharge. Near Atlanta, a cooling tower for one plant was completed in 2004 with two others scheduled for completion in 2008. The total estimated cost of these projects is $248 million, with $170 million remaining to be spent. Also, Georgia Power is conducting a study of the aquatic environment at another facility to determine if further thermal controls are necessary at that plant.

     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 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.

Global Climate Issues

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 constraints on the emissions of greenhouse gases for a group of industrialized countries. The Bush Administration has not supported U.S. ratification of the Kyoto Protocol or other mandatory carbon dioxide reduction legislation and, in 2002, announced a goal to reduce the greenhouse gas intensity of the U.S. — the ratio of greenhouse gas emissions to the value of U.S. economic output — by 18 percent by 2012. A year later, the Department of Energy (DOE) announced the Climate VISION program to support this goal. Energy-intensive industries, including electricity generation, are the initial focus of this program. Southern Company is leading the development of a voluntary electric utility sector climate change initiative in partnership with the government. The utility sector has pledged to reduce its greenhouse gas emissions rate by 3 to 5 percent over the next decade and, on December 13, 2004, signed a memorandum of understanding with the DOE initiating this program under Climate VISION. Because efforts under this voluntary program are just beginning, the impact of this program on the Company cannot be determined at this time.

Environmental Remediation Reserves

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 retail operating companies could incur substantial costs to clean up properties. The retail operating companies 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 retail operating companies 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 “Environmental Matters — Environmental Remediation” for additional information.

     In September 2004, Gulf Power increased its estimated liability for the estimated costs of environmental remediation projects by approximately $47 million. This increase relates to new regulations and more stringent site closure criteria by the Florida Department of Environmental Protection (FDEP) for impacts to soil and groundwater from herbicide applications at Gulf Power substations. The schedule for completion of the remediation projects will be subject to FDEP approval. The projects have been approved by the Florida PSC for recovery, as expended, through Gulf Power’s environmental cost recovery clause; therefore, there was no impact on Gulf Power’s net income as a result of these revised estimates.

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     Under Georgia PSC ratemaking provisions, $22 million has been deferred in a regulatory liability account for use in meeting future environmental remediation costs of Georgia Power. Under the December 2004 three-year retail rate plan ending December 31, 2007 (2004 Retail Rate Plan), this regulatory liability will be amortized over a three-year period beginning January 1, 2005. However, the order also approved an annual environmental accrual of $5.4 million. Environmental remediation expenditures will be charged against the reserve as they are incurred. The annual accrual amount will be reviewed and adjusted in future regulatory proceedings.

FERC and State PSC Matters

Transmission

In December 1999, the Federal Energy Regulatory Commission (FERC) issued its final rule on Regional Transmission Organizations (RTOs). Since that time, there have been a number of additional proceedings at the FERC designed to encourage further voluntary formation of RTOs or to mandate their formation. However, at the current time, there are no active proceedings that would require Southern Company to participate in an RTO. Current FERC efforts that may potentially change the regulatory and/or operational structure of transmission include rules related to the standardization of generation interconnection, as well as an inquiry into, among other things, market power by vertically integrated utilities. See “Generation Interconnection Agreements” and “Market-Based Rate Authority” below for additional information. The final outcome of these proceedings cannot now be determined. However, Southern Company’s financial condition, results of operations, and cash flows could be adversely affected by future changes in the federal regulatory or operational structure of transmission.

Generation Interconnection Agreements

In July 2003, the FERC issued its final rule on the standardization of generation interconnection agreements and procedures (Order 2003). Order 2003 shifts much of the financial burden of new transmission investment from the generator to the transmission provider. The FERC has indicated that Order 2003, which was effective January 20, 2004, is to be applied prospectively to interconnection agreements. Subsidiaries of Tenaska, Inc., as counterparties to three previously executed interconnection agreements with subsidiaries of Southern Company, have filed complaints at the FERC requesting that the FERC modify the agreements and that Southern Company refund a total of $19 million previously paid for interconnection facilities, with interest. Southern Company has also received similar requests from other entities totaling $9 million. Southern Company has opposed such relief, and the proceedings are still pending. The impact of Order 2003 and its subsequent rehearings on Southern Company and the final results of these matters cannot be determined at this time.

Market-Based Rate Authority

Each of the retail operating companies and Southern Power has authorization from the FERC to sell power to nonaffiliates at market-based prices. The retail operating companies and Southern Power 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, the retail operating companies, and Southern Power, and found Southern Company and others to be “pivotal suppliers” in their retail service territories 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. In April 2004, the FERC issued an order that abandoned the SMA test and adopted a new interim analysis for measuring generation market power. This new interim approach requires utilities to submit a pivotal supplier screen and a wholesale market share screen. If the applicant does not pass both screens, there will be a rebuttable presumption regarding generation market power. The FERC’s order also sets forth procedures for rebutting these presumptions and addresses mitigation measures for those entities that are found to have market power. In the absence of specific mitigation measures, the order includes several cost-based mitigation measures that would apply by default. The FERC also initiated a new rulemaking proceeding that, among other things, will adopt a final methodology for assessing generation market power.

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     In July 2004, the FERC denied Southern Company’s request for rehearing, along with a number of others, and reaffirmed the interim tests that it adopted in April 2004. In August 2004, Southern Company submitted a filing to the FERC that included results showing that Southern Company passed the pivotal supplier screen for all markets and the wholesale market share screen for all markets except the Southern Company retail service territory. Southern Company also submitted other analyses to demonstrate that it lacks generation market power. On December 17, 2004, the FERC initiated a proceeding to assess Southern Company’s generation dominance within its retail service territory. The ability to charge market-based rates in other markets is not at issue. As directed by this order, on February 15, 2005, Southern Company submitted additional information related to generation dominance in its retail service territory. Any new market-based rate transactions in its retail service territory entered into after February 27, 2005 will be subject to refund to the level of the default cost-based rates, pending the outcome of the proceeding. Southern Company, along with other utilities, has also filed an appeal of the FERC’s April and July 2004 orders with the U.S. Court of Appeals for the District of Columbia Circuit. The FERC has asked the court to dismiss the appeal on the grounds that it is premature.

     In the event that the FERC’s default mitigation measures are ultimately applied, Southern Power and the retail operating companies may be required to charge cost-based rates for certain wholesale sales in the retail service territory, which may be lower than negotiated market-based rates. The final outcome of this matter will depend on the form in which the final methodology for assessing generation market power and mitigation rules may be ultimately adopted and cannot be determined at this time.

Georgia Power Retail Rate Case

On December 21, 2004, the Georgia PSC approved the 2004 Retail Rate Plan for Georgia Power. Under the terms of the 2004 Retail Rate Plan, earnings will be evaluated against a retail ROE range of 10.25 percent to 12.25 percent. Two-thirds of any earnings above 12.25 percent will be applied to rate refunds, with the remaining one-third retained by Georgia Power. Retail rates and customer fees were increased by approximately $203 million effective January 1, 2005 to cover the higher costs of purchased power, operating and maintenance expenses, environmental compliance, and continued investment in new generation, transmission, and distribution facilities to support growth and ensure reliability.

     Georgia Power will not file for a general base rate increase unless its projected retail return on common equity falls below 10.25 percent. Georgia Power is required to file a general rate case by July 1, 2007, in response to which the Georgia PSC would be expected to determine whether the 2004 Retail Rate Plan should be continued, modified, or discontinued. See Note 3 to the financial statements under “Georgia Power Retail Rate Activity” for additional information.

Alabama Power Environmental Rate Filing

On October 5, 2004, the Alabama PSC approved a specific rate mechanism for the recovery of Alabama Power’s retail costs associated with environmental laws, regulations, or other such mandates. The rate mechanism began operation in January 2005 and provides for the recovery of these costs pursuant to a factor that will be calculated annually. Environmental costs to be recovered include operation and maintenance expenses, depreciation, and a return on invested capital. Retail rates have increased 1 percent in 2005, which should yield an annual recovery of approximately $33 million, and are expected to increase an additional 1 percent in 2006. In conjunction with the Alabama PSC’s approval, Alabama Power agreed to a moratorium until March 2007 on any retail rate increase under the previously approved Rate Stabilization and Equalization plan (RSE). Any increase in March 2007 would be based upon the retail ROE at December 31, 2006. See Note 3 to the financial statements under “Alabama Power Retail Regulatory Matters” for further information on RSE.

Mississippi Power Retail Rate Filing

In May 2004, the Mississippi PSC approved Mississippi Power’s request to reclassify to jurisdictional cost of service the 266 megawatts of Plant Daniel unit 3 and 4 capacity, effective January 1, 2004. The Mississippi PSC authorized Mississippi Power to include the related costs and revenue credits in jurisdictional rate base, cost of service, and revenue requirement calculations for purposes of retail rate recovery. Mississippi Power is amortizing the regulatory liability established pursuant to the Mississippi PSC’s interim December 2003 order, as approved in May 2004, to earnings as follows: $16.5 million in 2004, $25.1 million in

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2005, $13.0 million in 2006, and $5.7 million in 2007, resulting in expense reductions in each of those years.

Plant McIntosh Construction Project

In December 2002 after a competitive bidding process, the Georgia PSC certified PPAs between Southern Power and Georgia Power and Savannah Electric for capacity from Plant McIntosh units 10 and 11, construction of which is scheduled to be completed in June 2005. In April 2003, Southern Power applied for FERC approval of these PPAs. In July 2003, the FERC accepted the PPAs to become effective June 1, 2005, subject to refund, and ordered that hearings be held. Intervenors opposed the FERC’s acceptance of the PPAs, alleging that they did not meet the applicable standards for market-based rates between affiliates. To ensure the timely completion of the Plant McIntosh construction project and the availability of the units in the summer of 2005 for their retail customers, Savannah Electric and Georgia Power in May 2004 requested the Georgia PSC to direct them to acquire the Plant McIntosh construction project. The Georgia PSC issued such an order and the transfer occurred on May 24, 2004 at a total cost of approximately $415 million, including $14 million of transmission interconnection facilities. Subsequently, Southern Power filed a request to withdraw the PPAs and to terminate the ongoing FERC proceedings. In August 2004, the FERC issued a notice accepting the request to withdraw the PPAs and permitting such request to become effective by operation of law. However, the FERC made no determination on what additional steps may need to be taken with respect to testimony provided in the proceedings. The ultimate outcome of any additional FERC action cannot now be determined.

     As directed by the Georgia PSC order, Georgia Power and Savannah Electric in June 2004 filed an application to amend the resource certificate granted by the Georgia PSC in 2002 to change the character of the resource from a purchase to a self-owned, rate based asset and to describe the approximate construction schedule and the proposed rate base treatment. In connection with the 2004 Retail Rate Plan, the Georgia PSC approved the transfer of the Plant McIntosh construction project at a total fair market value of approximately $385 million. This value reflects an approximate $16 million disallowance and reduced Southern Company’s 2004 net income by approximately $9.5 million. The Georgia PSC also certified a total completion cost of $547 million for the project. The amount of the disallowance will be adjusted accordingly based on the actual completion cost of the project. Under the 2004 Retail Rate Plan, the Plant McIntosh impact will be reflected in Georgia Power’s rates evenly over the three years ending 2007. See Note 3 to the financial statements under “Georgia Power Retail Rate Activity” and “Plant McIntosh Construction Project” for additional information on the 2004 Retail Rate Plan and the Plant McIntosh construction project.

Retail Fuel Cost Recovery

The retail operating companies each have established fuel cost recovery rates approved by their respective state PSCs. In recent months, the retail operating companies have experienced higher than expected fuel costs for coal and gas. These higher fuel costs have increased the under recovered fuel costs included in the balance sheets. The retail operating companies will continue to monitor the under recovered fuel cost balance in light of these higher fuel costs.

     Alabama Power fuel costs are recovered under Rate ECR (Energy Cost Recovery), which provides for the addition of a fuel and energy cost factor to base rates. In April 2005, this factor is scheduled to increase from its current level.

     On February 18, 2005, Georgia Power filed a request with the Georgia PSC for a fuel cost recovery rate increase effective April 1, 2005, subject to refund. The requested increase, representing an average annual increase in revenues of approximately 11.7 percent, will allow for the recovery of fuel costs based on an estimate of future fuel costs, as well as the collection of the existing under recovery of fuel costs. Georgia Power’s under recovered fuel costs as of January 31, 2005 totaled $390 million. The Georgia PSC will examine Georgia Power’s fuel expenditures and determine whether the proposed fuel cost recovery rate is just and reasonable before issuing its decision in May 2005. The final outcome of the filing cannot be determined at this time. See Note 3 to the financial statements under “Georgia Power Retail Rate Activity” for additional information.

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Storm Damage Cost Recovery

Each retail operating company maintains a reserve for property damage to cover the cost of damages from major storms to its transmission and distribution lines and the cost of uninsured damages to its generation facilities and other property. In September 2004, Hurricane Ivan hit the Gulf Coast of Florida and Alabama and continued north through Southern Company’s service territory causing substantial damage.

     At Gulf Power, the related costs charged to its property damage reserve as of December 31, 2004 were $93.5 million. Prior to Hurricane Ivan, Gulf Power’s reserve balance was approximately $28 million. Gulf Power’s current annual accrual to the property damage reserve, as approved by the Florida PSC, is $3.5 million. The Florida PSC has also approved additional accrual amounts at Gulf Power’s discretion, and Gulf Power accrued an additional $15 million in 2004. In February 2005, Gulf Power, the Office of Public Counsel for the State of Florida, and the Florida Industrial Power Users Group filed a Stipulation and Settlement with the Florida PSC that, if approved, would allow Gulf Power to recover the retail portion of $51.7 million of these costs, plus interest and revenue taxes, from customers over a 24-month period. In connection with the stipulation, Gulf Power has agreed that it will not seek any additional increase in its base rates and charges to become effective on or before March 1, 2007.

     At Alabama Power, operation and maintenance expenses associated with repairing the damage to its facilities and restoring service to customers as a result of Hurricane Ivan were $57.8 million for 2004. The balance in Alabama Power’s natural disaster reserve prior to the storm was $14.6 million. In October 2004, Alabama Power received approval from the Alabama PSC to defer the negative balance for recovery in future periods. Alabama Power is allowed to accrue $250,000 per month until a 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 2004, Alabama Power accrued $9.9 million, including an additional amount of $6.9 million, to the reserve and at December 31, 2004, the negative balance totaled $37.7 million and is reflected in the balance sheet as a regulatory asset.

     In February 2005, Alabama Power requested and received Alabama PSC approval of an accounting order that allows Alabama Power to immediately return certain regulatory liabilities to the retail customers. The order also allows Alabama Power to simultaneously recover from customers an accrual of approximately $45 million to offset the costs of Hurricane Ivan and restore a positive balance in the natural disaster reserve. The combined effects of this order will have no impact on Alabama Power’s net income in 2005. See Notes 1 and 3 to the financial statements under “Storm Damage Reserves” and “Gulf Power and Alabama Power Storm Damage Recovery,” respectively, for additional information on these reserves.

Income Tax Matters

Synthetic Fuel Tax Credits

As discussed in Note 3 to the financial statements under “Income Tax Matters — Synthetic Fuel Tax Credits,” Southern Company has investments in two entities that produce synthetic fuel and receive tax credits under Section 29 of the Internal Revenue Code of 1986, as amended (Internal Revenue Code). These investments include a 30 percent interest in Alabama Fuel Products (AFP) and a 24.975 percent interest in Carbontronics Synfuels Investors, L.P. (Carbontronics). In January 2004, the IRS completed an audit of AFP for 1999 and 2000. In December 2004, the IRS notified Carbontronics that its audit for 2000 and 2001 had been completed. In addition, in December 2004, the IRS also concluded its audits of Southern Company’s consolidated income tax returns for 2000 and 2001. The IRS raised no issues related to synthetic fuel tax credits upon conclusion of any of these audits. As a result, in December 2004, Southern Company reversed its related reserve of $37 million.

     In accordance with Section 29 of the Internal Revenue Code, these tax credits are subject to limitation as the annual average price of oil (as determined by the DOE) increases over a specified, inflation-adjusted dollar amount published in the spring of the subsequent year. Southern Company, along with its partners in these investments, will continue to monitor oil prices. Any indicated potential limitation on these credits could affect either the timing or the amount of the credit recognition and could also require an impairment analysis of these investments by Southern Company.

Leveraged Lease Transactions

Southern Company participates in four international leveraged lease transactions and receives federal income tax deductions for rent, depreciation, and

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amortization, as well as interest on related debt. As discussed in Note 3 to the financial statements under “Income Tax Matters — Leveraged Lease Transactions,” the IRS proposed to disallow the tax losses for one of the lease transactions in connection with its audit of 1996 through 1999. To stop the interest accretion, Southern Company deposited approximately $30 million of additional taxes and interest with the IRS and filed a refund claim. In connection with its audit of 2000 and 2001, the IRS proposed a similar assessment of approximately $18 million, including approximately $3 million of interest. In October 2004, Southern Company submitted the issue to the IRS appeals division and, in February 2005, reached a negotiated settlement with the IRS. The settlement had no material impact on Southern Company’s financial statements.

     In connection with its audit of 2000 and 2001, the IRS has also challenged Southern Company’s deductions related to three other international lease transactions. Southern Company believes these transactions are valid leases for U.S. tax purposes and is pursuing resolution with the IRS. If the IRS is ultimately successful in disallowing the tax deductions related to these three transactions, beginning with the 2000 tax year, Southern Company could be subject to additional interest charges of up to $20 million. Additionally, although the payment of the tax liability, exclusive of this interest, would not affect Southern Company’s results of operations under current accounting standards, it could have a material impact on cash flow. Furthermore, the Financial Accounting Standards Board (FASB) is currently considering changes to the accounting for income tax settlements related to leveraged leases, which may result in a net income impact from such settlements. See Note 1 to the financial statements under “Leveraged Leases” for additional details of the deferred taxes related to these transactions. The final outcome of these matters cannot now be determined.

American Jobs Creation Act of 2004

On October 22, 2004, President Bush signed the American Jobs Creation Act of 2004 (Jobs Act) into law. The Jobs Act includes a provision that allows a generation tax deduction for utilities. Southern Company is currently assessing the impact of the Jobs Act, including this deduction, as well as the related regulatory treatment, on its taxable income. However, Southern Company currently does not expect the Jobs Act to have a material impact on its financial statements.

Other Matters

Other Construction Projects

In October 2004, a partnership between Southern Company and the Orlando Utilities Commission (OUC) was selected by the DOE to build and operate a 285 megawatt coal-gasification facility. The facility will be located at OUC’s Stanton Energy Center near Orlando, Florida, site of Plant Stanton A, an existing gas-fired 630 megawatt unit co-owned by Southern Power, OUC, and others. Southern Power will own and operate the Southern Company portion of the project. The project will demonstrate a coal gasification technology that has been under development, in partnership with the DOE, by Southern Company. The project is expected to begin commercial operation in 2011, with a projected total cost of $557 million. The DOE is expected to contribute approximately $235 million of the cost.

     In August 2004, Southern Power completed limited construction activities on Plant Franklin Unit 3 to preserve the long-term viability of the project. Final completion is not anticipated until the 2008-2011 period. See Note 3 to the financial statements under “Plant Franklin Construction Project” for additional information. The final outcome of this matter cannot now be determined.

Mirant Related Matters

On July 14, 2003, Mirant Corporation (Mirant) filed for voluntary reorganization under Chapter 11 of the Bankruptcy Code 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 discussed in Note 3 to the financial statements under “Mirant Related Matters.”

     In December 2004, as a result of concluding an IRS audit for the tax years 2000 and 2001, Southern Company paid $39 million in additional tax and interest for issues related to Mirant tax items. Under the terms of the separation agreements entered in connection with the spin-off, Mirant agreed to indemnify Southern Company for costs associated with these guarantees, lawsuits, and additional IRS assessments. However, as a result of Mirant’s bankruptcy, Southern Company must seek reimbursement as a creditor in the Chapter 11 proceeding. Based on management’s assessment of

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the collectibility of this receivable, Southern Company reserved approximately $12.5 million. If Southern Company is ultimately required to make any additional payments related to these obligations, Mirant’s indemnification obligation to Southern Company for these additional payments may also represent an unsecured claim, subject to compromise pursuant to Mirant’s final reorganization plan.

Other

In accordance with FASB Statement No. 87, Employers’ Accounting for Pensions, Southern Company recorded non-cash pension income, before tax, of approximately $44 million, $99 million, and $117 million in 2004, 2003, and 2002, respectively. Future pension income is dependent on several factors including trust earnings and changes to the pension 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 $106 million, $101 million, and $99 million in 2004, 2003, and 2002, 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 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.

     Southern Company is involved in various other matters being litigated, regulatory matters, and certain 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 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 PSCs 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, which requires the financial statements to reflect the effects of rate 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 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, 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 legislative, 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

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potentially subject them to environmental, litigation, income tax, and other risks. See FUTURE EARNINGS POTENTIAL herein and Note 3 to the financial statements for more information regarding certain of these contingencies. Southern 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 Southern Company’s financial statements. These events or conditions include the following:

•   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.
 
•   Changes in existing income tax regulations or changes in IRS interpretations of existing regulations.
 
•   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.
 
•   Identification and evaluation of other potential lawsuits or complaints in which Southern Company or its subsidiaries may be named as a defendant.
 
•   Resolution or progression of existing matters through the legislative process, the court systems, the IRS, or the EPA.

Unbilled Revenues

Revenues related to the sale of electricity are recorded when electricity is delivered to customers. However, the determination of kilowatt-hour sales to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month. At the end of each month, amounts of electricity delivered to customers, but not yet metered and billed, are estimated. Components of the unbilled revenue estimates include total kilowatt-hour territorial supply, total kilowatt-hour billed, estimated total electricity lost in delivery, and customer usage. These components can fluctuate as a result of a number of factors including weather, generation patterns, and power delivery volume and other operational constraints. These factors can be unpredictable and can vary from historical trends. As a result, the overall estimate of unbilled revenues could be significantly affected, which could have a material impact on the Company’s results of operations.

New Accounting Standards

On March 31, 2004, Southern Company prospectively adopted FASB Interpretation No. 46R, “Consolidation of Variable Interest Entities,” which requires the primary beneficiary of a variable interest entity to consolidate the related assets and liabilities. The adoption of FASB Interpretation No. 46R had no impact on Southern Company’s net income. However, as a result of the adoption, Southern Company and the retail operating companies deconsolidated certain wholly-owned trusts established to issue preferred securities since Southern Company and the retail operating companies do not meet the definition of primary beneficiary established by FASB Interpretation No. 46R. In addition, Southern Company consolidated its 85 percent limited partnership investment in an energy/technology venture capital fund that was previously accounted for under the equity method. See Note 1 to the financial statements under “Variable Interest Entities” for additional information.

     In the third quarter 2004, Southern Company prospectively adopted FASB Staff Position (FSP) 106-2, Accounting and Disclosure Requirements related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (Medicare Act). The Medicare Act provides a 28 percent prescription drug subsidy for Medicare eligible retirees. FSP 106-2 requires recognition of the impacts of the Medicare Act in the accumulated postretirement benefit obligation (APBO) and future cost of service for postretirement medical plans. The effect of the subsidy reduced Southern Company’s expenses for the six months ended December 31, 2004 by approximately $10.6 million and is expected to have a similar impact on future expenses. The subsidy’s impact on the postretirement medical plan APBO was a reduction of approximately $182 million. However, the ultimate impact on future periods is subject to final interpretation of the federal regulations which were published on January 21, 2005. See Note 2 to the financial statements under “Postretirement Benefits” for additional information.

     FASB Statement No. 123R, Share-Based Payment was issued in December 2004. This statement requires that compensation cost relating to

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share-based payment transactions be recognized in financial statements. That cost will be measured based on the grant date fair value of the equity or liability instruments issued. For Southern Company, this statement is effective beginning on July 1, 2005. Although the compensation expense required under the revised statement differs slightly, the impacts on the Company’s financial statements are expected to be similar to the pro forma disclosures included in Note 1 to the financial statements under “Stock Options.”

     See FUTURE EARNINGS POTENTIAL — “Income Tax Matters — American Jobs Creation Act of 2004” herein for information regarding the adoption of new tax legislation. In December 2004, the FASB issued FSP 109-1, Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax Deduction on Qualified Production Activities provided by the American Jobs Creation Act of 2004, which requires that the generation deduction be accounted for as a special tax deduction rather than as a tax rate reduction. Southern Company is currently assessing the Jobs Act and this pronouncement, as well as the related regulatory treatment, but currently does not expect a material impact on the Company’s financial statements.

FINANCIAL CONDITION AND LIQUIDITY

Overview

Southern Company’s financial condition continued to be strong at December 31, 2004. Net cash flow from operating activities totaled $2.7 billion, $3.1 billion, and $2.9 billion for 2004, 2003, and 2002, respectively. The $379 million decrease for 2004 resulted primarily from higher fuel costs at the retail operating companies. Those costs are recoverable in future periods and are reflected on the balance sheets as under recovered regulatory clause revenues. The $218 million increase from 2002 to 2003 resulted primarily from the deferral of income tax liabilities arising from accelerated depreciation deductions, partially offset by the settlement of interest rate hedges. Gross property additions to utility plant were $2.1 billion in 2004. The majority of funds needed for gross property additions since 2000 has been provided from operating activities.

     Significant balance sheet changes include a $0.5 billion increase in long-term debt and preferred stock for 2004 due to the replacement of short-term financing with long-term debt, consistent with the Company’s finance policy, and an increase of $0.8 billion in property, plant, and equipment.

     At the close of 2004, the closing price of Southern Company’s common stock was $33.52 per share, compared with book value of $13.86 per share. The market-to-book value ratio was 242 percent at the end of 2004, compared with 230 percent at year-end 2003.

     Each of the retail operating companies, Southern Power, and Southern Company Services, Inc. (SCS), the system service company, have received investment grade ratings from the major rating agencies.

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, preferred stock, and equity. Equity capital can be provided from any combination of the Company’s stock plans, private placements, or public offerings. The amount and timing of additional equity capital to be raised in 2005 — 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 2005 and is currently developing a program to repurchase shares to offset issuances under the Company’s stock compensation 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 operating cash flows. In recent years, financings primarily have utilized unsecured debt and preferred securities. However, the type and timing of any financings — if needed — will depend on market conditions and regulatory approval. The issuance of securities by Southern Company and its subsidiaries is generally subject to regulatory approval by the Securities and Exchange Commission (SEC) under the Public Utility Holding Company Act of 1935, as amended (PUHCA), and, generally, for the retail operating companies, the appropriate state PSC. Additionally, with respect to the public offering of securities, Southern Company and its subsidiaries must file registration statements with the SEC under the Securities Act of 1933, as amended (1933 Act). The amounts of securities authorized by the appropriate regulatory authorities, as well as the amounts registered under the 1933 Act, are continuously monitored and appropriate filings are made to ensure flexibility in the capital markets.

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     Southern Power plans to use operating cash flows, external funds, and equity capital from Southern Company to finance its capital expenditures. External funds are expected to be obtained from the issuance of unsecured senior debt and commercial paper or through credit arrangements from banks.

     Southern Company and each retail operating company obtains 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 PUHCA, most loans between affiliated companies must be approved in advance by the SEC.

     Southern 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 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 December 31, 2004, Southern Company and its subsidiaries had approximately $373 million of cash and cash equivalents and $3.2 billion of unused credit arrangements with banks, as described below. 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.

     At December 31, 2004, the Southern Company system had approximately $3.2 billion of unused credit arrangements with banks, of which $1.8 billion expire in 2005 and $1.4 billion expire in 2006 and beyond. Approximately $1.2 billion of the credit facilities expiring in 2005 allow for the execution of term loans for an additional two-year period, and $275 million allow for the execution of one-year term loans. See Note 6 to the financial statements under “Bank Credit Arrangements” for additional information.

Financing Activities

During 2004, Southern Company and its subsidiaries issued $2.1 billion of long-term debt, including long-term debt payable to affiliated trusts, and $175 million of preferred stock. In addition, Southern Company issued 7 million new shares of common stock through the Company’s stock plans and realized proceeds of $124 million. The security issuances were primarily used to redeem $1.5 billion of long-term debt. 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, 2004, Georgia Power refinanced $250 million of maturing long-term debt.

Off-Balance Sheet Financing Arrangements

In May 2001, Mississippi Power began the initial 10-year term of a lease agreement 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. 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 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 assets. See Note 7 to the financial statements under “Operating Leases” for additional information.

Credit Rating Risk

The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- or Baa3 or below. These contracts are primarily for physical electricity purchases and sales. At December 31, 2004, the maximum potential collateral requirements at a BBB- or Baa3 rating were approximately $40 million. The maximum potential collateral requirements at a rating below BBB- or Baa3 were approximately $324 million. Generally, collateral may be provided for by a

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Southern Company guaranty, letter of credit, or cash. The Company is also party to certain derivative agreements that could require collateral and/or accelerated payment in the event of a credit rating change to below investment grade. These agreements are primarily for natural gas price and interest rate risk management activities. At December 31, 2004, Southern Company and its subsidiaries’ maximum potential exposure to these contracts was $10 million.

Market Price Risk

Southern Company is exposed to market risks, primarily commodity price risk and interest rate risk. 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 risk management practices. Company policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, 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 $1.8 billion of long-term variable interest rate exposure that has not been hedged at January 1, 2005 was 2.6 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 $20.1 million at January 1, 2005. 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 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 state PSCs. Southern Company GAS also has in place a risk management program to substantially mitigate its exposure to price volatility for its natural gas purchases.

     The changes in fair value of energy-related derivative contracts and year-end valuations were as follows at December 31:

                 
    Changes in Fair Value  
    2004     2003  
    (in millions)  
Contracts beginning of year
  $ 15.8     $ 47.3  
Contracts realized or settled
    (58.7 )     (73.2 )
New contracts at inception
           
Changes in valuation techniques
           
Current period changes (a)
    53.4       41.7  
 
Contracts end of year
  $ 10.5     $ 15.8  
 

  (a)   Current period changes also include the changes in fair value of new contracts entered into during the period.
                         
Source of 2004 Year-End Valuation Prices  
    Total     Maturity  
    Fair Value     2005     2006-2007  
    (in millions)  
Actively quoted
  $ 9.4     $ 6.3     $ 3.1  
External sources
    1.1       1.1        
Models and other methods
                 
 
Contracts end of year
  $ 10.5     $ 7.4     $ 3.1  
 

     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, 2004, the fair value of derivative energy contracts was reflected in the financial statements as follows:

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    Amounts  
    (in millions)  
Regulatory liabilities, net
  $ 12.8  
Other comprehensive income
    (1.7 )
Net income
    (0.6 )
 
Total fair value
  $ 10.5  
 

     Unrealized pre-tax gains and losses recognized in income were not material for any year presented. 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 2005, $2.5 billion for 2006, and $3.2 billion for 2007. Environmental expenditures included in these amounts are $452 million, $615 million, and $896 million for 2005, 2006, and 2007, 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 Georgia Power and Savannah Electric in June 2005. 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.

     As a result of requirements by the Nuclear Regulatory Commission, Alabama Power and Georgia Power have established external trust funds for nuclear decommissioning costs. For additional information, see Note 1 to the financial statements under “Nuclear Decommissioning.” Also, as discussed in Note 1 to the financial statements under “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, preferred stock dividends, leases, and other purchase commitments are as follows. See Notes 1, 6, and 7 to the financial statements for additional information.

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Contractual Obligations

                                         
            2006-     2008-     After        
    2005     2007     2009     2009     Total  
    (in millions)  
Long-term debt(a)
                                       
Principal
  $ 983     $ 2,266     $ 1,100     $ 9,100     $ 13,449  
Interest
    624       1,140       976       8,781       11,521  
Preferred stock dividends(b)
    30       60       60             150  
Operating leases
    123       195       156       259       733  
Purchase commitments(c)
                                       
Capital(d)
    2,232       5,699                   7,931  
Coal and nuclear fuel
    3,135       4,574       1,126       193       9,028  
Natural gas(e)
    747       1,033       593       2,678       5,051  
Purchased power
    171       357       342       680       1,550  
Long-term service agreements
    67       145       168       1,049       1,429  
Trusts —
                                       
Nuclear decommissioning
    29       55       55       316       455  
Postretirement benefits(f)
    35       79                   114  
DOE
    7       9                   16  
 
Total
  $ 8,183     $ 15,612     $ 4,576     $ 23,056     $ 51,427  
 

(a)   All amounts are reflected based on final maturity dates. Southern Company and its subsidiaries plan to 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, 2005, as reflected in the 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 $3.3 billion, $3.2 billion, and $3.1 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, 2004, 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 Exchange future prices at December 31, 2004.
 
(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 and postretirement plans, including estimated benefit payments. Certain benefit payments will be made through the related trusts. Other benefit payments will be made from the Company’s corporate assets.

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Southern Company and Subsidiary Companies 2004 Annual Report

Cautionary Statement Regarding Forward-Looking Statements

Southern Company’s 2004 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning the strategic goals for Southern Company’s wholesale business, retail sales growth, storm damage cost recovery, environmental regulations and expenditures, the Company’s projections for postretirement benefit trust contributions, completion of construction projects, and estimated construction and other expenditures. 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 similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:

•   the impact of recent and future federal and state regulatory change, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, and also changes in environmental, 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;
 
•   current and future litigation, regulatory investigations, proceedings, or inquiries, including the pending EPA civil actions against certain Southern Company subsidiaries, IRS audits, and Mirant related matters;
 
•   the effects, extent, and timing of the entry of additional competition in the markets in which Southern Company’s subsidiaries operate;
 
•   variations in demand for electricity and gas, including those relating to weather, the general economy and population, and business growth (and declines);
 
•   available sources and costs of fuels;
 
•   ability to control costs;
 
•   investment performance of Southern Company’s employee benefit plans;
 
•   advances in technology;
 
•   state and federal rate regulations and the impact of pending and future rate cases and negotiations;
 
•   the performance of projects undertaken by the non-utility businesses and the success of efforts to invest in and develop new opportunities;
 
•   internal restructuring or other restructuring options that may be pursued;
 
•   potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to Southern Company or its subsidiaries;
 
•   the ability of counterparties of Southern Company and its subsidiaries to make payments as and when due;
 
•   the ability to obtain new short- and long-term contracts with neighboring utilities;
 
•   the direct or indirect effect on Southern Company’s business resulting from terrorist incidents and the threat of terrorist incidents;
 
•   interest rate fluctuations and financial market conditions and the results of financing efforts, including Southern Company’s and its subsidiaries’ credit ratings;
 
•   the ability of Southern Company and its subsidiaries to obtain additional generating capacity at competitive prices;
 
•   catastrophic events such as fires, earthquakes, explosions, floods, hurricanes, or other similar occurrences;
 
•   the direct or indirect effects on Southern Company’s business resulting from incidents similar to the August 2003 power outage in the Northeast;
 
•   the effect of accounting pronouncements issued periodically by standard setting bodies; and
 
•   other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed by Southern Company from time to time with the SEC.

Southern Company expressly disclaims any obligation to update any forward-looking statements.

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CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2004, 2003, and 2002
Southern Company and Subsidiary Companies 2004 Annual Report

                         
 
    2004     2003     2002  
    (in millions)  
Operating Revenues:
                       
Retail sales
  $ 9,732     $ 8,875     $ 8,728  
Sales for resale
    1,341       1,358       1,168  
Other electric revenues
    392       514       310  
Other revenues
    437       439       308  
 
Total operating revenues
    11,902       11,186       10,514  
 
Operating Expenses:
                       
Fuel
    3,521       3,121       2,831  
Purchased power
    643       473       449  
Other operations
    2,302       2,237       2,083  
Maintenance
    1,027       937       965  
Depreciation and amortization
    955       1,027       1,047  
Taxes other than income taxes
    627       586       557  
 
Total operating expenses
    9,075       8,381       7,932  
 
Operating Income
    2,827       2,805       2,582  
Other Income and (Expense):
                       
Allowance for equity funds used during construction
    47       25       22  
Interest income
    27       36       22  
Equity in losses of unconsolidated subsidiaries
    (95 )     (94 )     (91 )
Leveraged lease income
    70       66       58  
Interest expense, net of amounts capitalized
    (540 )     (527 )     (492 )
Interest expense to affiliate trusts
    (100 )            
Distributions on mandatorily redeemable preferred securities
    (27 )     (151 )     (175 )
Preferred dividends of subsidiaries
    (30 )     (21 )     (17 )
Other income (expense), net
    (60 )     (53 )     (63 )
 
Total other income and (expense)
    (708 )     (719 )     (736 )
 
Earnings Before Income Taxes
    2,119       2,086       1,846  
Income taxes
    587       612       528  
 
Consolidated Net Income
  $ 1,532     $ 1,474     $ 1,318  
 
Common Stock Data:
                       
Earnings per share -
                       
Basic
  $ 2.07     $ 2.03     $ 1.86  
Diluted
    2.06       2.02       1.85  
 
Average number of shares of common stock outstanding — (in millions)
                       
Basic
    739       727       708  
Diluted
    743       732       714  
 
Cash dividends paid per share of common stock
  $ 1.415     $ 1.385     $ 1.355  
 

The accompanying notes are an integral part of these financial statements.

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CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2004, 2003, and 2002
Southern Company and Subsidiary Companies 2004 Annual Report

                         
 
    2004     2003     2002  
 
    (in millions)  
Operating Activities:
                       
Consolidated net income
  $ 1,532     $ 1,474     $ 1,318  
Adjustments to reconcile consolidated net income to net cash provided from operating activities -
                       
Depreciation and amortization
    1,178       1,221       1,185  
Deferred income taxes and investment tax credits
    559       429       172  
Plant Daniel capacity
    (17 )     60        
Allowance for equity funds used during construction
    (47 )     (25 )     (22 )
Equity in losses of unconsolidated subsidiaries
    95       94       91  
Leveraged lease income
    (70 )     (66 )     (58 )
Pension, postretirement, and other employee benefits
          (25 )     (78 )
Tax benefit of stock options
    31       30       23  
Hedge settlements
    (10 )     (116 )     (16 )
Other, net
    (21 )     2       14  
Changes in certain current assets and liabilities -
                       
Receivables, net
    (369 )     6       (35 )
Fossil fuel stock
    (8 )     (17 )     105  
Materials and supplies
    (31 )     (12 )     8  
Other current assets
    14       27       (58 )
Accounts payable
    29       (88 )     105  
Accrued taxes
    (109 )     19       (49 )
Accrued compensation
    (16 )     (11 )     41  
Other current liabilities
    (48 )     69       107  
 
Net cash provided from operating activities
    2,692       3,071       2,853  
 
Investing Activities:
                       
Gross property additions
    (2,110 )     (2,014 )     (2,728 )
Investment in unconsolidated subsidiaries
    (97 )     (94 )     (90 )
Cost of removal net of salvage
    (75 )     (80 )     (109 )
Construction receivables/payables, net
    25       (34 )     (17 )
Other
    5       27       (24 )
 
Net cash used for investing activities
    (2,252 )     (2,195 )     (2,968 )
 
Financing Activities:
                       
Decrease in notes payable, net
    (141 )     (366 )     (968 )
Proceeds —
                       
Long-term debt
    1,861       3,494       2,914  
Mandatorily redeemable preferred securities
    200             1,315  
Preferred stock
    175       125        
Common stock
    124       470       428  
Redemptions —
                       
Long-term debt
    (1,245 )     (3,009 )     (1,370 )
Mandatorily redeemable preferred securities
    (240 )     (480 )     (1,171 )
Preferred stock
    (28 )           (70 )
Payment of common stock dividends
    (1,045 )     (1,004 )     (958 )
Other
    (39 )     (68 )     (86 )
 
Net cash provided from (used for) financing activities
    (378 )     (838 )     34  
 
Net Change in Cash and Cash Equivalents
    62       38       (81 )
Cash and Cash Equivalents at Beginning of Year
    311       273       354  
 
Cash and Cash Equivalents at End of Year
  $ 373     $ 311     $ 273  
 

The accompanying notes are an integral part of these financial statements.

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CONSOLIDATED BALANCE SHEETS
At December 31, 2004 and 2003
Southern Company and Subsidiary Companies 2004 Annual Report

                 
 
Assets
  2004     2003  
 
    (in millions)  
               
Current Assets:
               
Cash and cash equivalents
  $ 373     $ 311  
Receivables -
               
Customer accounts receivable
    755       680  
Unbilled revenues
    304       275  
Under recovered regulatory clause revenues
    532       204  
Other accounts and notes receivable
    320       338  
Accumulated provision for uncollectible accounts
    (46 )     (30 )
Fossil fuel stock, at average cost
    325       316  
Vacation pay
    105       97  
Materials and supplies, at average cost
    602       570  
Prepaid expenses
    126       269  
Other
    67       30  
 
Total current assets
    3,463       3,060  
 
Property, Plant, and Equipment:
               
In service
    41,437       40,339  
Less accumulated depreciation
    14,951       14,312  
 
 
    26,486       26,027  
Nuclear fuel, at amortized cost
    218       223  
Construction work in progress
    1,657       1,275  
 
Total property, plant, and equipment
    28,361       27,525  
 
Other Property and Investments:
               
Nuclear decommissioning trusts, at fair value
    905       808  
Leveraged leases
    976       838  
Other
    392       280  
 
Total other property and investments
    2,273       1,926  
 
Deferred Charges and Other Assets:
               
Deferred charges related to income taxes
    864       874  
Prepaid pension costs
    986       911  
Unamortized debt issuance expense
    153       152  
Unamortized loss on reacquired debt
    323       326  
Other regulatory assets
    248       132  
Other
    291       272  
 
Total deferred charges and other assets
    2,865       2,667  
 
Total Assets
  $ 36,962     $ 35,178  
 

The accompanying notes are an integral part of these financial statements.

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CONSOLIDATED BALANCE SHEETS (continued)
At December 31, 2004 and 2003
Southern Company and Subsidiary Companies 2004 Annual Report

                 
 
Liabilities and Stockholders’ Equity
  2004     2003  
 
    (in millions)  
               
Current Liabilities:
               
Securities due within one year
  $ 983     $ 741  
Notes payable
    426       568  
Accounts payable
    885       688  
Customer deposits
    200       189  
Accrued taxes -
               
Income taxes
    47       46  
Other
    243       249  
Accrued interest
    179       185  
Accrued vacation pay
    137       129  
Accrued compensation
    431       437  
Other
    260       273  
 
Total current liabilities
    3,791       3,505  
 
Long-term Debt (See accompanying statements)
    10,488       10,164  
 
Long-term Debt Payable to Affiliated Trusts (See accompanying statements)
    1,961        
 
Mandatorily Redeemable Preferred Securities (See accompanying statements)
          1,900  
 
Deferred Credits and Other Liabilities:
               
Accumulated deferred income taxes
    5,237       4,837  
Deferred credits related to income taxes
    373       408  
Accumulated deferred investment tax credits
    552       579  
Employee benefit obligations
    864       765  
Asset retirement obligations
    903       845  
Other cost of removal obligations
    1,296       1,260  
Miscellaneous regulatory liabilities
    350       572  
Other
    308       272  
 
Total deferred credits and other liabilities
    9,883       9,538  
 
Total Liabilities
    26,123       25,107  
 
Preferred Stock of Subsidiaries (See accompanying statements)
    561       423  
 
Common Stockholders’ Equity (See accompanying statements)
    10,278       9,648  
 
Total Liabilities and Stockholders’ Equity
  $ 36,962     $ 35,178  
 
Commitments and Contingent Matters (See notes)
               
 

The accompanying notes are an integral part of these financial statements.

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CONSOLIDATED STATEMENTS OF CAPITALIZATION
At December 31, 2004 and 2003
Southern Company and Subsidiary Companies 2004 Annual Report

                                     
 
        2004     2003     2004     2003  
 
        (in millions)     (percent of total)  
Long-Term Debt of Subsidiaries:
                                   
First mortgage bonds -
                                   
Maturity
  Interest Rates                                
2006
  6.50% to 6.90%   $ 45     $ 45                  
2025 through 2026
  6.88% to 7.45%     60       60                  
 
Total first mortgage bonds
        105       105                  
 
Long-term senior notes and debt -
                                   
Maturity
  Interest Rates                                
2004
  4.88% to 7.25%           580                  
2005
  5.49% to 5.50%     379       379                  
2006
  1.60% to 6.20%     674       679                  
2007
  2.79% to 7.13%     1,220       929                  
2008
  3.13% to 6.55%     462       458                  
2009
  4.10% to 7.27%     169       43                  
2010 through 2044
  4.00% to 8.12%     4,535       4,242                  
Adjustable rates (at 1/1/05):
                                   
2004
  1.27% to 2.44%           89                  
2005
  1.66% to 3.63%     563       492                  
2006
  2.09%     195       195                  
2007
  3.76%     90       47                  
2009
  2.48% to 2.76%     440                        
 
Total long-term senior notes and debt
        8,727       8,133                  
 
Other long-term debt -
                                   
Pollution control revenue bonds -
                                   
Maturity
  Interest Rates                                
Collateralized:
                                   
2006
  5.25%     12       12                  
2024
  5.50%     24       24                  
Variable rates (at 1/1/05):
                                   
2015 through 2017
  2.01% to 2.16%     90       90                  
Non-collateralized:
                                   
2012 through 2034
  1.08% to 5.45%     850       850                  
Variable rates (at 1/1/05):
                                   
2011 through 2038
  1.24% to 2.65%     1,565       1,565                  
 
Total other long-term debt
        2,541       2,541                  
 
Capitalized lease obligations
        115       107                  
 
Unamortized debt (discount), net
        (17 )     (21 )                
 
Total long-term debt (annual interest requirement — $496 million)
        11,471       10,865                  
 
Less amount due within one year
        983       701                  
 
Long-term debt excluding amount due within one year     10,488       10,164       45.1 %     45.9 %
 

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CONSOLIDATED STATEMENTS OF CAPITALIZATION (continued)
At December 31, 2004 and 2003
Southern Company and Subsidiary Companies 2004 Annual Report

                                     
 
        2004     2003     2004     2003  
 
        (in millions)     (percent of total)  
Long-term Debt Payable to Affiliated Trusts:                                
Maturity
  Interest Rates                                
2027 through 2041
  7.20% to 8.19%     436                        
2042
  4.75% to 7.13%     1,319                        
2044
  5.88%     206                        
 
Total long-term debt payable to affiliated trusts (annual interest requirement — $128 million)
    1,961             8.4       0.0  
 
Mandatorily Redeemable Preferred Securities:                                
$25 liquidation value -                                
Maturity
  Interest Rates                                
2028 through 2042
  6.85% to 7.63%           944                  
$1,000 liquidation value -                                
Maturity
  Interest Rates                                
2027 through 2042
  4.75% to 8.19%           996                  
 
Total mandatorily redeemable preferred securities           1,940                  
Less amount due within one year           40                  
 
Total mandatorily redeemable preferred securities excluding amount due within one year
          1,900       0.0       8.6  
 
Preferred Stock of Subsidiaries:                                
$100 cumulative par or stated value — 4.20% to 7.00%     100       98                  
$25 par or stated value —                                
   Cumulative — 5.20% to 5.83%     294       200                  
   Non-cumulative — 6.00%     44                        
$100,000 cumulative par or stated value — 4.95%     123       125                  
 
Total preferred stock of subsidiaries (annual dividend requirement — $30 million)
    561       423       2.4       1.9  
 
Common Stockholders’ Equity:                                
Common stock, par value $5 per share —     3,709       3,675                  
   Authorized — 1 billion shares                                
   Issued — 2004: 742 million shares                                
      — 2003: 735 million shares
                                   
   Treasury — 2004: 0.2 million shares                                
          — 2003: 0.2 million shares
                                   
   Paid-in capital     869       747                  
   Treasury, at cost     (6 )     (4 )                
Retained earnings     5,839       5,343                  
Accumulated other comprehensive income (loss)     (133 )     (113 )                
 
Total common stockholders’ equity     10,278       9,648       44.1       43.6  
 
Total Capitalization   $ 23,288     $ 22,135       100.0 %     100.0 %
 

The accompanying notes are an integral part of these financial statements.

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CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY
For the Years Ended December 31, 2004, 2003, and 2002
Southern Company and Subsidiary Companies 2004 Annual Report

                                                 
    Common Stock                      
                                    Accumulated        
    Par     Paid-In             Retained     Other Comprehensive        
    Value     Capital     Treasury     Earnings     Income (Loss)     Total  
 
    (in millions)  
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  
Net income
                      1,532             1,532  
Other comprehensive income (loss)
                            (20 )     (20 )
Stock issued
    34       122                         156  
Cash dividends
                      (1,044 )           (1,044 )
Other
                (2 )     8             6  
 
Balance at December 31, 2004
  $ 3,709     $ 869     $ (6 )   $ 5,839     $ (133 )   $ 10,278  
 

The accompanying notes are an integral part of these financial statements.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2004, 2003, and 2002
Southern Company and Subsidiary Companies 2004 Annual Report

                         
 
    2004     2003     2002  
 
    (in millions)  
Consolidated Net Income
  $ 1,532     $ 1,474     $ 1,318  
 
Other comprehensive income (loss):
                       
Change in additional minimum pension liability, net of tax of $(11), $(11), and $(18), respectively
    (20 )     (17 )     (31 )
Change in fair value of marketable securities, net of tax of $(4)
    6              
Changes in fair value of qualifying hedges, net of tax of $(12), $(2), $(45), and respectively
    (18 )     (17 )     (60 )
Less: Reclassification adjustment for amounts included in net income, net of tax of $7, $1, and $1, respectively
    12       3       2  
 
Total other comprehensive income (loss)
    (20 )     (31 )     (89 )
 
Consolidated Comprehensive Income
  $ 1,512     $ 1,443     $ 1,229  
 

The accompanying notes are an integral part of these financial statements.

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NOTES TO FINANCIAL STATEMENTS
Southern Company and Subsidiary Companies 2004 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 (SouthernLINC Wireless), 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 the subsidiary companies. SouthernLINC Wireless 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 the State of Georgia. Southern Holdings is an intermediate holding subsidiary for Southern Company’s investments in synthetic fuels and leveraged leases and various other energy-related businesses. Southern Nuclear operates and provides services to Southern Company’s nuclear power plants.

     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 and for variable interest entities where the Company is not the primary beneficiary. All material intercompany items have been eliminated in consolidation. Certain prior years’ data presented in the 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, as amended (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 (PSC). 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 2004, 2003, and 2002 were $409 million, $312 million, and $217 million, respectively. Synfuel Services, Inc. (SSI), another subsidiary of Southern Holdings, provides fuel transportation services to AFP that are ultimately reflected in the cost of the synthetic fuel billed to Alabama Power and Georgia Power. In connection with these services, the related revenues of approximately $82 million, $65 million, and $35 million in 2004, 2003, and 2002, respectively, have been eliminated against fuel expense in the financial statements. SSI also provides additional services to AFP, as well as to a related party of AFP. Revenues from these transactions totaled approximately $24 million, $20 million, and $15 million, in 2004, 2003, and 2002, respectively.

Revenues

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. 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 the actual recoverable costs and amounts billed in current regulated rates.

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Southern Company and Subsidiary Companies 2004 Annual Report

     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 averaged less than 1 percent of revenues despite an increase in customer bankruptcies.

Fuel Costs

Fuel costs are expensed as the fuel is used. Fuel expense generally includes the cost of purchased emission allowances as they are used. Fuel expense also includes the amortization of the cost of nuclear fuel and a charge, based on nuclear generation, for the permanent disposal of spent nuclear fuel. Total charges for nuclear fuel included in fuel expense amounted to $134 million in 2004, $138 million in 2003, and $134 million in 2002. 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 1998 as required by the contracts, and Alabama Power and Georgia Power 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. Construction of an on-site dry storage facility at Plant Farley is in progress and scheduled for operation in 2005. The onsite storage facility is expected to provide adequate spent fuel storage through 2015 for both units. Also, the facility will be able to be expanded to provide storage through 2025. Sufficient pool storage capacity for spent fuel is available at Plant Vogtle to maintain full-core discharge capability for both units into 2015. Construction of an on-site dry storage facility at Plant Vogtle is scheduled to begin in sufficient time to maintain pool full-core discharge capability. 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.

     Also, the Energy Policy Act of 1992 established 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, 2004 under this law to be approximately $9 million and $7 million.

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 balance sheets at December 31 relate to:

                         
    2004     2003     Note  
 
    (in millions)  
Deferred income tax charges
  $ 865     $ 874       (a )
Asset retirement obligations
    (173 )     (138 )     (a )
Other cost of removal obligations
    (1,296 )     (1,260 )     (a )
Deferred income tax credits
    (374 )     (409 )     (a )
Loss on reacquired debt
    323       326       (b )
Vacation pay
    105       97       (c )
Accelerated cost recovery
    (1 )     (115 )     (d )
Building lease
    53       54       (e )
Generating plant outage costs
    49       45       (e )
Other assets
    104       100       (e )
Storm damage
    83       (53 )     (e )
Environmental remediation
    13       (41 )     (e )
Deferred purchased power
    (19 )     (92 )     (e )
Other liabilities
    (31 )     (26 )     (e )
Plant Daniel capacity
    (44 )     (60 )     (f )
 
Total
  $ (343 )   $ (698 )        
 

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 60 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)   Recorded as earned by employees and recovered as paid, generally within one year.

(d)   Amortized over three-year period ending in 2004 for Georgia Power and 2005 for Savannah Electric.

(e)   Recorded and recovered or amortized as approved by the appropriate state PSCs.

(f)   Amortized over four-year period ending in 2007.

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Southern Company and Subsidiary Companies 2004 Annual Report

     In the event that a portion of a retail operating company’s operations is no longer subject to the provisions of FASB Statement No. 71, such company would be required to write off related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the retail operating 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 currently reflected in rates.

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 life of the related property.

Depreciation and Amortization

Depreciation of the original cost of plant in service is provided primarily by using composite straight-line rates, which approximated 3.0 percent in 2004, 3.1 percent in 2003, and 3.2 percent in 2002. When property subject to composite depreciation is retired or otherwise disposed of in the normal course of business, its original cost — together with the cost of removal, less salvage — is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation is removed from the balance sheet accounts and a gain or loss is recognized. Minor items of property included in the original cost of the plant are retired when the related property unit is retired.

     Under its 2001 rate order, the Georgia PSC ordered Georgia Power to amortize $333 million — the cumulative balance of accelerated depreciation and amortization previously expensed — equally over three years as a credit to depreciation and amortization expense beginning January 2002. Georgia Power was also ordered to recognize new certified purchased power costs in rates evenly over the three-year period by the 2001 rate order. As a result of this regulatory adjustment, Georgia Power recorded depreciation and amortization expense of $(77) million, $14 million, and $63 million in 2004, 2003, and 2002, respectively. See Note 3 under “Georgia Power Retail Rate Activity” for additional information.

     In May 2004, the Mississippi PSC approved Mississippi Power’s request to reclassify 266 megawatts of Plant Daniel units 3 and 4 capacity to jurisdictional cost of service effective January 1, 2004 and authorized Mississippi Power to include the related costs and revenue credits in jurisdictional rate base, cost of service, and revenue requirement calculations for purposes of retail rate recovery. Mississippi Power is amortizing the regulatory liability established pursuant to the Mississippi PSC’s interim December 2003 order, as approved in May 2004, to earnings as follows: $16.5 million in 2004, $25.1 million in 2005, $13.0 million in 2006, and $5.7 million in 2007, resulting in increases to earnings in each of those years.

Asset Retirement Obligations and Other Costs of Removal

Effective January 1, 2003, Southern 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 costs 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. Although 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 retail operating companies have received accounting guidance from their respective state PSCs allowing such treatment. Accordingly, the accumulated removal costs for other obligations previously accrued will continue to be reflected on the balance sheets 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, 2004 was $905 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

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Southern Company and Subsidiary Companies 2004 Annual Report

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 statements of income 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 balance sheets. See “Nuclear Decommissioning” herein for further information on amounts included in rates.

     Details of the asset retirement obligations included in the balance sheets are as follows:

                 
    2004     2003  
 
    (in millions)  
Balance beginning of year
  $ 845     $  
Liabilities incurred
          780  
Liabilities settled
    (3 )      
Accretion
    57       55  
Cash flow revisions
    4       10  
 
Balance end of year
  $ 903     $ 845  
 

Nuclear Decommissioning

The Nuclear Regulatory Commission (NRC) requires licensees of commercial nuclear power reactors to establish a plan for providing reasonable assurance of funds for future 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 PSCs, 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 PSCs. The NRC’s minimum external funding requirements are based on a generic estimate of the cost to decommission only 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 studies as of December 31, 2004 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  
 
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  
 

     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 PSCs. The amount expensed in 2004 and fund balances were as follows:

                         
    Plant     Plant     Plant  
    Farley     Hatch     Vogtle  
 
    (in millions)  
Amount expensed in 2004
  $ 18     $ 7     $ 2  
Accumulated provisions:
                       
External trust funds, at fair value
  $ 446     $ 294     $ 165  
Internal reserves
    29             2  
 
Total
  $ 475     $ 294     $ 167  
 

     Alabama Power’s decommissioning costs for ratemaking are based on the site study. Effective January 1, 2005, the Georgia PSC has ordered the annual decommissioning costs for ratemaking be decreased from $9 million to $7 million. This amount is based on the NRC generic estimate to decommission the radioactive portion of the facilities as of 2003 — $421 million and $326 million for plants Hatch and Vogtle, respectively. Significant assumptions used to determine these costs for ratemaking were an inflation rate of 4.5 percent and 3.1 percent for Alabama Power and Georgia Power, respectively, and a trust earnings rate of 7.0 percent and 5.1 percent for Alabama Power and Georgia Power, respectively. Another significant assumption used was the change in the operating license for

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Southern Company and Subsidiary Companies 2004 Annual Report

Plant Hatch. 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. The NRC is expected to rule on the application by July 2005. Alabama Power and Georgia Power expect their respective state PSCs to periodically review and adjust, if necessary, the amounts collected in rates for the anticipated cost of decommissioning.

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 $551 million, $603 million, and $560 million in 2004, 2003, and 2002, respectively, net of amounts capitalized of $36 million, $49 million, and $59 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 state PSC 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. See Note 3 under “Plant McIntosh Construction Project” for information on a regulatory disallowance by the Georgia PSC in December 2004.

Storm Damage Reserves

Each retail operating company maintains a reserve for property damage to cover the cost of uninsured damages from major storms to transmission and distribution lines and to generation facilities and other property. In accordance with their respective state PSC orders, the retail operating companies accrue a total of $16 million annually. Alabama Power, Gulf Power, and Mississippi Power also have discretionary authority from their state PSCs to accrue additional amounts as circumstances warrant. In 2004, Alabama Power, Gulf Power, and Mississippi Power accrued additional amounts of $6.9 million, $15 million, and $3.1 million, respectively. See Note 3 under “Gulf Power and Alabama Power Storm Damage Recovery” for additional information regarding the impact of Hurricane Ivan on these reserves.

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NOTES (continued)
Southern Company and Subsidiary Companies 2004 Annual Report

Environmental Cost Recovery

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 may also incur substantial costs to clean up properties. Alabama Power, Gulf Power, and Mississippi Power have each received authority from their respective state PSCs to recover approved environmental compliance costs through specific retail rate clauses. Within limits approved by the state PSCs, these rates are adjusted annually. Georgia Power and Savannah Electric continue to recover environmental costs through their base rates.

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:

                 
    2004     2003  
 
    (in millions)  
Net rentals receivable
  $ 1,755     $ 1,512  
Unearned income
    (779 )     (674 )
 
Investment in leveraged leases
    976       838  
Deferred taxes arising from leveraged leases
    (392 )     (351 )
 
Net investment in leveraged leases
  $ 584     $ 487  
 

     A summary of the components of income from leveraged leases is as follows:

                         
    2004     2003     2002  
 
    (in millions)  
Pretax leveraged lease income
  $ 70     $ 66     $ 58  
Income tax expense
    27       23       20  
 
Net leveraged lease income
  $ 43     $ 43     $ 38  
 

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 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.

     The pro forma impact of fair-value accounting for options granted on earnings from continuing operations is as follows:

                 
    As     Pro  
    Reported     Forma  
 
2004
               
Net income (in millions)
  $ 1,532     $ 1,516  
Earnings per share (dollars):
               
Basic
  $ 2.07     $ 2.05  
Diluted
  $ 2.06     $ 2.04  
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  
 

     The estimated fair values of stock options granted in 2004, 2003, and 2002 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:

                         
    2004     2003     2002  
 
Interest rate
    3.1 %     2.7 %     2.8 %
Average expected life of stock options (in years)
    5.0       4.3       4.3  
Expected volatility of common stock
    19.6 %     23.6 %     26.3 %
Expected annual dividends on common stock
  $ 1.40     $ 1.37     $ 1.34  
Weighted average fair value of stock options granted
  $ 3.29     $ 3.59     $ 3.37  
 

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Southern Company and Subsidiary Companies 2004 Annual Report

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 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, 2004
  $ 13,317     $ 13,560  
At December 31, 2003
    10,759       10,971  
Preferred securities:
               
At December 31, 2004
           
At December 31, 2003
    1,940       2,059  
 

     The fair values were based on either closing market price or closing price of comparable instruments. See “Variable Interest Entities” herein and Note 6 under “Mandatorily Redeemable Preferred Securities/Long-Term Debt Payable to Affiliated Trusts” for further information.

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 value of qualifying cash flow hedges and marketable securities, and changes in additional minimum pension liability, less income taxes and reclassifications for amounts included in net income.

Variable Interest Entities

On March 31, 2004, Southern Company prospectively adopted FASB Interpretation No. 46R, “Consolidation of Variable Interest Entities,” which requires the primary beneficiary of a variable interest entity to consolidate the related assets and liabilities. The adoption of Interpretation No. 46R had no impact on the net income of Southern Company. However, as a result of the adoption, Southern Company deconsolidated certain wholly-owned trusts established to issue preferred securities since Southern Company and the retail operating companies are not the primary beneficiaries of the trusts. Therefore, the investments in these trusts are reflected as Other Investments, and the related loans from the trusts are reflected as Long-term Debt Payable to Affiliated Trusts on the balance sheet as of December 31, 2004. This treatment resulted in a $60 million increase in both total assets and total liabilities as of March 31, 2004.

     In addition, Southern Company consolidated its 85 percent limited partnership investment in an energy/technology venture capital fund that was previously accounted for under the equity method. During the third quarter of 2004, Southern Company terminated new investments in this fund; however, additional contributions to existing investments will still occur. Southern Company has committed to a maximum investment of $50 million. At December 31, 2004, Southern Company’s investment totaled $22.0 million.

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 of 1974, as amended (ERISA), requirements. No contributions to the plan are expected for the year ending December 31, 2005. Southern Company also provides certain non-qualified benefit plans for a selected group of management and highly

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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, 2005, postretirement trust contributions are expected to total approximately $34.5 million.

     The measurement date for plan assets and obligations is September 30 for each year.

Pension Plans

The accumulated benefit obligation for the pension plans was $4.6 billion in 2004 and $4.2 billion in 2003. Changes during the year in the projected benefit obligations, accumulated benefit obligations, and fair value of plan assets were as follows:

                 
    Projected  
    Benefit Obligations  
    2004     2003  
 
    (in millions)  
Balance at beginning of year
  $ 4,573     $ 4,094  
Service cost
    128       115  
Interest cost
    270       261  
Benefits paid
    (207 )     (197 )
Plan amendments
    6       11  
Actuarial (gain) loss
    305       289  
 
Balance at end of year
  $ 5,075     $ 4,573  
 
                 
    Plan Assets  
    2004     2003  
 
    (in millions)  
Balance at beginning of year
  $ 5,159     $ 4,600  
Actual return on plan assets
    501       735  
Employer contributions
    23       -  
Benefits paid
    (207 )     (176 )
 
Balance at end of year
  $ 5,476     $ 5,159  
 

     Pension plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code of 1986, as amended (Internal 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     2004     2003  
 
Domestic equity
    37 %     36 %     37 %
International equity
    20       20       20  
Fixed income
    26       26       24  
Real estate
    10       10       11  
Private equity
    7       8       8  
 
Total
    100 %     100 %     100 %
 

     The reconciliations of the funded status with the accrued pension costs recognized in the balance sheets were as follows:

                 
    2004     2003  
 
    (in millions)  
Funded status
  $ 401     $ 586  
Unrecognized transition amount
    (14 )     (26 )
Unrecognized prior service cost
    292       314  
Unrecognized net (gain) loss
    185       (70 )
 
Prepaid pension asset, net
  $ 864     $ 804  
 

     The prepaid pension asset, net is reflected in the balance sheets in the following line items:

                 
    2004     2003  
 
    (in millions)  
Prepaid pension asset
  $ 986     $ 911  
Employee benefit obligations
    (280 )     (229 )
Other Property and Investments Other
    50       45  
Accumulated other comprehensive income
    108       77  
 
Prepaid pension asset, net
  $ 864     $ 804  
 

     Components of the pension plans’ net periodic cost were as follows:

                         
    2004     2003     2002  
 
            (in millions)          
Service cost
  $ 128     $ 115     $ 109  
Interest cost
    269       261       277  
Expected return on plan assets
    (452 )     (450 )     (449 )
Recognized net gain
    (7 )     (42 )     (65 )
Net amortization
    18       17       11  
 
Net pension cost (income)
  $ (44 )   $ (99 )   $ (117 )
 

     Future benefit payments reflect expected future service and are estimated based on assumptions used to measure the projected benefit obligation for the pension plans. At December 31, 2004, estimated benefit payments were as follows:

         
    (in millions)  
2005
  $ 207  
2006
    211  
2007
    218  
2008
    226  
2009
    237  
2010 to 2014
    1,482  
 

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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  
    2004     2003  
 
    (in millions)  
Balance at beginning of year
  $ 1,655     $ 1,461  
Service cost
    27       25  
Interest cost
    93       93  
Benefits paid
    (68 )     (66 )
Actuarial (gain) loss
    72       142  
Plan amendments
    (67 )     -  
 
Balance at end of year
  $ 1,712     $ 1,655  
 
                 
    Plan Assets  
    2004     2003  
 
    (in millions)  
Balance at beginning of year
  $ 522     $ 417  
Actual return on plan assets
    64       70  
Employer contributions
    74       101  
Benefits paid
    (68 )     (66 )
 
Balance at end of year
  $ 592     $ 522  
 

     Postretirement benefits plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal 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     2004     2003  
 
Domestic equity
    43 %     43 %     44 %
International equity
    17       18       18  
Fixed income
    33       32       31  
Real estate
    4       4       4  
Private equity
    3       3       3  
 
Total
    100 %     100 %     100 %
 

     The accrued postretirement costs recognized in the balance sheets were as follows:

                 
    2004     2003  
 
    (in millions)  
Funded status
  $ (1,120 )   $ (1,133 )
Unrecognized transition obligation
    129       144  
Unrecognized prior service cost
    130       211  
Unrecognized net loss (gain)
    408       357  
Fourth quarter contributions
    30       19  
 
Accrued liability recognized in the balance sheets
  $ (423 )   $ (402 )
 

     Components of the postretirement plans’ net periodic cost were as follows:

                         
    2004     2003     2002  
 
            (in millions)  
Service cost
  $ 28     $ 25     $ 21  
Interest cost
    93       93       91  
Expected return on plan assets
    (50 )     (47 )     (42 )
Net amortization
    35       30       29  
 
Net postretirement cost
  $ 106     $ 101     $ 99  
 

     In the third quarter 2004, Southern Company prospectively adopted FASB Staff Position (FSP) 106-2, Accounting and Disclosure Requirements related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (Medicare Act). The Medicare Act provides a 28 percent prescription drug subsidy for Medicare eligible retirees. FSP 106-2 requires recognition of the impacts of the Medicare Act in the accumulated postretirement benefit obligation (APBO) and future cost of service for postretirement medical plan. The effect of the subsidy reduced Southern Company’s expenses for the six months ended December 31, 2004 by approximately $10.6 million and is expected to have a similar impact on future expenses. The subsidy’s impact on the postretirement medical plan APBO was a reduction of approximately $182 million.

     Future benefit payments, including prescription drug benefits, reflect expected future service and are estimated based on assumptions used to measure the accumulated benefit obligation for the postretirement plans. Estimated benefit payments are reduced by drug subsidy receipts expected as a result of the Medicare Act as follows:

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    Benefit     Subsidy        
    Payments     Receipts     Total  
 
            (in millions)        
2005
  $ 67     $     $ 67  
2006
    73       (8 )     65  
2007
    80       (9 )     71  
2008
    87       (10 )     77  
2009
    96       (11 )     85  
2010 to 2014
    612       (72 )     540  
 

     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:

                         
    2004     2003     2002  
 
Discount
    5.75 %     6.00 %     6.50 %
Annual salary increase
    3.50       3.75       4.00  
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 11 percent for 2004, decreasing gradually to 5 percent through the year 2012, 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, 2004 as follows:

                 
    1 Percent     1 Percent  
    Increase     Decrease  
 
    (in millions)  
Benefit obligation
  $ 156     $ 123  
Service and interest costs
    9       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 2004, 2003, and 2002 were $56 million, $55 million, and $53 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 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 Bankruptcy

In July 2003, Mirant Corporation (Mirant) filed for voluntary reorganization under Chapter 11 of the Bankruptcy Code with the U.S. Bankruptcy Court (Bankruptcy Court). In January 2005, Mirant filed its plan of reorganization (POR), which must be approved by the 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 below. Southern Company has paid approximately $1.4 million in connection with the guarantees. Also, Southern Company has joint and several liability with Mirant regarding the joint consolidated federal income tax returns through 2001, as discussed in Note 5. In December 2004, as a result of concluding an IRS audit for the tax years 2000 and 2001, Southern Company paid $39 million in additional tax and interest for issues related to Mirant tax items. Based on management’s assessment of the collectibility of this receivable, Southern Company reserved approximately $12.5 million.

     Under the terms of the separation agreements, Mirant agreed to indemnify Southern Company for

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costs associated with these guarantees, lawsuits, and additional IRS assessments. However, as a result of Mirant’s bankruptcy, Southern Company must seek reimbursement as a creditor in Mirant’s Chapter 11 proceeding. Southern Company has filed several claims against Mirant in connection with Mirant’s indemnity obligations.

     The POR provides for the settlement of court-approved claims by unsecured creditors with common stock of a new corporation to which Mirant would transfer substantially all of its assets and its restructured debt and interests in a trust to which Mirant would transfer certain assets, including any claims that Mirant may have against Southern Company. Mirant’s disclosure statement filed with the POR states that it is unlikely that there is sufficient value to provide a full recovery to all creditors. A valuation hearing is scheduled before the Bankruptcy Court for April 11, 2005. If Southern Company is ultimately required to make any additional payments related to these obligations, Mirant’s indemnification obligation to Southern Company for those additional payments may also represent an unsecured claim, subject to compromise pursuant to the POR.

     In April 2004, the U.S. Bankruptcy Court judge presiding over Mirant’s proceedings ordered that an examiner be appointed and defined the duties of the examiner, including the investigation of any potential causes of action against insiders, past or present, of Mirant or any basis for objecting to or subordinating any claim that may be available to Mirant against any past or present insider or any member of a committee appointed in Mirant’s bankruptcy proceeding. As a former shareholder of Mirant, Southern Company could be considered a past insider. In June 2004, Mirant’s bankruptcy counsel notified Southern Company that it is investigating, on behalf of a committee of independent Mirant directors, potential claims against Southern Company. Southern Company has produced documents in response to related informal requests by Mirant’s bankruptcy counsel and is cooperating in the investigation. The final outcome of these matters cannot now be determined.

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 were added as defendants in a class action lawsuit that several Mirant shareholders originally filed against Mirant and certain Mirant officers in May 2002. 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.

     In July 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 do not allege any improper trading and marketing activity, accounting errors, or material misstatements or omissions on the part of Southern Company but 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 in September 2003. Plaintiffs have also filed a motion for class certification.

     As a result of Mirant’s Chapter 11 proceeding, the Bankruptcy Code automatically stayed all litigation as to Mirant. In November 2003, the Bankruptcy Court granted a request to extend this automatic stay to all other non-debtor defendants, including Southern Company and its current and/or former officers named as defendants in the Mirant securities litigation. However, the Bankruptcy Court authorized Mirant 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 agreed that document discovery could proceed. In October 2003, the Bankruptcy Court entered an order authorizing Southern Company’s insurance companies to pay related defense costs.

     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 who are also named as defendants in this lawsuit. The final outcome of these matters cannot now be determined.

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Southern Company Employee Savings Plan Litigation

On June 30, 2004, an employee of a subsidiary of Southern Company filed a complaint in the U.S. District Court for the Northern District of Georgia alleging violations of ERISA, on behalf of a purported class of individuals who were participants in or beneficiaries of The Southern Company Employee Savings Plan (Plan) at any time since April 2, 2001 and whose Plan accounts included investments in Mirant common stock. The complaint, which was amended on December 6, 2004, named as defendants Southern Company, SCS, the Employee Savings Plan Committee, the Pension Fund Investment Review Committee, individual members of such committees, and the SCS Board of Directors during the class period.

     In the amended complaint, the plaintiff alleges that the various defendants had certain fiduciary duties under ERISA regarding the Mirant shares distributed to Southern Company shareholders in the spin off and held in the Mirant stock fund in the Plan. The plaintiff alleges that the various defendants breached their respective fiduciary duties by, among other things, failing to adequately determine whether Mirant stock was an appropriate investment option to hold in the Plan and by failing to adequately inform Plan participants that Mirant stock was not an appropriate investment for their retirement assets based on Mirant’s alleged improper energy trading and accounting practices, mismanagement, and dire business conditions. The amended complaint also alleges that certain defendants failed to monitor Plan fiduciaries and that certain defendants had conflicting interests regarding Mirant, which prevented them from acting solely in the interests of Plan participants and beneficiaries. The plaintiff seeks class-wide equitable relief and an unspecified amount of money damages.

     On February 7, 2005, the Southern Company defendants filed a motion to dismiss all of the claims asserted in the amended complaint. The ultimate outcome of this matter cannot now be determined.

Environmental Matters

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 and Georgia Power, alleging violations of the New Source Review (NSR) provisions of the Clean Air Act and related state laws at five coal-fired generating facilities. The EPA concurrently issued to each of the retail operating companies notices of violation relating to 10 generating facilities, including 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.

     The U.S. District Court for the Northern District of Georgia subsequently granted Alabama Power’s motion to dismiss and denied the EPA’s motion to add Gulf Power and Mississippi Power for lack of jurisdiction in Georgia. In March 2001, the court granted the EPA’s motion to add Savannah Electric as a defendant and to add allegations regarding two additional generating facilities owned by Alabama Power. 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 civil complaints allege violations with respect to eight coal-fired generating facilities in Alabama and Georgia, and they request penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The EPA has not refiled against Gulf Power or Mississippi Power.

     The actions against Alabama Power, Georgia Power, and Savannah Electric were effectively stayed in the spring of 2001 during the appeal of a similar NSR enforcement action against the Tennessee Valley Authority (TVA) before the U.S. Court of Appeals for the Eleventh Circuit. In June 2003, the Court of Appeals issued its ruling in the TVA case, dismissing the appeal for reasons unrelated to the issues in the cases pending against Alabama Power, Georgia Power, and Savannah Electric. In May 2004, the U.S. Supreme Court denied the EPA’s petition for review of the case. In June 2004, the U.S. District Court for the Northern District of Alabama lifted the stay in the action against Alabama Power, placing the case back onto the court’s active docket. At this time, no party to the case against Georgia Power and Savannah Electric has sought to reopen that case, which remains administratively closed in the U.S. District Court for the Northern District of Georgia.

     Since the inception of the NSR proceedings against Alabama Power, Georgia Power, and

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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. District courts addressing these cases have, to date, issued opinions that reached conflicting conclusions.

     Southern Company believes that the retail operating companies complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $32,500 per day, per violation at each generating unit, depending on the date of the alleged violation. 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.

     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 (RMRR) exclusion. A coalition of states and environmental organizations has filed petitions for review of these revisions with the U.S. Court of Appeals for the District of Columbia Circuit. The October 2003 RMRR rules have been stayed by the Court of Appeals pending its review of the rules. In any event, the final regulations must be adopted by the individual states to apply to facilities in the Southern Company system. The effect of these final regulations, related legal challenges, and potential state rulemakings cannot be determined at this time.

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 for the Northern District of 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.

     The court has concluded the liability phase of the action. The court ruled in favor of Georgia Power on the allegations regarding the hazardous air pollutants, the allegations regarding emission offsets, and a majority of the allegations regarding the permit provision that requires the combined cycle units to operate above certain levels. The court ruled in favor of the plaintiffs on a majority of the opacity incidents. Georgia Power has filed a petition for review of the decision with the U.S. Court of Appeals for the Eleventh Circuit. The district court case has been administratively closed pending that appeal. If necessary, the district court will hold a separate remedy trial which will address civil penalties and possible injunctive relief requested by the plaintiffs. The ultimate outcome of this matter cannot currently be determined; however, an adverse outcome could require substantial capital expenditures that cannot be determined at this time and could possibly require the 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 Remediation

Georgia Power has been designated as a potentially responsible party at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act. In 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. As of December 31, 2004, Georgia Power had recorded approximately $6 million in cumulative expenses associated with its agreed-upon share of the removal and remedial investigation and feasibility study costs for the Brunswick site. Additional claims for recovery of

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natural resource damages at the site are anticipated. Georgia Power has also recognized $35 million in cumulative expenses through December 31, 2004 for the assessment and anticipated cleanup of other sites on the Georgia Hazardous Sites Inventory.

     Under Georgia PSC ratemaking provisions, $22 million has been deferred in a regulatory liability account for use in meeting future environmental remediation costs at Georgia Power. Under the December 2004 three-year retail rate plan ending December 31, 2007 (2004 Retail Rate Plan), this regulatory liability will be amortized over a three-year period beginning January 1, 2005. However, the order also approved an annual environmental accrual of $5.4 million. Environmental remediation expenditures will be charged against the reserve as they are incurred. The annual accrual amount will be reviewed and adjusted in future regulatory proceedings.

     In September 2004, Gulf Power increased its liability and related regulatory asset for the estimated costs of environmental remediation projects by approximately $47 million to $59.8 million. This increase relates to new regulations and more stringent site closure criteria by the Florida Department of Environmental Protection (FDEP) for impacts to soil and groundwater from herbicide applications at Gulf Power substations. The schedule for completion of these remediation projects will be subject to FDEP approval.

     The final outcome of the Georgia Power and Gulf Power matters cannot now be determined. However, based on the currently known conditions at these sites and the nature and extent of activities relating to these sites, management does not believe that additional liabilities, if any, at these sites would be material to the financial statements.

Generation Interconnection Agreements

In July 2003, the FERC issued its final rule on the standardization of generation interconnection agreements and procedures (Order 2003). Order 2003 shifts much of the financial burden of new transmission investment from the generator to the transmission provider. The FERC has indicated that Order 2003, which was effective January 20, 2004, is to be applied prospectively to interconnection agreements. Subsidiaries of Tenaska, Inc., as counterparties to three previously executed interconnection agreements with subsidiaries of Southern Company, have filed complaints at the FERC requesting that the FERC modify the agreements and that Southern Company refund a total of $19 million previously paid for interconnection facilities, with interest. Southern Company has also received similar requests from other entities totaling $9 million. Southern Company has opposed such relief, and the proceedings are still pending. The impact of Order 2003 and its subsequent rehearings on Southern Company and the final results of these matters cannot be determined at this time.

Market-Based Rate Authority

Each of the retail operating companies and Southern Power has authorization from the FERC to sell power to nonaffiliates at market-based prices. The retail operating companies and Southern Power 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, the retail operating companies, and Southern Power, and found Southern Company and others to be “pivotal suppliers” in their retail service territories 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.

     In April 2004, the FERC issued an order that abandoned the SMA test and adopted a new interim analysis for measuring generation market power. This new interim approach requires utilities to submit a pivotal supplier screen and a wholesale market share screen. If the applicant does not pass both screens, there will be a rebuttable presumption regarding generation market power. The FERC’s order also sets forth procedures for rebutting these presumptions and addresses mitigation measures for those entities that are found to have market power. In the absence of specific mitigation measures, the order includes several cost-based mitigation measures that would apply by default. The FERC also initiated a new rulemaking proceeding that, among other things, will adopt a final methodology for assessing generation market power.

     In July 2004, the FERC denied Southern Company’s request for rehearing, along with a

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number of others, and reaffirmed the interim tests that it adopted in April 2004. In August 2004, Southern Company submitted a filing to the FERC that included results showing that Southern Company passed the pivotal supplier screen for all markets and the wholesale market share screen for all markets except the Southern Company retail service territory. Southern Company also submitted other analyses to demonstrate that it lacks generation market power. On December 17, 2004, the FERC initiated a proceeding to assess Southern Company’s generation dominance within its retail service territory. The ability to charge market-based rates in other markets is not at issue. As directed by this order, Southern Company submitted additional information on February 15, 2005 related to generation dominance in its retail service territory. Any new market-based rate transactions in its retail service territory entered into after February 27, 2005 will be subject to refund to the level of the default cost-based rates, pending the outcome of the proceeding. Southern Company, along with other utilities, has also filed an appeal of the FERC’s April and July 2004 orders with the U.S. Court of Appeals for the District of Columbia Circuit. The FERC has asked the court to dismiss the appeal on the grounds that it is premature.

     In the event that the FERC’s default mitigation measures are ultimately applied, Southern Power and the retail operating companies may be required to charge cost-based rates for certain wholesale sales in the retail service territory, which may be lower than negotiated market-based rates. The final outcome of this matter will depend on the form in which the final methodology for assessing generation market power and mitigation rules may be ultimately adopted and cannot be determined at this time.

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 U.S. Court of Appeals for the Eleventh Circuit subsequently denied plaintiffs’ petition seeking permission to file an appeal of the October 2001 decision. In March 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. In April 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. On November 10, 2004, a three-judge panel of the U.S. Court of Appeals for the Eleventh Circuit issued an order affirming in all respects the district court’s rulings. On December 1, 2004, the plaintiffs filed a petition for rehearing seeking a review of the November 2004 order by the entire Eleventh Circuit panel of judges. If this petition is denied, the plaintiffs will have 90 days from the date of the court’s order denying the petition to file a petition for writ of certiorari to the U.S. Supreme Court. 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, have been named as defendants in numerous lawsuits brought by landowners since 2001. 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 exceed the easements or other property rights held by defendants. The plaintiffs assert claims for, among other things, trespass and unjust enrichment and seek compensatory and punitive damages and injunctive relief. Management of Southern Company and its subsidiaries believe that they 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 November 2003, the Second Circuit Court in Gadsden County, Florida, ruled in favor of the plaintiffs on their motion for partial summary judgment concerning liability in 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. Subsequently, the plaintiffs sought to amend their complaint and asked the court to enter a final declaratory judgment and to enter an order enjoining Gulf Power from allowing expanded general telecommunications use of the fiber optic cables that

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are the subject of this litigation. On January 6, 2005, the trial judge entered an order granting in part the plaintiffs’ motion to amend their complaint and denying the requested declaratory and injunctive relief at this time. On January 14, 2005, the Superior Court of Decatur County, Georgia, granted partial summary judgment in another such lawsuit brought by landowners against Georgia Power on the plaintiffs’ declaratory judgment claim that the easements do not permit general telecommunications use. Georgia Power is appealing this ruling to the Georgia Court of Appeals. The court also dismissed Southern Telecom from this case. The question of damages and other liability or remedies issues with respect to these actions, if any, will be decided at future trials. In the event of an adverse verdict in either case, Gulf Power or Georgia Power, as applicable, could appeal the issues of both liability and damages or other relief granted. With respect to approximately one-third of the plaintiffs in the actions pending against Mississippi Power, Mississippi Power has entered into an agreement with plaintiffs’ counsel clarifying Mississippi Power’s easement rights. This agreement has been approved by the Circuit Court of Harrison County, Mississippi (First Judicial District) and dismissals of the related cases are in progress.

     In addition, in late 2001, certain subsidiaries of Southern Company, including Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric, and Southern Telecom, 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 it in pending and future right of way litigation. The Company believes that the plaintiff’s claims are without merit. In the fall of 2004, the trial court stayed the case until resolution of the underlying landowner litigation discussed above. On January 12, 2005, the Georgia Court of Appeals dismissed the telecommunications company’s appeal of the trial court’s order for lack of jurisdiction. 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 Matters

Synthetic Fuel Tax Credits

Southern Company has investments in two entities that produce synthetic fuel and receive tax credits under Section 29 of the Internal Revenue Code — a 30 percent ownership interest in Alabama Fuel Products (AFP) and a 24.975 percent limited partnership interest in Carbontronics Synfuels Investors, L.P. (Carbontronics). At December 31, 2004, Southern Company’s total investment in these entities was approximately $29 million.

     In June 2003, the IRS completed 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 and announced that it has 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 required taxpayers applying for future rulings, as well as those already holding rulings, to implement and maintain certain sampling and quality control procedures, as well as additional documentation and record retention procedures. Both AFP and Carbontronics 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 independent laboratories and experts to test for chemical change. These tests replicated significant chemical changes consistent with the procedures submitted with the private letter rulings.

     In October 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. There has been no significant activity related to this investigation to date.

     In January 2004, the IRS completed an audit of AFP for tax years 1999 and 2000. In December 2004, the IRS notified Carbontronics that its audit for 2000 and 2001 had been completed. In addition,

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in December 2004, the IRS also concluded its audit of Southern Company’s consolidated income tax returns for 2000 and 2001. The IRS raised no issues related to synthetic fuel tax credits upon conclusion of any of these audits. As a result, in December 2004, Southern Company reversed its related reserve of $37 million.

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 2001. As part of the audit for the 1996-1999 tax years, the IRS proposed to disallow the tax losses associated with Southern Company’s lease-in-lease-out (LILO) transaction, resulting in an additional tax payment of approximately $30 million, including approximately $6.5 million of interest. To stop interest accretion, Southern Company deposited this payment with the IRS in May 2003 and filed a refund claim. In January 2004, the IRS proposed to disallow the refund claim. In connection with its audit of 2000 and 2001, the IRS proposed a similar assessment of approximately $18 million, including approximately $3 million of interest. In October 2004, Southern Company submitted the issue to the IRS appeals division and in February 2005 reached a negotiated settlement with the IRS. The settlement had no material impact on Southern Company’s financial statements.

     In connection with its audit of 2000 and 2001, the IRS has also challenged Southern Company’s deductions related to three other international lease transactions (so-called SILO or sale-in-lease-out transactions). Southern Company believes that these transactions are valid leases for U.S. tax purposes and is pursuing resolution with the IRS. If the IRS is ultimately successful in disallowing the tax deductions related to these three transactions, beginning with the 2000 tax year, Southern Company could be subject to additional interest charges of up to $20 million. Additionally, although the payment of the tax liability, exclusive of this interest, would not affect Southern Company’s results of operations under current accounting standards, it could have a material impact on cash flow. See Note 1 under “Leveraged Leases” for additional information on deferred taxes arising from these transactions. Furthermore, the FASB is currently considering changes to the accounting for income tax settlements related to leveraged leases, which may result in a net income impact from such settlements. The final outcome of these matters cannot now be determined.

Alabama Power Retail Regulatory Matters

Alabama Power operates under a Rate Stabilization and Equalization plan (Rate RSE) originally adopted by the Alabama PSC in November 1982. Rate RSE provides for periodic annual adjustments based upon Alabama Power’s earned return on end-of-period retail common equity. Such annual adjustments are limited to 3 percent. Within a range of return on common equity of 13 percent to 14.5 percent, rates remain unchanged. The Alabama PSC has also approved a rate mechanism that provides 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 (Rate CNP). Both increases and decreases have been placed into effect since the adoption of these rates.

     In accordance with Rate RSE, a 2 percent increase in retail rates was effective in April 2002, amounting to an annual increase of $55 million. Also, to recover certificated purchased power costs under Rate CNP, an increase of 2.6 percent in retail rates, or $79 million annually, was effective July 2003. An additional increase of $25 million annually was effective in June 2004 under Rate CNP for new certificated purchased power costs. In April 2005, an annual true-up adjustment to Rate CNP is expected to decrease retail rates by approximately 0.5 percent or $18.5 million annually.

     In October 2004, the Alabama PSC approved a request by Alabama Power to amend Rate CNP to also provide for the recovery of retail costs associated with environmental laws and regulations, effective in January 2005. In conjunction with the Alabama PSC’s approval, Alabama Power agreed to a moratorium until March 2007 on any retail rate increase under the Rate RSE. Any increase in March 2007 would be based upon the earned return on retail common equity at December 31, 2006. The ratemaking procedures will remain in effect until the Alabama PSC votes to modify or discontinue them.

     Alabama Power fuel costs are recovered under Rate ECR (Energy Cost Recovery), which provides for the addition of a fuel and energy cost factor to base rates. In April 2005, this factor is scheduled to increase from its current level.

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Georgia Power Retail Rate Activity

On December 21, 2004, the Georgia PSC voted to approve the 2004 Retail Rate Plan for Georgia Power. Under the terms of the 2004 Retail Rate Plan, earnings will be evaluated against a retail return on common equity range of 10.25 percent to 12.25 percent. Two-thirds of any earnings above 12.25 percent will be applied to rate refunds, with the remaining one-third retained by Georgia Power. Retail rates and customer fees will be increased by approximately $203 million effective January 1, 2005 to cover the higher costs of purchased power, operating and maintenance expenses, environmental compliance, and continued investment in new generation, transmission, and distribution facilities to support growth and ensure reliability.

     Georgia Power will not file for a general base rate increase unless its projected retail return on common equity falls below 10.25 percent. Georgia Power is required to file a general rate case by July 1, 2007, in response to which the Georgia PSC would be expected to determine whether the rate order should be continued, modified, or discontinued.

     In December 2001, the Georgia PSC approved a three-year retail rate plan (2001 Retail Rate Plan) for Georgia Power ending December 31, 2004. Under the terms of the 2001 Retail Rate Plan, earnings were evaluated against a retail return on common equity range of 10 percent to 12.95 percent. Georgia Power’s earnings in all three years were within the common equity range. Under the 2001 Retail Rate Plan, Georgia Power amortized a regulatory liability of $333 million, related to previously recorded accelerated amortization expenses, equally over three years beginning in 2002. Also, the 2001 Retail Rate Plan 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.

     On February 18, 2005, Georgia Power filed a request with the Georgia PSC for a fuel cost recovery rate increase. The requested increase, representing an average annual increase in revenues of approximately 11.7 percent, will allow for the recovery of fuel costs based on an estimate of future fuel costs, as well as the collection of the existing under recovery of fuel costs. Georgia Power’s under recovered fuel costs as of January 31, 2005 totaled $390 million. The Georgia PSC will examine Georgia Power’s fuel expenditures and determine whether the proposed fuel cost recovery rate is just and reasonable before issuing its decision in May 2005. The final outcome of the filing cannot be determined at this time.

Gulf Power and Alabama Power Storm Damage Recovery

In September 2004, Hurricane Ivan hit the Gulf Coast of Florida and Alabama and continued north through Southern Company’s service territory causing substantial damage. At Gulf Power, the related costs charged to its property damage reserve were $141.5 million, resulting in a negative reserve balance of $96.5 million at December 31, 2004. At Alabama Power, the related costs charged to its natural disaster reserve were $57.8 million, resulting in a negative reserve balance of $37.7 million at December 31, 2004, which is reflected in the balance sheet as a regulatory asset pursuant to Alabama PSC order. See Note 1 under “Storm Damage Reserves” for additional information on these reserves.

     In February 2005, the Citizens of the State of Florida through the Office of Public Counsel for the State of Florida, the Florida Industrial Power Users Group, and Gulf Power filed a Stipulation and Settlement with the Florida PSC that, if approved, would allow Gulf Power to recover the retail portion of $51.7 million of these costs, plus interest and revenue taxes, from customers over a 24-month period. In connection with the stipulation, Gulf Power has agreed that it will not seek any additional increase in its base rates and charges to become effective on or before March 1, 2007.

     Also in February 2005, Alabama Power requested and received Alabama PSC approval of an accounting order that allows Alabama Power to immediately return certain regulatory liabilities to its retail customers. The order also allows Alabama Power to simultaneously recover from its customers an accrual of approximately $45 million to offset the costs of Hurricane Ivan and restore the natural disaster reserve. The combined effects of this order will have no impact on Alabama Power’s net income in 2005.

Plant McIntosh Construction Project

In December 2002, after a competitive bidding process, the Georgia PSC certified purchased power agreements (PPAs) between Southern Power and Georgia Power and Savannah Electric for capacity from Plant McIntosh units 10 and 11, construction of which is scheduled to be completed in June 2005. In

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April 2003, Southern Power applied for FERC approval of these PPAs. In July 2003, the FERC accepted the PPAs to become effective June 1, 2005, subject to refund, and ordered that hearings be held. Intervenors opposed the FERC’s acceptance of the PPAs, alleging that they did not meet the applicable standards for market-based rates between affiliates. To ensure the timely completion of the Plant McIntosh construction project and the availability of the units in the summer of 2005 for their retail customers, Savannah Electric and Georgia Power in May 2004 requested the Georgia PSC to direct them to acquire the Plant McIntosh construction project. The Georgia PSC issued such an order, and the transfer occurred on May 24, 2004 at a total cost of approximately $415 million, including $14 million of transmission interconnection facilities. Subsequently, Southern Power filed a request to withdraw the PPAs and to terminate the ongoing FERC proceedings. In August 2004, the FERC issued a notice accepting the request to withdraw the PPAs and permitting such request to become effective by operation of law. However, the FERC made no determination on what additional steps may need to be taken with respect to testimony provided in the proceedings. The ultimate outcome of any additional FERC action cannot now be determined.

     As directed by the Georgia PSC order, Georgia Power and Savannah Electric in June 2004 filed an application to amend the resource certificate granted by the Georgia PSC in 2002. In connection with the 2004 Retail Rate Plan, the Georgia PSC approved the transfer of the Plant McIntosh construction project at a total fair market value of approximately $385 million. This value reflects an approximate $16 million disallowance and reduced Southern Company’s net income by approximately $9.5 million. The Georgia PSC also certified a total completion cost of $547 million for the project. The amount of the disallowance will be adjusted accordingly based on the actual completion cost of the project. Under the 2004 Retail Rate Plan, the Plant McIntosh impact will be reflected in Georgia Power’s rates evenly over the three years ending 2007. See “Georgia Power Retail Rate Activity” above for additional information on the 2004 Retail Rate Plan.

Plant Franklin Construction Project

Southern Power completed 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, 2004, Southern Power’s investment in Unit 3 of Plant Franklin was $172 million. The final 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, 2004, 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 %   $ 3,304     $ 1,756  
Plant Hatch (nuclear)
    50.1       932       485  
Plant Miller (coal) Units 1 and 2
    91.8       776       356  
Plant Scherer (coal) Units 1 and 2
    8.4       114       53  
Plant Wansley (coal)
    53.5       394       164  
Rocky Mountain (pumped storage)
    25.4       169       89  
Intercession City (combustion turbine)
    33.3       12       2  
Plant Stanton (combined cycle) Unit A
    65.0       156       6  
 

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     Alabama Power, Georgia Power, and Southern Power have contracted to operate and maintain the jointly owned facilities — except for Rocky Mountain 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 statements of income.

5. INCOME TAXES

Southern Company files a consolidated federal income tax return and a combined State of Georgia income tax return. Under a joint consolidated income tax allocation agreement, as required by the PUHCA, 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. In December 2004, the IRS concluded its audit for the tax years 2000 and 2001, and Southern Company paid $39 million in additional tax and interest for issues related to Mirant tax items. Under the terms of the separation agreements, Mirant agreed to indemnify Southern Company for subsequent assessment of any additional taxes related to its transactions prior to the spin off. However, as a result of Mirant’s bankruptcy, Southern Company must seek reimbursement as an unsecured creditor. For additional information, see Note 3 under “Mirant Related Matters — Mirant Bankruptcy.”

     At December 31, 2004, the tax-related regulatory assets and liabilities were $865 million and $374 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:

                         
    2004     2003     2002  
 
    (in millions)  
Total provision for income taxes:
                       
Federal —
                       
Current
  $ 14     $ 141     $ 284  
Deferred
    482       393       167  
 
 
    496       534       451  
 
State —
                       
Current
    15       44       64  
Deferred
    76       34       13  
 
 
    91       78       77  
 
Total
  $ 587     $ 612     $ 528  
 

     Net cash payments for income taxes in 2004, 2003, and 2002 were $78 million, $189 million, and $374 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:

                 
    2004     2003  
 
    (in millions)  
Deferred tax liabilities:
               
Accelerated depreciation
  $ 4,252     $ 3,854  
Property basis differences
    1,047       1,035  
Leveraged lease basis differences
    447       351  
Employee benefit obligations
    305       283  
Under recovered fuel clause
    209       70  
Premium on reacquired debt
    132       133  
Other
    195       165  
 
Total
    6,587       5,891  
 
Deferred tax assets:
               
Federal effect of state deferred taxes
    246       220  
State effect of federal deferred taxes
    111       99  
Employee benefit obligations
    190       161  
Other property basis differences
    162       171  
Deferred costs
    105       128  
Alternative minimum tax carryforward
    106        
Other
    386       436  
 
Total
    1,306       1,215  
 
Total deferred tax liabilities, net
    5,281       4,676  
Portion included in prepaid expenses (accrued income taxes), net
    (57 )     150  
Deferred state tax assets
    13       11  
 
Accumulated deferred income taxes in the balance sheets
  $ 5,237     $ 4,837  
 

     At December 31, 2004, 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 $59 million, if utilized. These deductions will expire between 2010 and 2021. During 2004, Southern Company realized $10 million in such state income tax benefits. Beginning in 2002, the State of Georgia allowed 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 statements of income. Credits amortized in this manner amounted to $27 million in 2004, $29 million in 2003, and $27 million in 2002. At December 31, 2004, all investment tax credits

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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:

                         
          2004         2003         2002
 
Federal statutory rate
    35.0 %     35.0 %     35.0 %
State income tax, net of federal deduction
    2.8       2.4       2.7  
Synthetic fuel tax credits
    (8.5 )     (5.7 )     (5.8 )
Employee stock plans dividend deduction
    (1.5 )     (1.5 )     (2.9 )
Non-deductible book depreciation
    1.1       1.1       1.3  
Difference in prior years’ deferred and current tax rate
    (0.7 )     (0.7 )     (1.0 )
Other
    (0.9 )     (1.5 )     (0.9 )
 
Effective income tax rate
    27.3 %     29.1 %     28.4 %
 

6. FINANCING

Mandatorily Redeemable Preferred Securities/Long-Term Debt Payable to Affiliated Trusts

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 substantially all assets of these trusts and are reflected on the balance sheets as Long-term Debt Payable to Affiliated Trusts. Southern Company and the retail operating companies each consider 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, 2004, preferred securities of $1.9 billion were outstanding. Southern Company guarantees the notes related to $574 million of these securities issued on its behalf. See Note 1 under “Variable Interest Entities” for additional information on the accounting treatment for these trusts and the related securities.

Long-Term Debt Due Within One Year

A summary of scheduled maturities and redemptions of long-term debt due within one year at December 31 is as follows:

                 
    2004     2003  
 
    (in millions)  
Capitalized leases
  $ 12     $ 11  
Senior notes
    675       655  
Other long-term debt
    296       35  
 
Total
  $ 983     $ 701  
 

     Debt redemptions and/or serial maturities through 2009 applicable to total long-term debt are as follows: $983 million in 2005; $967 million in 2006; $1.3 billion in 2007; $476 million in 2008, and $624 million in 2009.

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 retail operating 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 2005, unused credit arrangements with banks totaled $3.2 billion, of which $1.8 billion expires during 2005 and $1.4 billion expires during 2006 and beyond. The following table outlines the credit arrangements by company:

                                 
    Amount of Credit     Expires  
                            2006 &  
Company   Total     Unused     2005     beyond  
 
            (in millions)        
Alabama Power
  $ 868     $ 868     $ 643     $ 225  
Georgia Power
    773       773       423       350  
Gulf Power
    57       57       57        
Mississippi Power
    101       101       101        
Savannah Electric
    80       80       70       10  
Southern Company
    1,000       1,000       500       500  
Southern Power
    325       325             325  
Other
    30       30       30        
 
Total
  $ 3,234     $ 3,234     $ 1,824     $ 1,410  
 

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     Approximately $1.2 billion of the credit facilities expiring in 2005 allow the execution of term loans for an additional two-year period, and $275 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 one-eighth of 1 percent for Southern Company and the retail operating companies and less than three-eighths of 1 percent for Southern Power. Compensating balances are not legally restricted from withdrawal. Included in the total $3.2 billion of unused credit arrangements is $2.5 billion of syndicated credit arrangements that require the payment of agent fees.

     Most of the credit arrangements with banks have covenants that limit debt levels to 65 percent of total capitalization, as defined in the agreements. For purposes of these definitions, debt excludes the long-term debt payable to affiliated trusts. At December 31, 2004, Southern Company, Southern Power, and the retail operating companies were each 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. Except for Southern Power, 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. Southern Power’s bank credit arrangements have a cross default to Southern Company’s indebtedness, which, if triggered, would require prepayment of debt related to projects financed under the credit arrangement that are not complete. Southern Company 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 $40 million would be prohibited if the borrower experiences a material adverse change, as defined in such arrangements. 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 $3.2 billion unused credit with banks is allocated to provide liquidity support to the retail operating companies’ variable rate pollution control bonds. The amount of variable rate pollution control bonds requiring liquidity support as of December 31, 2004 was $662 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. Southern Company and the retail operating companies may also borrow through extendible commercial note programs. The amount of commercial paper and extendible commercial notes outstanding and included in notes payable on the balance sheets at December 31, 2004 and December 31, 2003 was $377 million and $568 million, respectively. During 2004, the peak amount outstanding for commercial paper was $848 million, and the average amount outstanding was $511 million. The average annual interest rate on commercial paper was 1.3 percent in both 2004 and 2003.

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 state PSCs. 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, 2004, the fair value of derivative energy contracts was reflected in the financial statements as follows:

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    Amounts  
 
    (in millions)  
Regulatory liabilities, net
  $ 12.8  
Other comprehensive income
    (1.7 )
Net income
    (0.6 )
 
 
Total fair value
  $ 10.5  
 

     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 2004, 2003, and 2002, approximately $(3) million, $22 million, and $3 million, respectively, of pre-tax gains (losses) were reclassified from other comprehensive income to fuel expense. For the year 2005, approximately $3 million of pre-tax gains are expected to be reclassified from other comprehensive income to fuel expense. There was no significant ineffectiveness recorded in earnings for any period presented. Southern Company has energy-related hedges in place up to and including 2007.

     Southern Company and certain subsidiaries also enter into derivatives to hedge exposure to changes in interest rates. 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. As the derivatives employed as hedging instruments are generally structured to match the critical terms of the hedged debt instruments, no material ineffectiveness has been recorded in earnings.

     At December 31, 2004, Southern Company had $2.6 billion notional amount of interest rate swaps and options outstanding with net fair value gains of $12 million as follows:

Fair Value Hedges

                         
        Variable           Fair  
        Rate   Notional       Value  
Company   Maturity   Paid   Amount       Gain  
 
            (in millions)  
Southern Company
  2007   6-month   $ 400     $ 17.1  
 
      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)  
Alabama Power
  2007   2.01*   $ 536     $ 5.6  
 
  2006   1.89     195       3.2  
 
  2035   5.68     250       (16.0 )
 
                       
Georgia Power
  2005   1.96     250       0.3  
 
  2005   1.56     50       0.1  
 
  2015   4.66     250       0.7  
 
  2015   5.03     100       (0.9 )
 
  2006   6.00**     150       (0.1 )
 
  2005-07   2.35-3.85***     400       0.6  
 
                       
Savannah Electric
  2007   2.50*     14       0.1  


*   Hedged using the Bond Market Association Municipal Swap Index.
 
**   Costless collar with cap rate of 6.00 percent.
 
***   Capped rate based on formula approximating the yield on tax-exempt auction rate securities.

     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 2004, 2003, and 2002, the Company settled losses of $7 million, $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 original interest derivative. For 2004, 2003, and 2002, approximately $23 million, $26 million, and $6 million, respectively, of pre-tax losses were reclassified from other comprehensive income to interest expense. For 2005, pre-tax losses of approximately $11 million are expected to be reclassified from other comprehensive income to interest expense. The Company has interest-related hedges in place through 2035.

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7. COMMITMENTS

Construction Program

Southern Company is engaged in continuous construction programs, currently estimated to total $2.2 billion in 2005, $2.5 billion in 2006, and $3.2 billion in 2007. These amounts include $64 million, $45 million, and $39 million in 2005, 2006, and 2007, respectively, for construction expenditures related to contractual purchase commitments for uranium and nuclear fuel conversion, enrichment, and fabrication services included herein 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, 2004, 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 during 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. The LTSAs stipulate that GE will perform all planned inspections on the covered equipment, which includes the cost of all labor and materials. GE is also obligated to cover the costs of unplanned maintenance on the covered equipment subject to a limit specified in each contract.

     In general, except for Southern Power’s Plant Dahlberg, these LTSAs are in effect through two major inspection cycles per unit. The Dahlberg agreement is in effect through the first major inspection of each unit. Scheduled payments to GE are made at various intervals based on actual operating hours of the respective units. Total payments to GE under these agreements for facilities owned are currently estimated at $1.4 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.

     In December 2004, Georgia Power entered into a LTSA with GE for blanket coverage of neutron monitoring system parts and electronics at Plant Hatch. GE will be responsible for parts and service for 10 years. Total payments under the agreement are estimated at $14 million. The contract contains cancellation provisions at the option of Georgia Power.

     Payments made to GE prior to the performance of any planned inspections are recorded as a prepayment in the balance sheets. Inspection costs are capitalized or charged to expense based on the nature of the work performed.

Fuel 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. Coal commitments include forward contract purchases for sulfur dioxide emission allowances. 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 Exchange future prices at December 31, 2004. Also, Southern Company has entered into various long-term commitments for the purchase of electricity. Total estimated minimum long-term obligations at December 31, 2004 were as follows:

                         
            Coal and        
    Natural     Nuclear     Purchased  
Year   Gas     Fuel     Power  
 
(in millions)  
2005
  $ 747     $ 3,135     $ 171  
2006
    635       2,652       178  
2007
    398       1,922       179  
2008
    303       777       181  
2009
    290       349       161  
2010 and thereafter
    2,678       193       680  
 
Total commitments
  $ 5,051     $ 9,028     $ 1,550  
 

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Southern Company and Subsidiary Companies 2004 Annual Report

     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 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. In 2003, approximately $11 million in lease termination costs were also included in operation expenses. 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. 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. Mississippi Power is required to amortize approximately 4 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. A liability of approximately $13 million for the fair market value of this residual value guarantee is included in the balance sheet as of December 31, 2004.

     Southern Company also has other operating lease agreements with various terms and expiration dates. Total operating lease expenses were $156 million, $172 million, and $169 million for 2004, 2003, and 2002, respectively. At December 31, 2004, estimated minimum rental commitments for noncancelable operating leases were as follows:

                                 
    Plant     Rail              
Year   Daniel     Cars     Other     Total  
 
    (in millions)  
2005
  $ 29     $ 38     $ 56     $ 123  
2006
    29       35       42       106  
2007
    29       26       34       89  
2008
    29       25       27       81  
2009
    29       23       23       75  
2010 and thereafter
    56       98       105       259  
 
Total minimum payments
  $ 201     $ 245     $ 287     $ 733  
 

     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 leases with respect to the residual value of the leased property. These leases expire in 2006, 2009, and 2011, and the maximum obligations are $66 million, $19.5 million, and $72 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. The total notional amount of guarantees outstanding at December 31, 2004 is less than $20 million, all of which will expire by 2009.

     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.

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Southern Company and Subsidiary Companies 2004 Annual Report

8. COMMON STOCK

Stock Issued

Southern Company raised $124 million (7 million shares) in 2004 and $470 million (18 million shares) in 2003 from the issuance of new common shares under the Company’s various stock plans.

Shares Reserved

At December 31, 2004, a total of 39.2 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, 2004, 6,286 current and former employees participated in the stock option plan. The maximum number of shares of common stock that may be issued under this plan may not exceed 55 million. The prices of options granted to date have been at the fair market value of the shares on the dates of grant. Options granted to date become exercisable pro rata over a maximum period of three years from the date of grant. Options outstanding will expire no later than 10 years after the date of grant, unless terminated earlier by the Southern Company Board of Directors in accordance with the stock option plan. Activity from 2002 to 2004 for the stock option plan is summarized below:

                 
    Shares     Average  
    Subject     Option Price  
    To Option     Per Share  
 
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
    7,165,398       27.98  
Options canceled
    (181,381 )     24.37  
Options exercised
    (5,725,336 )     16.56  
 
Balance at December 31, 2003
    33,933,495       21.97  
Options granted
    7,231,703       29.49  
Options canceled
    (72,225 )     26.85  
Options exercised
    (6,557,690 )     18.11  
 
Balance at December 31, 2004
    34,535,283     $ 24.27  
 
Shares reserved for future grants:
               
At December 31, 2002
    46,788,994          
At December 31, 2003
    39,751,477          
At December 31, 2004
    32,583,523          
 
Options exercisable:
               
At December 31, 2002
    15,463,414          
At December 31, 2003
    18,874,426          
At December 31, 2004
    21,782,064          
 

     The following table summarizes information about options outstanding at December 31, 2004:

                         
    Dollar Price  
    Range of Options
    13-20     20-26     26-32  
 
Outstanding:
                       
Shares (in thousands)
    9,328       11,073       14,134  
Average remaining life (in years)
    4.5       6.2       8.1  
Average exercise price
  $ 17.51     $ 24.25     $ 28.75  
Exercisable:
                       
Shares (in thousands)
    9,328       8,918       3,536  
Average exercise price
  $ 17.51     $ 24.00     $ 28.26  
 

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
    2004     2003     2002  
 
    (in thousands)
As reported shares
    738,879       726,702       708,161  
Effect of options
    4,197       5,202       5,409  
 
Diluted shares
    743,076       731,904       713,570  
 

Common Stock Dividend Restrictions

The income of Southern Company is derived primarily from equity in earnings of its subsidiaries. At December 31, 2004, consolidated retained earnings included $4.1 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.

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Southern Company and Subsidiary Companies 2004 Annual Report

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 $10.76 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 the 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 $39 million and $43 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, which 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.

10. SEGMENT AND RELATED INFORMATION

Southern Company’s reportable business segment is the sale of electricity in the Southeast by the five

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Southern Company and Subsidiary Companies 2004 Annual Report

retail operating companies and Southern Power. 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. Southern Power’s revenues from sales to the retail operating companies were $425 million, $313 million, and $183 million in 2004, 2003, and 2002, respectively. In addition, see Note 1 under “Related Party Transactions” for information regarding revenues from services for synthetic fuel production that are included in the cost of fuel purchased by Alabama Power and Georgia Power. All other intersegment revenues are not material. Financial data for business segments and products and services are as follows:

Business Segment

                                                         
    Electric Utilities                    
    Retail                                          
    Operating     Southern                     All              
    Companies     Power     Eliminations     Total     Other     Eliminations     Consolidated  
 
    (in millions)  
2004
                                                       
Operating revenues
  $ 11,300     $ 701     $ (536 )   $ 11,465     $ 549     $ (112 )   $ 11,902  
Depreciation and amortization
    857       51             908       47             955  
Interest income
    24       1             25       4       (2 )     27  
Interest expense
    518       66             584       84       (1 )     667  
Income taxes
    802       73             875       (288 )           587  
Segment net income (loss)
    1,309       112             1,421       112       (1 )     1,532  
Total assets
    33,524       2,067       (103 )     35,488       1,996       (522 )     36,962  
Gross property additions
    2,318       116       (415 )     2,019       91             2,110  
 
                                                         
    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     $ (87 )   $ 11,186  
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
    31,506       2,409       (122 )     33,793       1,671       (286 )     35,178  
Gross property additions
    1,636       344             1,980       34             2,014  
 
                                                         
    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     $ (57 )   $ 10,514  
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
    1,784       1,215       (390 )     2,609       119             2,728  
 

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Southern Company and Subsidiary Companies 2004 Annual Report

Products and Services

                                 
    Electric Utilities Revenues
Year   Retail     Wholesale     Other     Total  
 
      (in millions)  
 
2004
  $ 9,732     $ 1,341     $ 392     $ 11,465  
2003
    8,875       1,358       514       10,747  
2002
    8,728       1,168       310       10,206  
 

11. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

Summarized quarterly financial data for 2004 and 2003 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 2004
  $ 2,732     $ 623     $ 331     $ 0.45     $ 0.3500     $ 30.87     $ 29.10  
June 2004
    3,009       695       352       0.48       0.3500       30.59       27.86  
September 2004
    3,441       1,113       645       0.87       0.3575       30.65       28.86  
December 2004
    2,720       396       204       0.28       0.3575       33.92       29.95  
 
                                                       
March 2003
  $ 2,541     $ 588     $ 298     $ 0.41     $ 0.3425     $ 30.81     $ 27.71  
June 2003
    2,824       781       432       0.60       0.3425       31.81       27.94  
September 2003
    3,301       1,095       619       0.85       0.3500       30.53       27.76  
December 2003
    2,520       341       125       0.17       0.3500       30.40       28.65  
 

Southern Company’s business is influenced by seasonal weather conditions.

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SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA 2000-2004
Southern Company and Subsidiary Companies 2004 Annual Report

                                         
 
    2004     2003     2002     2001     2000  
 
Operating Revenues (in millions)
  $ 11,902     $ 11,186     $ 10,514     $ 10,155     $ 10,066  
Total Assets (in millions)
  $ 36,962     $ 35,178     $ 33,721     $ 31,856     $ 33,282  
Gross Property Additions (in millions)
  $ 2,110     $ 2,014     $ 2,728     $ 2,617     $ 2,225  
Return on Average Common Equity (percent)
    15.38       16.05       15.79       13.51       13.20  
Cash Dividends Paid Per Share of Common Stock
  $ 1.415     $ 1.385     $ 1.355     $ 1.34     $ 1.34  
 
Consolidated Net Income (in millions):
                                       
Continuing operations
  $ 1,532     $ 1,474     $ 1,318     $ 1,120     $ 994  
Discontinued operations
                      142       319  
 
Total
  $ 1,532     $ 1,474     $ 1,318     $ 1,262     $ 1,313  
 
Earnings Per Share From Continuing Operations —
                                       
Basic
  $ 2.07     $ 2.03     $ 1.86     $ 1.62     $ 1.52  
Diluted
    2.06       2.02       1.85       1.61       1.52  
Earnings Per Share Including Discontinued Operations —
                                       
Basic
  $ 2.07     $ 2.03     $ 1.86     $ 1.83     $ 2.01  
Diluted
    2.06       2.02       1.85       1.82       2.01  
 
Capitalization (in millions):
                                       
Common stock equity
  $ 10,278     $ 9,648     $ 8,710     $ 7,984     $ 10,690  
Preferred stock
    561       423       298       368       368  
Mandatorily redeemable preferred securities
          1,900       2,380       2,276       2,246  
Long-term debt payable to affiliated trusts
    1,961                          
Long-term debt
    10,488       10,164       8,714       8,297       7,843  
 
Total excluding amounts due within one year
  $ 23,288     $ 22,135     $ 20,102     $ 18,925     $ 21,147  
 
Capitalization Ratios (percent):
                                       
Common stock equity
    44.1       43.6       43.3       42.2       50.6  
Preferred stock
    2.4       1.9       1.5       1.9       1.7  
Mandatorily redeemable preferred securities
          8.6       11.8       12.0       10.6  
Long-term debt payable to affiliated trusts
    8.4                          
Long-term debt
    45.1       45.9       43.4       43.9       37.1  
 
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)
  $ 13.86     $ 13.13     $ 12.16     $ 11.43     $ 15.69  
Market price per share (dollars):
                                       
High
  $ 33.920     $ 31.810     $ 30.850     $ 26.000     $ 35.000  
Low
    27.860       27.710       23.890       16.152       20.375  
Close
    33.520       30.250       28.390       25.350       33.250  
Market-to-book ratio (year-end) (percent)
    241.8       230.4       233.5       221.8       211.9  
Price-earnings ratio (year-end) (times)
    16.2       14.9       15.3       15.6       16.5  
Dividends paid (in millions)
  $ 1,044     $ 1,004     $ 958     $ 922     $ 873  
Dividend yield (year-end) (percent)
    4.2       4.6       4.8       5.3       4.0  
Dividend payout ratio (percent)
    68.2       68.1       72.8       82.4       66.5  
Shares outstanding (in thousands):
                                       
Average
    738,879       726,702       708,161       689,352       653,087  
Year-end
    741,495       734,829       716,402       698,344       681,158  
Stockholders of record (year-end)
    125,975       134,068       141,784       150,242       160,116  
 
Customers for Retail Operating Companies (year-end) (in thousands):
                                       
Residential
    3,600       3,552       3,496       3,441       3,398  
Commercial
    578       564       553       539       527  
Industrial
    14       14       14       14       14  
Other
    5       6       5       4       5  
 
Total
    4,197       4,136       4,068       3,998       3,944  
 

Note: Common stock data in 2001 declined as a result of the Mirant spin off.

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SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA 2000-2004 (continued)
Southern Company and Subsidiary Companies 2004 Annual Report

                                         
 
    2004     2003     2002     2001     2000  
 
Employees (year-end)
    25,642       25,762       26,178       26,122       26,021  
 
Operating Revenues (in millions):
                                       
Residential
  $ 3,848     $ 3,565     $ 3,556     $ 3,247     $ 3,361  
Commercial
    3,346       3,075       3,007       2,966       2,918  
Industrial
    2,446       2,146       2,078       2,144       2,289  
Other
    92       89       87       83       32  
 
Total retail
    9,732       8,875       8,728       8,440       8,600  
Sales for resale within service area
    504       444       443       338       377  
Sales for resale outside service area
    837       914       725       836       600  
 
Total revenues from sales of electricity
    11,073       10,233       9,896       9,614       9,577  
Other revenues
    829       953       618       541       489  
 
Total
  $ 11,902     $ 11,186     $ 10,514     $ 10,155     $ 10,066  
 
Kilowatt-Hour Sales (in millions):
                                       
Residential
    49,702       47,833       48,784       44,538       46,213  
Commercial
    50,037       48,372       48,250       46,939       46,249  
Industrial
    56,399       54,415       53,851       52,891       56,746  
Other
    1,005       998       1,000       977       970  
 
Total retail
    157,143       151,618       151,885       145,345       150,178  
Sales for resale within service area
    11,417       10,712       10,853       9,388       9,579  
Sales for resale outside service area
    23,822       29,808       21,698       21,380       17,190  
 
Total
    192,382       192,138       184,436       176,113       176,947  
 
Average Revenue per Kilowatt-Hour (cents):
                                       
Residential
    7.74       7.45       7.29       7.29       7.27  
Commercial
    6.69       6.36       6.23       6.32       6.31  
Industrial
    4.34       3.94       3.86       4.05       4.03  
Total retail
    6.19       5.85       5.75       5.81       5.73  
Sales for resale
    3.81       3.35       3.59       3.82       3.65  
Total sales
    5.76       5.33       5.37       5.46       5.41  
Average Annual Kilowatt-Hour Use per Residential Customer
    13,879       13,562       14,036       13,014       13,702  
Average Annual Revenue per Residential Customer
  $ 1,074     $ 1,011     $ 1,023     $ 949     $ 996  
Plant Nameplate Capacity Owned (year-end) (megawatts)
    38,622       38,679       36,353       34,579       32,807  
Maximum Peak-Hour Demand (megawatts):
                                       
Winter
    28,467       31,318       25,939       26,272       26,370  
Summer
    34,414       32,949       32,355       29,700       31,359  
System Reserve Margin (at peak) (percent)
    20.2       21.4       13.3       19.3       8.1  
Annual Load Factor (percent)
    61.4       62.0       51.1       62.0       60.2  
Plant Availability (percent):
                                       
Fossil-steam
    88.5       87.7       84.8       88.1       86.8  
Nuclear
    92.8       94.4       90.3       90.8       90.5  
 
Source of Energy Supply (percent):
                                       
Coal
    64.6       66.4       65.7       67.5       72.3  
Nuclear
    14.4       14.8       14.7       15.2       15.1  
Hydro
    2.9       3.8       2.6       2.6       1.5  
Oil and Gas
    10.9       8.8       11.4       8.4       4.0  
Purchased power
    7.2       6.2       5.6       6.3       7.1  
 
Total
    100.0       100.0       100.0       100.0       100.0  
 

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ALABAMA POWER COMPANY

 
 
 
FINANCIAL SECTION
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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, 2004 and 2003, 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, 2004. 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.

     We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (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 consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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 to II-118) present fairly, in all material respects, the financial position of Alabama Power Company at December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004, 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
February 28, 2005

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION
Alabama Power Company 2004 Annual Report

OVERVIEW

Business Activities

Alabama Power Company (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.

     Many factors affect the opportunities, challenges, and risks 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 more stringent environmental standards.

     On September 15 and 16, 2004, Hurricane Ivan hit the Gulf Coast of Florida and Alabama and continued north through the state of Alabama, causing substantial damage in the service territory of the Company. Approximately 826,000 of the Company’s 1,370,000 customer accounts were without electrical service immediately after the hurricane. Almost 95% of those without power had service restored within one week, and two weeks after the storm, power had been restored to all who could receive service.

     In 2004, the Company completed a retail rate proceeding that should help enable the recovery of substantial capital investments associated with environmental improvements.

Key Performance Indicators

In striving to maximize shareholder value while providing low-cost energy to nearly 1.4 million customers, the Company focuses on several key indicators. These indicators include customer satisfaction, peak season equivalent forced outage rate (Peak Season EFOR), and return on equity (ROE). The Company’s financial success is directly tied to the satisfaction of its customers. Key elements of ensuring customer satisfaction include outstanding service, high reliability, and competitive prices. Management uses nationally recognized customer satisfaction surveys and reliability indicators to evaluate the Company’s results. Peak Season EFOR is an indicator of plant availability and efficient generation fleet operations during the months when generation needs are greatest. The rate is calculated by dividing the number of hours of forced outages by total generation hours. ROE is a performance standard used by both the investment community and many regulatory agencies. The Company’s 2004 results compared with its targets for each of these indicators are reflected in the following chart.

                         
 
  Key     2004     2004  
  Performance     Target     Actual  
  Indicator     Performance     Performance  
 
Customer
Satisfaction
    Top quartile in national and regional surveys     Top quartile  
 
Peak Season
EFOR
    2.81% or less       1.86 %  
 
ROE
      13.50 %       13.53 %  
 

     The strong financial performance achieved in 2004 reflects the focus that management places on these indicators, as well as the commitment shown by the Company’s employees in achieving or exceeding management’s expectations.

Earnings

The Company’s 2004 net income after dividends on preferred stock was $481 million, representing an $8 million (1.8 percent) increase from the prior year. This improvement is due primarily to higher retail sales, increases in other revenues, and lower interest expense, partially offset by higher non-fuel operating expenses.

     The 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 was due primarily to higher retail sales, 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.

     The return on average common equity for 2004 was 13.53 percent compared to 13.75 percent in 2003 and 13.80 percent in 2002.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2004 Annual Report

RESULTS OF OPERATIONS

A condensed income statement is as follows:

                                 
            Increase (Decrease)  
    Amount   From Prior Year  
    2004     2004     2003     2002  
            (in millions)          
Operating revenues
  $ 4,236     $ 276     $ 250     $ 124  
 
Fuel
    1,187       119       98       (31 )
Purchased power
    413       98       66       (44 )
Other operation and maintenance
    947       26       67       71  
Depreciation and amortization
    426       13       15       15  
Taxes other than income taxes
    243       14       11       2  
 
Total operating expenses
    3,216       270       257       13  
 
Operating income
    1,020       6       (7 )     111  
Total other income and (expense)
    (202 )     30       20       6  
Income taxes
    313       23       (2 )     44  
 
Net income
    505       13       15       73  
Dividends on preferred stock
    24       5       3       (1 )
 
Net income after dividends on preferred stock
  $ 481     $ 8     $ 12     $ 74  
 

Revenues

Operating revenues for 2004 were $4.2 billion, reflecting a $276 million increase from 2003. The following table summarizes the principal factors that have affected operating revenues for the past three years:

                         
    Amount  
    2004     2003     2002  
    (in millions)  
Retail — prior year
  $ 3,051     $ 2,951     $ 2,748  
Change in -
                       
Base rates
    41       51       76  
Sales growth
    48       68       70  
Weather
    12       (61 )     60  
Fuel cost recovery and other
    141       42       (3 )
 
Retail — current year
    3,293       3,051       2,951  
 
Sales for resale —
                       
Non-affiliates
    484       488       474  
Affiliates
    308       277       188  
 
Total sales for resale
    792       765       662  
 
Other operating revenues
    151       144       97  
 
Total operating revenues
  $ 4,236     $ 3,960     $ 3,710  
 
Percent change
    7.0 %     6.7 %     3.5 %
 

     Retail revenues in 2004 were $3.3 billion. Revenues increased $242 million (7.9 percent) from the prior year, increased $100 million (3.4 percent) in 2003, and increased $203 million (7.4 percent) in 2002. All sectors of retail revenues increased $68 million (3.7 percent) for the Company in 2004. These 2004 and 2003 increases were primarily due to increased fuel revenue and 2.6 percent and 0.8 percent increases in retail base rates which went into effect in July 2003 and July 2004, respectively. 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 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.

     Fuel rates billed to customers are designed to fully recover fluctuating fuel and purchased power costs over a period of time. At December 31, 2004, the Company had $102 million of unrecovered fuel costs. Fuel revenues generally have no effect on net income because they represent the recording of revenues to offset fuel and purchased power 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:

                         
    2004     2003     2002  
    (in thousands)  
Unit power -
                       
Capacity
  $ 134,615     $ 130,022     $ 119,193  
Energy
    146,809       145,342       134,051  
 
Total
  $ 281,424     $ 275,364     $ 253,244  
 

     No significant declines in the amount of capacity are scheduled until the termination of the 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 based rates that generally provide a margin above the Company’s variable cost to produce

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2004 Annual Report

the energy. Revenues associated with other power sales to non-affiliates were as follows:

                         
    2004     2003     2002  
    (in thousands)  
Other power sales -
                       
Capacity and other
  $ 90,673     $ 96,263     $ 81,884  
Variable cost of energy
    111,742       115,829       139,162  
 
Total
  $ 202,415     $ 212,092     $ 221,046  
 

     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. These affiliated sales and purchases are made in accordance with the affiliated company interchange agreements as approved by the Federal Energy Regulatory Commission (FERC). In 2004, sales for resale revenues increased $31 million primarily due to increases in fuel-related expenses. Sales for resale revenues increased $89.1 million in 2003 due to increased capacity payments received from affiliates. 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 2004 increased $7.0 million (4.9 percent) from 2003 due to an increase of $7.7 million in revenues from gas-fueled co-generation steam facilities — primarily as a result of higher gas prices – and a $2.4 million increase in revenues from rent from electric property offset by a $2.0 million decrease in transmission revenues. Since co-generation steam revenues are generally offset by fuel expense, these revenues did not have a significant impact on earnings.

     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.

     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.

Energy Sales

Changes in revenues are influenced heavily by the volume of energy sold each year. Kilowatt-hour (KWH) sales for 2004 and the percent change by year were as follows:

                                 
    KWH     Percent Change  
    2004     2004     2003     2002  
    (millions)                          
 
                               
Residential
    17,368       2.4 %     (2.5 )%     9.6 %
Commercial
    13,823       2.8       0.7       4.4  
Industrial
    22,855       5.8       2.3       3.1  
Other
    198       (2.4 )     (1.1 )     3.7  
 
                             
Total retail
    54,244       3.9       0.3       5.5  
Sales for resale-
                               
Non-affiliates
    15,483       (9.4 )     9.9       1.8  
Affiliates
    7,234       (23.2 )     6.5        
 
                             
Total
    76,961       (2.2 )     2.9       4.1  
 

     Energy sales in the residential sector grew by 2.4 percent in 2004 due primarily to continued customer growth and a return to normal summer temperatures. Commercial sales increased 2.8 percent in 2004 primarily due to the State of Alabama’s continuing transition from a manufacturing-based economy to a more service-based economy. Industrial sales rebounded 5.8 percent during the year with primary metal, chemical, and paper sectors leading the growth.

     In 2003, residential energy sales 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.

     Assuming normal weather, sales to retail customers are projected to grow approximately 1.7 percent annually on average during 2005 through 2009.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2004 Annual Report

Expenses

Total operating expenses in 2004 grew $270 million (9.2 percent) to $3.2 billion. This increase over the previous year was primarily related to an increase in natural gas and coal prices. In addition, purchased power expenses increased $98 million (31.0 percent) primarily due to a 71.7 percent increase in energy purchased, while purchased power prices decreased by 1.9 percent. Depreciation and amortization expense increased $13 million (3.1 percent) primarily due to an increase in utility plant in service.

     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.

     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 kilowatt-hour (KWH) generated and the average cost of purchased power were as follows:

                         
    2004     2003     2002  
     
Total generation (billions of KWHs)
    70       72       71  
Sources of generation (percent) —
                       
Coal
    65       64       62  
Nuclear
    19       19       19  
Hydro
    6       8       6  
Gas
    10       9       13  
Average cost of fuel per net KWH generated (cents)
    1.69       1.54       1.44  
Average cost of purchased power per net KWH (cents)
    4.79       3.61       2.91  
 

     Fuel and purchased power expenses totaled $1.6 billion in 2004, an increase of $216 million (15.6 percent). This was due to the average natural gas prices increasing by 30.5 percent, the average coal prices increasing 3.1 percent over the previous year, and higher capacity payments associated with an existing power purchase agreement (PPA). 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 KWHs (4.1 percent) compared with the amounts recorded in 2001.

     A significant upward trend in the cost of coal and natural gas has emerged since 2003, and volatility in these markets is expected to continue. Increased coal prices have been influenced by a worldwide increase in demand as a result of rapid economic growth in China as well as by increases in mining costs. Higher natural gas prices in the United States are the result of slightly lower gas supplies despite increased drilling activity. Natural gas supply interruptions, such as those caused by the 2004 hurricanes, result in an immediate market response; however, the impact of this price volatility may be reduced by imports of natural gas and liquefied natural gas. Fuel expenses, including purchased power, are offset by fuel revenues through the Company’s energy cost recovery clause and generally have no effect on net income.

     Purchased power consists of purchases from affiliates in the Southern Company 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

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each company. Purchased power from non-affiliates increased $75 million (68 percent) in 2004. This was due to a 71.7 percent increase in energy purchased offset by a 1.9 percent decrease in purchased power prices over the previous year. 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 KWHs in 2002, an 18.4 percent increase over the previous year.

     Depreciation and amortization expense increased 3.1 percent in 2004, 3.6 percent in 2003, and 3.9 percent in 2002. These increases reflect additions to property, plant, and equipment.

     Allowance for equity funds used during construction (AFUDC) increased $3.5 million (28.2 percent) in 2004 due primarily to an increase in the amount of construction work in progress over the prior year. 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. See Note 1 to the financial statements under “AFUDC” for additional information.

     Interest expense, net of amounts capitalized of $194 million in 2004 decreased $20.7 million (9.7 percent) from 2003, which had decreased $11.4 million (5.1 percent) from 2002, which had decreased $21 million (8.4 percent) from 2001. All years reflect a decrease in interest rates on long-term debt due to refinancing activities.

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 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 Company operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located in the State of Alabama and to wholesale customers in the Southeast. Prices for electricity provided by the Company to retail customers are set by the Alabama PSC 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 FERC. Retail rates and earnings are reviewed and adjusted periodically within certain limitations based on ROE. See ACCOUNTING POLICIES – “Application of Critical Accounting Policies and Estimates – Electric Utility Regulation” herein and Note 3 to the financial statements for additional information about these and other regulatory matters.

     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 that affect the opportunities, challenges, and risks of the Company’s primary 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 more stringent 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 Company’s service area.

     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

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regarding its limited energy trading operations through Southern Company Services, Inc. (SCS).

Environmental Matters

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, alleging that the Company had violated the New Source Review (NSR) provisions of the Clean Air Act and related state laws with respect to coal-fired generating facilities at the Company’s Plants Miller, Barry, and Gorgas. The EPA concurrently issued to the Company a notice of violation relating to these specific facilities, as well as Plants Greene County and Gaston. In early 2000, the EPA filed a motion to amend its complaint to add the violations alleged in its notice of violation. The 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 was effectively stayed in the spring of 2001 pending the appeal of a similar NSR action against the Tennessee Valley Authority before the U.S. Court of Appeals for the Eleventh Circuit. In June 2004, following the final resolution of that appeal, the U.S. District Court for the Northern District of Alabama lifted the stay in the action against the Company, placing the case back onto the court’s active docket. See Note 3 to the financial statements under “New Source Review Actions” for additional information.

     The Company believes that it complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $32,500 per day, per violation at each generating unit, depending on the date of the alleged violation. 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.

     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 (RMRR) exclusion. A coalition of states and environmental organizations has filed petitions for review of these revisions with the U.S. Court of Appeals for the District of Columbia Circuit. The October 2003 RMRR rules have been stayed by the Court of Appeals pending its review of the rules. In any event, the final regulations must also be adopted by the State of Alabama in order to apply to the Company’s facilities. The effect of these final regulations, related legal challenges, and potential state rulemakings cannot be determined at this time.

Carbon Dioxide Litigation

On July 21, 2004, attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel for New York City filed a complaint in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. A nearly identical complaint was filed by three environmental groups in the same court. The complaints allege that the companies’ emissions of carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs assert is a public nuisance. Under common law public and private nuisance theories, the plaintiffs seek a judicial order (1) holding each defendant jointly and severally liable for creating, contributing to, and/or maintaining global warming and (2) requiring each of the defendants to cap its emissions of carbon dioxide and then reduce those emissions by a specified percentage each year for at least a decade. Plaintiffs have not, however, requested that damages be awarded in connection with their claims. Southern Company believes these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. Southern Company and the other defendants have filed motions to dismiss both lawsuits. Southern Company intends to vigorously defend against these claims. While the outcome of these matters cannot be determined at this time, an adverse judgment in either of these actions could result in substantial capital expenditures.

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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 involves significant capital and operating costs, a major portion of which is expected to be recovered through existing ratemaking provisions. See “FERC and Alabama PSC Matters – Environmental Rate Filing” and Note 3 to the financial statements under “Retail Rate Adjustment Procedures” for additional information. Environmental costs that are known and estimable at this time are included in capital expenditures discussed under FINANCIAL CONDITION AND LIQUIDITY – “Capital Requirements and Contractual Obligations” herein. There is no assurance, however, that all such costs will, in fact, be recovered.

     Compliance with the 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 and resulted in total construction expenditures of approximately $66 million through 2000. Some of these previous 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 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 totaled approximately $249 million through 2004.

     To help 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, were required to comply with these reductions by May 31, 2004. Additional construction expenditures for compliance with these rules are currently estimated at approximately $369 million, of which $169 million remains to be spent. In March 2004, the EPA redesignated the Birmingham, Alabama area from nonattainment to attainment under the one-hour ozone standard.

     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 and included development of an eight-hour ozone standard, as opposed to the previous one-hour ozone standard. 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. On April 30, 2004, the EPA published its eight-hour ozone nonattainment designations and a portion of the rules implementing the new eight-hour ozone standard. The counties around Birmingham have been designated as nonattainment under the eight-hour ozone standard. Under the implementation provisions of the new rule, the EPA announced that the one-hour ozone standard will be revoked on June 15, 2005. With respect to the eight-hour nonattainment areas, state implementation plans, including new emission control regulations necessary to bring those areas into attainment, could be required as early as 2007. These state implementation plans could require reductions in nitrogen oxide emissions from power plants. The impact of the eight-hour designations and the new standard will depend on the development and implementation of Alabama’s state implementation plan and therefore cannot be determined at this time.

     On December 17, 2004, the EPA issued its final “nonattainment” designations for the fine particulate national ambient air quality standard. Several areas within the Company’s service area were included in the EPA’s final particulate matter designations. The EPA plans to propose a fine particulate matter implementation rule in 2005 and finalize the implementation rule in 2006. State implementation plans addressing the nonattainment designations may be required by 2008 and could require reductions in sulfur dioxide emissions and further reductions in nitrogen oxide emissions from power plants. The impact of the fine particulate designations will depend on the development and implementation of Alabama state implementation plans and therefore cannot be determined at this time.

     In January 2004, the EPA issued a proposed Clean Air Interstate Rule (CAIR) to address interstate transport of

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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 in 2005. If finalized, the rule could modify or supplant other state requirements for attainment of the fine particulate matter standard and the eight-hour ozone standard, as well as other air quality regulations. 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.

     The Company has developed and maintains an environmental compliance strategy for the installation of additional control technologies and the purchase of emission allowances to assure continued compliance with current sulfur dioxide and nitrogen oxide emission regulations. Additional expenses associated with these regulations are anticipated to be incurred each year to maintain current and future compliance. Because the Company’s compliance strategy is impacted by factors such as changes to existing environmental laws and regulations, increases in the cost of emissions allowances, and any change in the Company’s fuel mix, future environmental compliance costs 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 and to implement emission reduction requirements that make progress toward remedying current visibility impairment in certain natural areas. 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 implementation plans in 2008 that contain emission reduction strategies for implementing BART and for achieving sufficient progress toward the Clean Air Act’s visibility improvement goal. In response to litigation, the EPA proposed revised rules in May 2004, which it plans to finalize in April 2005. The impact of these regulations will depend on the promulgation of final rules and implementation of those rules by the states and, therefore, it is not possible to determine the effect of these rules on the Company at this time.

     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 March 2005, and compliance could be required as early as 2008. Because the regulations have not been finalized, the impact on the Company cannot be determined at this time.

     Major bills to amend the Clean Air Act to impose more stringent emissions limitations on power plants, including the Bush Administration’s Clear Skies Act, have been re-proposed in 2005. The Clear Skies Act is expected to further limit power plant emissions of sulfur dioxide, nitrogen oxides, and mercury and to supplement the proposed CAIR and mercury regulatory programs. Other proposals to limit emissions of carbon dioxide have also been introduced. The cost impacts of such legislation would depend upon the specific requirements enacted and cannot be determined at this time.

     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. In July 2004, the EPA published final rules that 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 and the actual limits established by the regulatory agencies.

     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 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.

Global Climate Issues

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

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constraints on the emissions of greenhouse gases for a group of industrialized countries. The Bush Administration has not supported U.S. ratification of the Kyoto Protocol or other mandatory carbon dioxide reduction legislation and, in 2002, announced a goal to reduce the greenhouse gas intensity of the U.S. – the ratio of greenhouse gas emissions to the value of U.S. economic output — by 18 percent by 2012. A year later, the Department of Energy (DOE) announced the Climate VISION program to support this goal. Energy-intensive industries, including electricity generation, are the initial focus of this program. Southern Company is leading the development of a voluntary electric utility sector climate change initiative in partnership with the government. The utility sector has pledged to reduce its greenhouse gas emissions rate by 3 to 5 percent over the next decade and, on December 13, 2004, signed a memorandum of understanding with the DOE initiating this program under Climate VISION. Because efforts under this voluntary program are just beginning, the impact of this program on the Company cannot be determined at this time.

Environmental Remediation Reserves

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.

FERC and Alabama PSC Matters

Transmission

In December 1999, the FERC issued its final rule on Regional Transmission Organizations (RTOs). Since that time, there have been a number of additional proceedings at the FERC designed to encourage further voluntary formation of RTOs or to mandate their formation. However, at the current time, there are no active proceedings that would require the Company to participate in an RTO. Current FERC efforts that may potentially change the regulatory and/or operational structure of transmission include rules related to the standardization of generation interconnection, as well as an inquiry into, among other things, market power by vertically integrated utilities. See “Generation Interconnection Agreements” and “Market-Based Rate Authority” herein for additional information. The final outcome of these proceedings cannot now be determined. However, the Company’s financial condition, results of operations and cash flows could be adversely affected by future changes in the federal regulatory or operational structure of transmission.

Generation Interconnection Agreements

In July 2003, the FERC issued its final rule on the standardization of generation interconnection agreements and procedures (Order 2003). Order 2003 shifts much of the financial burden of new transmission investment from the generator to the transmission provider. The FERC has indicated that Order 2003, which was effective January 20, 2004, is to be applied prospectively to interconnection agreements. Subsidiaries of Tenaska, Inc., as counterparties to two previously executed interconnection agreements with the Company, have filed complaints at the FERC requesting that the FERC modify the agreements and that the Company refund a total of $11 million previously paid for interconnection facilities, with interest. The Company has also received similar requests from other entities totaling $2.5 million. The Company has opposed such relief, and the proceedings are still pending. The impact of Order 2003 and its subsequent rehearings on the Company and the final results of these matters cannot be determined at this time.

Market-Based Rate Authority

The Company has authorization from the FERC to sell power to nonaffiliates at market-based prices. Through SCS, as an 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, the retail operating companies, and Southern Power, and found them and others to be “pivotal suppliers” in their retail service territories 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. In April 2004, the FERC issued an order that abandoned the SMA test and adopted a new interim analysis for measuring generation market power. This

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new interim approach requires utilities to submit a pivotal supplier screen and a wholesale market share screen. If the applicant does not pass both screens, there will be a rebuttable presumption regarding generation market power. The FERC’s order also sets forth procedures for rebutting these presumptions and addresses mitigation measures for those entities that are found to have market power. In the absence of specific mitigation measures, the order includes several cost-based mitigation measures that would apply by default. The FERC also initiated a new rulemaking proceeding that, among other things, will adopt a final methodology for assessing generation market power.

     In July 2004, the FERC denied Southern Company’s request for rehearing, along with a number of others, and reaffirmed the interim tests that it adopted in April. In August 2004, Southern Company submitted a filing to the FERC that included results showing that Southern Company passed the pivotal supplier screen for all markets and the wholesale market share screen for all markets except the Southern Company retail service territory. Southern Company also submitted other analyses to demonstrate that it lacks generation market power. On December 17, 2004, the FERC initiated a proceeding to assess Southern Company’s generation dominance within its retail service territory. The ability to charge market-based rates in other markets is not at issue. As directed by this order, on February 15, 2005, Southern Company submitted additional information related to generation dominance in its retail service territory. Any new market-based rate transactions in Southern Company’s retail service territory entered into after February 27, 2005 will be subject to refund to the level of the default cost-based rates, pending the outcome of the proceeding. Southern Company, along with other utilities, has also filed an appeal of the FERC’s April and July 2004 orders with the U.S. Court of Appeals for the District of Columbia Circuit. The FERC has asked the court to dismiss the appeal on the grounds that it is premature.

     In the event that the FERC’s default mitigation measures are ultimately applied, the Company may be required to charge cost-based rates for certain wholesale sales in Southern Company’s retail service territory, which may be lower than negotiated market-based rates. The final outcome of this matter will depend on the form in which the final methodology for assessing generation market power and mitigation rules may be ultimately adopted and cannot be determined at this time.

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. The final outcome of this matter cannot be determined at this time.

Nuclear Relicensing

The Company filed an application with the Nuclear Regulatory Commission (NRC) in September 2003 to extend the operating license for Plant Farley for an additional 20 years. The NRC is expected to rule on the application by July 2005. If the NRC approves the extension, the Company’s annual decommissioning expense could decrease, subject to Alabama PSC approval. See Note 1 to the financial statements under “Nuclear Decommissioning” for additional information.

Environmental Rate Filing

On October 5, 2004, the Alabama PSC approved a specific rate mechanism for the recovery of the Company’s retail costs associated with environmental laws, regulations, or other such mandates. The rate mechanism began operation in January 2005 and provides for the recovery of these costs pursuant to a factor that will be calculated annually. Environmental costs to be recovered include operation and maintenance expenses, depreciation and a return on invested capital. Retail rates have increased 1 percent in 2005, which should yield an annual recovery of approximately $33 million, and are expected to increase an additional 1 percent in 2006. In conjunction with the Alabama PSC’s approval, the Company agreed to a moratorium until March 2007 on any retail rate increase under the previously approved Rate Stabilization and Equalization plan (RSE). Any increase in March 2007 would be based upon the earned return on retail common equity at December 31, 2006. See Note 3 to the financial statements under “Retail Rate Adjustment Procedures” for further information on RSE.

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Retail Rate Adjustments

The Company’s retail rates, approved by the Alabama PSC, also provide for adjustments to recognize the placing of new generating facilities into retail service and the recovery of retail costs associated with certificated PPAs under Rate Certificated New Plant (CNP). 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. An additional increase of $25 million annually was effective July 2004 under Rate CNP for new certificated PPAs. In April 2005, an adjustment to Rate CNP is expected to decrease retail rates by approximately 0.5 percent, or $18.5 million annually. See Note 3 to the financial statements under “Retail Rate Adjustment Procedures” for additional information.

Retail Fuel Cost Recovery

The Company has established fuel cost recovery rates approved by the Alabama PSC. In recent months, the Company has experienced higher than expected fuel costs for coal and gas. Those higher fuel costs have increased the under recovered fuel costs included in the balance sheets. In April 2005, the retail energy clause recovery factor is scheduled to increase from its current level. The Company will continue to monitor the under recovered fuel cost balance to determine if an additional adjustment to billing rates should be requested from the Alabama PSC.

Natural Disaster Cost Recovery

The Company maintains a reserve for operation and maintenance expense to cover the cost of damages from major storms to its transmission and distribution lines and the cost of uninsured damages to its generation facilities and other property. On September 15 and 16, 2004, Hurricane Ivan hit the Gulf Coast of Florida and Alabama and continued north through the state of Alabama, causing substantial damage in the service territory of the Company. Approximately 826,000 of the Company’s 1,370,000 customer accounts were without electrical service immediately after the hurricane. Almost 95% of those without power had service restored within one week, and two weeks after the storm, power had been restored to all who could receive service.

     The operation and maintenance expenses associated with repairing the damage to the Company’s facilities and restoring service to customers as a result of Hurricane Ivan were $57.8 million for 2004. The balance in the Company’s natural disaster reserve prior to the storm was $14.6 million. On October 19, 2004, the Company received approval from the Alabama PSC to record its hurricane related operation and maintenance expenses in its natural disaster reserve, thereby deferring the regulatory asset for recovery in future periods. The Company is allowed to accrue $250 thousand per month until a 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 2004, the Company accrued $9.9 million, including an additional amount of $6.9 million, to the reserve and at December 31, 2004 the regulatory asset totaled $37.7 million.

     In February 2005, the Company requested and received Alabama PSC approval of an accounting order that allows the Company to immediately return certain regulatory liabilities to the retail customers. The order also allows the Company to simultaneously recover from customers an accrual of approximately $45 million to offset the costs of Hurricane Ivan and restore the natural disaster reserve. The combined effects of this order will have no impact on the Company’s net income in 2005. See Notes 1 and 3 to the financial statements under “Natural Disaster Reserve” and “Natural Disaster Cost Recovery,” respectively, for additional information on these reserves.

Income Tax Matters

American Jobs Creation Act of 2004

On October 22, 2004, President Bush signed the American Jobs Creation Act of 2004 (Jobs Act) into law. The Jobs Act includes a provision that allows a generation tax deduction for utilities. The Company is currently assessing the impact of the Jobs Act, including this deduction, as well as the related regulatory treatment, on its taxable income. However, the Company currently does not expect the Jobs Act to have a material impact on its financial statements.

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 $36 million, $52 million, and $56 million in 2004, 2003, and 2002, respectively. Future pension income is dependent on several factors including trust earnings and changes to the pension plan. The decline in pension income is expected to continue, but should not become a pension expense in

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the foreseeable future. Postretirement benefit costs for the Company were $22 million, $23 million, and $23 million in 2004, 2003, and 2002, respectively, and are expected to trend upward. A portion of pension income and postretirement benefit costs is capitalized based on construction-related labor charges. Pension 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.

     The Company is involved in various other 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. Southern Company 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.

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, which requires the financial statements to reflect the effects of rate 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 legislative, 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” herein 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:

•   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.
 
•   Changes in existing income tax regulations or changes in Internal Revenue Service interpretations of existing regulations.
 
•   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.

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•   Identification and evaluation of other potential lawsuits or complaints in which the Company may be named as a defendant.
 
•   Resolution or progression of existing matters through the legislative process, the court systems, or the EPA.

Unbilled Revenues

Revenues related to the sale of electricity are recorded when electricity is delivered to customers. However, the determination of KWH sales to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month. At the end of each month, amounts of electricity delivered to customers, but not yet metered and billed, are estimated. Components of the unbilled revenue estimates include total KWH territorial supply, total KWH billed, estimated total electricity lost in delivery, and customer usage. These components can fluctuate as a result of a number of factors including weather, generation patterns, power delivery volume, and other operational constraints. These factors can be unpredictable and can vary from historical trends. As a result, the overall estimate of unbilled revenues could be significantly affected, which could have a material impact on the Company’s results of operations.

New Accounting Standards

On March 31, 2004, the Company prospectively adopted FASB Interpretation No. 46R, Consolidation of Variable Interest Entities, which requires the primary beneficiary of a variable interest entity to consolidate the related assets and liabilities. The adoption of FASB Interpretation No. 46R had no impact on the Company’s net income. However, as a result of the adoption, the Company deconsolidated certain wholly-owned trusts established to issue preferred securities since the Company does not meet the definition of primary beneficiary established by FASB Interpretation No. 46R. See Note 1 to the financial statements under “Variable Interest Entities” for additional information.

     In the third quarter 2004, the Company prospectively adopted FASB Staff Position (FSP) 106-2, Accounting and Disclosure Requirements related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (Medicare Act). The Medicare Act provides a 28 percent prescription drug subsidy for Medicare eligible retirees. FSP 106-2 requires recognition of the impacts of the Medicare Act in the accumulated postretirement benefit obligation (APBO) and future cost of service for postretirement medical plans. The effect of the subsidy reduced the Company’s expenses for the six months ended December 31, 2004 by approximately $3.2 million and is expected to have a similar impact on future expenses. The subsidy’s impact on the postretirement medical plan APBO was a reduction of approximately $59.8 million. However, the ultimate impact on future periods is subject to final interpretation of the federal regulations which were published on January 21, 2005. See Note 2 to the financial statements under “Postretirement Benefits” for additional information.

     FASB Statement No. 123R, Share-Based Payment was issued in December 2004. This statement requires that compensation cost relating to share-based payment transactions be recognized in financial statements. That cost will be measured based on the grant date fair value of the equity or liability instruments issued. For the Company, this statement is effective beginning on July 1, 2005. Although the compensation expense calculation required under the revised statement differs slightly, the impact on the Company’s financial statements are expected to be similar to the pro forma disclosures included in Note 1 to the financial statements under “Stock Options.”

     See FUTURE EARNINGS POTENTIAL – “Income Tax Matters — American Jobs Creation Act of 2004” herein for information regarding the adoption of new tax legislation. In December 2004, the FASB issued FSP 109-1, Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax Deduction on Qualified Production Activities provided by the American Jobs Creation Act of 2004, which requires that the generation deduction be accounted for as a special tax deduction rather than as a tax rate reduction. The Company is currently assessing the Jobs Act and this pronouncement, as well as the related regulatory treatment, but currently does not expect a material impact on the Company’s financial statements.

FINANCIAL CONDITION AND LIQUIDITY

Overview

The Company’s financial condition continued to be strong at December 31, 2004. Net cash flow from operating activities totaled $1.0 billion, $1.1 billion, and $973 million for 2004, 2003, and 2002, respectively. The $107 million decrease for 2004 in operating activities primarily relates to an increase in under recovered fuel cost and storm damage costs related to Hurricane Ivan. These increases were partially offset by the deferral of income tax liabilities arising from accelerated depreciation

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Alabama Power Company 2004 Annual Report

deductions. Fuel costs are recoverable in future periods and are reflected on the balance sheets as under recovered regulatory clause revenues. The $145 million increase from 2002 to 2003 resulted from the deferral of income tax liabilities arising from accelerated depreciation deductions offset by the settlement of interest rate hedges.

     Significant balance sheet changes include the $478 million increase in long-term debt for 2004 primarily due to the replacement of debt due within one year with long-term debt, and an increase of $412 million in gross plant.

     The Company’s ratio of common equity to total capitalization — including short-term debt — was 42.6 percent in 2004, 43.3 percent in 2003, and 42.6 percent in 2002. 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, preferred stock, and preferred securities.

     Security issuances are subject to regulatory approval by the Alabama PSC. Additionally, with respect to the public offering of securities, the Company must file registration statements with the Securities and Exchange Commission (SEC) under the Securities Act of 1933, as amended (1933 Act). The amounts of securities authorized by the Alabama PSC, as well as the amounts registered under the 1933 Act, are continuously monitored and appropriate filings are made to ensure flexibility in the capital markets.

     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 of 1935, as amended (PUHCA), most loans between affiliated companies must be approved in advance by the 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 has various internal and external sources of liquidity. At the beginning of 2005, the Company had approximately $84 million of cash and cash equivalents and $868 million of unused credit arrangements with banks. 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.

     The Company maintains committed lines of credit in the amount of $868 million of which $643 million will expire at various times during 2005. $225 million of the credit facilities expiring in 2005 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. 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 retail operating company. The obligations of each company under these arrangements are several and there is no cross affiliate credit support.

     At December 31, 2004, the Company had no commercial paper or extendible commercial notes outstanding.

Financing Activities

During 2004, the Company issued $900 million of long-term debt and $100 million of preferred stock. In addition, the Company issued 1 million new shares of common stock to Southern Company at $40.00 a share and realized proceeds of $40 million. The proceeds of these issues were used to redeem or repay at maturity long-term debt, to repay short-term indebtedness, and for other general corporate purposes.

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Alabama Power Company 2004 Annual Report

     Composite financing rates for long-term debt, preferred stock, and preferred securities for the years 2002 through 2004, as of year-end, were as follows:

                         
    2004     2003     2002  
 
Long-term debt interest rate
    4.14 %     4.42 %     5.05 %
Preferred securities distribution rate
    5.25       5.25       5.25  
Preferred stock dividend rate
    5.14       5.10       5.17  
 

Credit Rating Risk

The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. However, the Company is party to certain derivative agreements that could require collateral and/or accelerated payment in the event of a credit rating change to below investment grade. These agreements are primarily for natural gas price and interest rate risk management activities. At December 31, 2004, the Company’s maximum potential exposure to these contracts was $9.8 million.

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 risk management practices. Company policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, 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 January 1, 2005 was 2.57 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 $2.5 million at January 1, 2005. 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. The Company has implemented fuel hedging programs at the instruction of the Alabama PSC.

     In addition, the Company’s Rate ECR allows the recovery of specific costs associated with the sales of natural gas that become necessary due to operating considerations at the Company’s electric generating facilities. Rate ECR also allows recovery of 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, 2004, exposure from these activities was not material to the Company’s financial position, results of operations, or cash flows. The fair value changes in energy related derivative contracts and year-end valuations were as follows at December 31:

                 
    Changes in Fair Value  
 
    2004     2003  
 
    (in thousands)  
Contracts beginning of year
  $ 6,413     $ 21,402  
Contracts realized or settled
    (26,384 )     (38,809 )
New contracts at inception
           
Changes in valuation techniques
           
Current period changes (a)
    23,988       23,820  
 
Contracts end of year
  $ 4,017     $ 6,413  
 
(a)   Current period changes also include the changes in fair value of new contracts entered into during the period.
                         
    Source of 2004 Year-End  
    Valuation Prices
    Total     Maturity
    Fair Value     2005     2006-2007  
 
    (in thousands)  
 
Actively quoted
  $ 3,985     $ 2,917     $ 1,068  
External sources
    32       32        
Models and other methods
                 
 
Contracts end of Year
  $ 4,017     $ 2,949     $ 1,068  
 

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Alabama Power Company 2004 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 clause. Gains and losses on derivative contracts that are not designated as hedges are recognized in the income statement as incurred. At December 31, 2004, the fair value of derivative energy contracts was reflected in the financial statements as follows:

         
    Amounts  
 
    (in thousands)  
Regulatory liabilities, net
  $ 3,978  
Other comprehensive income
     
Net income
    39  
 
Total fair value
  $ 4,017  
 

     Unrealized pre-tax gains (losses) on energy contracts recognized in income in 2004 and 2003 were not material. For 2002, pre-tax losses of $2.0 million were recognized in income. 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 $902 million for 2005, $921 million for 2006, and $1.0 billion for 2007. Over the next three years, the Company estimates spending $913 million on environmental related additions (including $276 million on selective catalytic reduction facilities), $238 million on Plant Farley (including $177 million for nuclear fuel), $767 million on distribution facilities, and $411 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 $1.4 billion will be required by the end of 2007 for maturities of long-term debt. The Company plans to continue, when economically feasible, to retire higher cost securities 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 approved by the Alabama PSC. The amount expensed in 2004 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 “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.

     The Company has 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 for other purposes and may require the Company to seek capital from other sources. For additional information, see Note 2 to the financial statements under “Postretirement Benefits.”

     Other funding requirements related to obligations associated with scheduled maturities of long-term debt and preferred securities, as well as the related interest, preferred stock dividends, leases, and other purchase commitments, are as follows. See Notes 1, 6, and 7 to the financial statements for additional information.

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Alabama Power Company 2004 Annual Report

Contractual Obligations

                                         
            2006-     2008-     After        
    2005     2007     2009     2009     Total  
 
    (in millions)  
Long-term debt(a)
                                       
Principal
  $ 225.0     $ 1,215.0     $ 660.0     $ 2,294.4     $ 4,394.4  
Interest
    185.2       327.3       243.0       1,924.7       2,680.2  
Preferred stock dividends(b)
    23.6       47.2       47.2             118.0  
Operating leases
    29.1       35.3       19.0       34.6       118.0  
Purchase commitments(c)
                                       
Capital(d)
    902.5       1,938.4                   2,840.9  
Coal and nuclear fuel
    907.0       1,517.0       356.0       97.0       2,877.0  
Natural gas(e)
    249.0       309.0       52.0       108.0       718.0  
Purchased power
    87.0       175.0       179.0       38.0       479.0  
Long-term service agreements
    17.2       35.8       37.3       103.1       193.4  
Trusts —
                                       
Nuclear decommissioning
    20.3       40.6       40.6       192.1       293.6  
Postretirement benefits(f)
    25.3       51.6                   76.9  
DOE assessments
    4.4       4.5                   8.9  
 
Total
  $ 2,675.6     $ 5,696.7     $ 1,634.1     $ 4,791.9     $ 14,798.3  
 

(a)   All amounts are reflected based on final maturity dates. The Company plans to 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, 2005, 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 $947 million, $921 million, and $854 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, 2004, 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 Exchange future prices at December 31, 2004.
 
(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 and postretirement plans, including estimated benefit payments. Certain benefit payments will be made through the related trusts. Other benefit payments will be made from the Company’s corporate assets.

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Alabama Power Company 2004 Annual Report

Cautionary Statement Regarding Forward-Looking Statements

The Company’s 2004 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning retail sales growth and retail rates, storm damage cost recovery, environmental regulations and expenditures, the Company’s projections for postretirement benefit trust contributions, and estimated construction and other expenditures. 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 similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:

•   the impact of recent and future federal and state regulatory change, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, and also changes in environmental, tax, and other laws and regulations to which the Company is subject, as well as changes in application of existing laws and regulations;
 
•   current and future litigation, regulatory investigations, proceedings or inquiries, including the pending EPA civil action against the Company;
 
•   the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates;
 
•   variations in demand for electricity and gas, including those relating to weather, the general economy and population and business growth (and declines);

•   available sources and costs of fuels;

•   ability to control costs;

•   investment performance of the Company’s employee benefit plans;

•   advances in technology;

•   state and federal rate regulations and the impact of pending and future rate cases and negotiations;

•   internal restructuring or other restructuring options that may be pursued;

•   potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to the Company;

•   the ability of counterparties of the Company to make payments as and when due;

•   the ability to obtain new short- and long-term contracts with neighboring utilities;

•   the direct or indirect effect on the Company’s business resulting from terrorist incidents and the threat of terrorist incidents;

•   interest rate fluctuations and financial market conditions and the results of financing efforts, including the Company’s credit ratings;

•   the ability of the Company to obtain additional generating capacity at competitive prices;

•   catastrophic events such as fires, earthquakes, explosions, floods, hurricanes, or other similar occurrences;

•   the direct or indirect effects on the Company’s business resulting from incidents similar to the August 2003 power outage in the Northeast;

•   the effect of accounting pronouncements issued periodically by standard-setting bodies; and

•   other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed by the Company from time to time by the Company with the SEC.

The Company expressly disclaims any obligation to update any forward-looking statements.

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STATEMENTS OF INCOME
For the Years Ended December 31, 2004, 2003, and 2002
Alabama Power Company 2004 Annual Report

                         
 
    2004     2003     2002  
 
    (in thousands)  
Operating Revenues:
                       
Retail sales
  $ 3,292,828     $ 3,051,463     $ 2,951,217  
Sales for resale —
                       
Non-affiliates
    483,839       487,456       474,291  
Affiliates
    308,312       277,287       188,163  
Other revenues
    151,012       143,955       96,862  
 
Total operating revenues
    4,235,991       3,960,161       3,710,533  
 
Operating Expenses:
                       
Fuel
    1,186,472       1,067,821       969,521  
Purchased power —
                       
Non-affiliates
    186,187       110,885       90,998  
Affiliates
    226,697       204,353       158,121  
Other operations
    634,030       611,418       574,979  
Maintenance
    313,407       309,451       279,406  
Depreciation and amortization
    425,906       412,919       398,428  
Taxes other than income taxes
    242,809       228,414       216,919  
 
Total operating expenses
    3,215,508       2,945,261       2,688,372  
 
Operating Income
    1,020,483       1,014,900       1,022,161  
Other Income and (Expense):
                       
Allowance for equity funds used during construction
    16,141       12,594       11,168  
Interest income
    15,677       15,220       13,991  
Interest expense, net of amounts capitalized
    (193,590 )     (214,302 )     (225,706 )
Interest expense to affiliate trusts
    (16,191 )            
Distributions on mandatorily redeemable preferred securities
          (15,255 )     (24,599 )
Other income (expense), net
    (24,728 )     (31,702 )     (28,785 )
 
Total other income and (expense)
    (202,691 )     (233,445 )     (253,931 )
 
Earnings Before Income Taxes
    817,792       781,455       768,230  
Income taxes
    313,024       290,378       292,436  
 
Net Income
    504,768       491,077       475,794  
Dividends on Preferred Stock
    23,597       18,267       14,439  
 
Net Income After Dividends on Preferred Stock
  $ 481,171     $ 472,810     $ 461,355  
 

The accompanying notes are an integral part of these financial statements.

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STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2004, 2003, and 2002
Alabama Power Company 2004 Annual Report

                         
 
    2004     2003     2002  
 
    (in thousands)  
Operating Activities:
                       
Net income
  $ 504,768     $ 491,077     $ 475,794  
Adjustments to reconcile net income to net cash provided from operating activities —
                       
Depreciation and amortization
    497,010       487,370       442,660  
Deferred income taxes and investment tax credits, net
    252,858       153,154       48,828  
Deferred revenues
    (11,510 )     (17,932 )     (8,099 )
Allowance for equity funds used during construction
    (16,141 )     (12,594 )     (11,168 )
Pension, postretirement, and other employee benefits
    (29,362 )     (38,953 )     (34,977 )
Tax benefit of stock options
    10,672       8,680       6,670  
Other, net
    10,817       6,292       19,271  
Changes in certain current assets and liabilities —
                       
Receivables, net
    (144,256 )     (13,488 )     33,074  
Fossil fuel stock
    30,130       (13,251 )     25,535  
Materials and supplies
    (26,229 )     (4,651 )     3,728  
Other current assets
    19,131       (953 )     1,479  
Accounts payable
    (12,778 )     77,128       (1,034 )
Accrued taxes
    (24,568 )     (33,507 )     (40,922 )
Accrued compensation
    (7,041 )     664       17,122  
Other current liabilities
    (42,544 )     29,058       (4,798 )
 
Net cash provided from operating activities
    1,010,957       1,118,094       973,163  
 
Investing Activities:
                       
Gross property additions
    (797,014 )     (661,154 )     (645,262 )
Cost of removal net of salvage
    (37,369 )     (35,440 )     (32,111 )
Other
    11,575       (1,169 )     5,017  
 
Net cash used for investing activities
    (822,808 )     (697,763 )     (672,356 )
 
Financing Activities:
                       
Increase (decrease) in notes payable, net
          (36,991 )     26,994  
Proceeds —
                       
Senior notes
    900,000       1,415,000       975,000  
Mandatorily redeemable preferred securities
                300,000  
Preferred stock
    100,000       125,000        
Common stock
    40,000       50,000        
Capital contributions from parent company
    17,541       17,826       43,118  
Redemptions —
                       
First mortgage bonds
                (350,000 )
Senior notes
    (725,000 )     (1,507,000 )     (415,602 )
Other long-term debt
    (1,445 )     (943 )     (883 )
Mandatorily redeemable preferred securities
                (347,000 )
Preferred stock
                (70,000 )
Payment of preferred stock dividends
    (23,639 )     (18,181 )     (14,176 )
Payment of common stock dividends
    (437,300 )     (430,200 )     (431,000 )
Other
    (16,597 )     (14,775 )     (30,329 )
 
Net cash used for financing activities
    (146,440 )     (400,264 )     (313,878 )
 
Net Change in Cash and Cash Equivalents
    41,709       20,067       (13,071 )
Cash and Cash Equivalents at Beginning of Period
    42,752       22,685       35,756  
 
Cash and Cash Equivalents at End of Period
  $ 84,461     $ 42,752     $ 22,685  
 
Supplemental Cash Flow Information:
                       
Cash paid during the period for —
                       
Interest (net of $6,832, $6,367, and $6,738 capitalized, respectively)
  $ 188,556     $ 185,272     $ 230,102  
Income taxes (net of refunds)
    69,068       161,004       269,043  
 

The accompanying notes are an integral part of these financial statements.

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BALANCE SHEETS
At December 31, 2004 and 2003
Alabama Power Company 2004 Annual Report

                 
 
Assets   2004     2003  
 
    (in thousands)  
Current Assets:
               
Cash and cash equivalents
  $ 84,461     $ 42,752  
Receivables —
               
Customer accounts receivable
    235,221       223,865  
Unbilled revenues
    96,486       95,953  
Under recovered regulatory clause revenues
    119,773       16,697  
Other accounts and notes receivable
    52,145       53,547  
Affiliated companies
    61,149       48,876  
Accumulated provision for uncollectible accounts
    (5,404 )     (4,756 )
Fossil fuel stock, at average cost
    57,787       86,993  
Vacation pay
    36,494       35,530  
Materials and supplies, at average cost
    237,919       211,690  
Prepaid expenses
    61,896       78,409  
Other
    11,269       19,454  
 
Total current assets
    1,049,196       909,010  
 
Property, Plant, and Equipment:
               
In service
    14,636,168       14,224,117  
Less accumulated provision for depreciation
    5,097,930       4,907,549  
 
 
    9,538,238       9,316,568  
Nuclear fuel, at amortized cost
    93,388       93,611  
Construction work in progress
    470,844       321,316  
 
Total property, plant, and equipment
    10,102,470       9,731,495  
 
Other Property and Investments:
               
Equity investments in unconsolidated subsidiaries
    45,455       47,811  
Nuclear decommissioning trusts, at fair value
    445,634       384,574  
Other
    44,322       23,708  
 
Total other property and investments
    535,411       456,093  
 
Deferred Charges and Other Assets:
               
Deferred charges related to income taxes
    316,528       321,077  
Prepaid pension costs
    489,193       446,256  
Unamortized debt issuance expense
    28,392       23,457  
Unamortized loss on reacquired debt
    109,403       110,946  
Other regulatory assets
    46,603       13,092  
Other
    106,263       91,370  
 
Total deferred charges and other assets
    1,096,382       1,006,198  
 
Total Assets
  $ 12,783,459     $ 12,102,796  
 

The accompanying notes are an integral part of these financial statements.

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BALANCE SHEETS
At December 31, 2004 and 2003
Alabama Power Company 2004 Annual Report

                 
 
Liabilities and Stockholder’s Equity   2004     2003  
 
    (in thousands)  
Current Liabilities:
               
Securities due within one year
  $ 225,005     $ 526,019  
Accounts payable —
               
Affiliated
    141,096       141,940  
Other
    198,834       162,314  
Customer deposits
    49,598       47,507  
Accrued taxes —
               
Income taxes
    28,498       3,679  
Other
    29,688       22,274  
Accrued interest
    40,029       46,489  
Accrued vacation pay
    36,494       35,530  
Accrued compensation
    76,858       75,726  
Other
    26,365       34,407  
 
Total current liabilities
    852,465       1,095,885  
 
Long-term Debt (See accompanying statements)
    3,855,257       3,377,148  
 
Long-term Debt Payable to Affiliated Trusts (See accompanying statements)
    309,279        
 
Mandatorily Redeemable Preferred Securities (See accompanying statements)
          300,000  
 
Deferred Credits and Other Liabilities:
               
Accumulated deferred income taxes
    1,885,120       1,684,741  
Deferred credits related to income taxes
    148,395       162,168  
Accumulated deferred investment tax credits
    205,353       216,309  
Employee benefit obligations
    194,837       174,036  
Deferred capacity revenues
    25,056       36,567  
Asset retirement obligations
    383,621       358,759  
Asset retirement obligation regulatory liability
    159,230       127,346  
Other cost of removal obligations
    597,147       572,816  
Miscellaneous regulatory liabilities
    55,459       86,323  
Other
    36,989       37,526  
 
Total deferred credits and other liabilities
    3,691,207       3,456,591  
 
Total Liabilities
    8,708,208       8,229,624  
 
Cumulative Preferred Stock (See accompanying statements)
    465,047       372,512  
 
Common Stockholder’s Equity (See accompanying statements)
    3,610,204       3,500,660  
 
Total Liabilities and Stockholder’s Equity
  $ 12,783,459     $ 12,102,796  
 
Commitments and Contingent Matters (See notes)
               
 

The accompanying notes are an integral part of these financial statements.

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STATEMENTS OF CAPITALIZATION
At December 31, 2004 and 2003
Alabama Power Company 2004 Annual Report

                                 
 
    2004     2003     2004     2003  
 
    (in thousands)   (percent of total)  
Long-Term Debt:
                               
Long-term notes payable —
                               
4.875% to 7.125% due 2004
  $     $ 525,000                  
5.49% due November 1, 2005
    225,000       225,000                  
2.65% to 2.80% due 2006
    520,000       520,000                  
Floating rate (2.09% at 1/1/05) due 2006
    195,000       195,000                  
3.50% to 7.125% due 2007
    500,000       200,000                  
3.125% to 5.375% due 2008
    410,000       410,000                  
Floating rate (2.57% at 1/1/05) due 2009
    250,000                        
4.70% to 6.75% due 2010-2039
    1,425,000       1,275,000                  
 
Total long-term notes payable
    3,525,000       3,350,000                  
 
Other long-term debt —
                               
Pollution control revenue bonds —
                               
Collateralized:
                               
5.50% due 2024
    24,400       24,400                  
Variable rates (2.01% to 2.16% at 1/1/05) due 2015-2017
    89,800       89,800                  
Non-collateralized:
                               
Variable rates (2.01% to 2.16% at 1/1/05) due 2021-2031
    445,940       445,940                  
 
Total other long-term debt
    560,140       560,140                  
 
Capitalized lease obligations
    52       1,497                  
 
Unamortized debt premium (discount), net
    (4,930 )     (8,470 )                
 
Total long-term debt (annual interest requirement — $169.0 million)
    4,080,262       3,903,167                  
Less amount due within one year
    225,005       526,019                  
 
Long-term debt excluding amount due within one year
  $ 3,855,257     $ 3,377,148       46.8 %     44.7 %
 

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STATEMENTS OF CAPITALIZATION (continued)
At December 31, 2004 and 2003
Alabama Power Company 2004 Annual Report

                                 
 
    2004     2003     2004     2003  
 
      (in thousands)       (percent of total)  
Long-term Debt Payable to Affiliated Trusts:
                               
4.75% through 2007 due 2042*
    103,093                        
5.5% through 2009 due 2042*
    206,186                        
 
Total long-term debt payable to affiliated trusts (annual interest requirement — $16.2 million)
    309,279             3.8       0.0  
 
Mandatorily Redeemable Preferred Securities:
                               
$1,000 liquidation value due 2042 —
                               
4.75% through 2007*
          100,000                  
5.50% through 2009*
          200,000                  
 
Total mandatorily redeemable preferred securities
          300,000       0.0       4.0  
 
Cumulative Preferred Stock:
                               
$100 par or stated value — 4.20% to 4.92%
    47,611       47,512                  
$25 par or stated value — 5.20% to 5.83%
    294,105       200,000                  
$100,000 stated value — 4.95%
    123,331       125,000                  
 
Total cumulative preferred stock (annual dividend requirement — $24.3 million)
    465,047       372,512       5.6       4.9  
 
Common Stockholder’s Equity:
                               
Common stock, par value $40 per share —
    330,000       290,000                  
Authorized - 15,000,000 shares
                               
Outstanding - 8,250,000 shares in 2004 and 7,250,000 shares in 2003
                               
Paid-in capital
    1,955,183       1,927,069                  
Retained earnings
    1,341,049       1,291,558                  
Accumulated other comprehensive income (loss)
    (16,028 )     (7,967 )                
 
Total common stockholder’s equity
    3,610,204       3,500,660       43.8       46.4  
 
Total Capitalization
  $ 8,239,787     $ 7,550,320       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.

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STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
For the Years Ended December 31, 2004, 2003, and 2002
Alabama Power Company 2004 Annual Report

                                         
 
                            Other        
    Common     Paid-In     Retained     Comprehensive        
    Stock     Capital     Earnings     Income (loss)     Total  
 
    (in thousands)  
Balance at December 31, 2001
  $ 240,000     $ 1,850,775     $ 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       1,900,563       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       1,927,069       1,291,558       (7,967 )     3,500,660  
Net income after dividends on preferred stock
                481,171             481,171  
Issuance of common stock
    40,000                         40,000  
Capital contributions from parent company
          28,213                   28,213  
Other comprehensive income (loss)
                      (8,061 )     (8,061 )
Cash dividends on common stock
                (437,300 )           (437,300 )
Other
          (99 )     5,620             5,521  
 
Balance at December 31, 2004
  $ 330,000     $ 1,955,183     $ 1,341,049     $ (16,028 )   $ 3,610,204  
 

The accompanying notes are an integral part of these financial statements.

STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2004, 2003, and 2002
Alabama Power Company 2004 Annual Report

                         
 
    2004     2003     2002  
 
    (in thousands)  
Net income after dividends on preferred stock
  $ 481,171     $ 472,810     $ 461,355  
 
Other comprehensive income (loss):
                       
Change in additional minimum pension liability, net of tax of $(2,482), $(2,301) and $(2,536), respectively
    (4,083 )     (3,785 )     (4,172 )
Change in fair value of marketable securities, net of tax of $252
    414              
Changes in fair value of qualifying hedges, net of tax of $(4,807), $1,330 and $(6,430), respectively
    (7,906 )     2,188       (10,576 )
Less: Reclassification adjustment for amounts included in net income, net of tax of $2,136, $4,285 and $810, respectively
    3,514       7,047       1,331  
 
Total other comprehensive income (loss)
    (8,061 )     5,450       (13,417 )
 
Comprehensive Income
  $ 473,110     $ 478,260     $ 447,938  
 

The accompanying notes are an integral part of these financial statements.

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NOTES TO FINANCIAL STATEMENTS
Alabama Power Company 2004 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 (SouthernLINC Wireless), 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. SouthernLINC Wireless 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 various other energy-related businesses. Southern Nuclear operates and provides services to Southern Company’s nuclear power plants, including the Company’s Plant Farley.

     The equity method is used for subsidiaries in which the Company has significant influence but does not control and for variable interest entities where the Company is not the primary beneficiary. Certain prior years’ data presented in the financial statements have been reclassified to conform with current year presentation.

     Southern Company is registered as a holding company under the Public Utility Holding Company Act of 1935, as amended (PUHCA). Both Southern Company and its subsidiaries are subject to the regulatory provisions of the PUHCA. In addition, the Company is 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.

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 $224 million, $217 million, and $218 million during 2004, 2003, and 2002, 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 under which Southern Nuclear operates the Company’s Plant Farley and provides 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 $169 million, $153 million, and $154 million during 2004, 2003, and 2002, respectively.

     The Company jointly owns Plant Greene County with Mississippi Power. The Company has an agreement with Mississippi Power under which the Company operates Plant Greene County, and Mississippi Power reimburses the Company for its proportionate share of expenses which were $7.2 million in 2004, $6.6 million in 2003, and $6.4 million in 2002. See Note 4 for additional information.

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NOTES (continued)
Alabama Power Company 2004 Annual Report

     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 reimbursed for its expenses. Amounts billed under this agreement totaled approximately $28.7 million, $27.5 million, and $34.5 million in 2004, 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 2004, 2003, and 2002 totaled $236.9 million, $209.2 million, and $211.0 million, respectively.

     In June 2003, the Company entered into an agreement with Southern Power under which the Company operates and maintains Plant Harris at cost. In 2004 and 2003, the Company billed Southern Power $1.8 million and $0.8 million, respectively, for operation and maintenance. Under a power purchase agreement (PPA) with Southern Power, the Company’s purchased power costs from Plant Harris in 2004 and 2003 totaled $59.0 million and $41.7 million, respectively. The Company also provides the fuel, at cost, associated with the PPA and the fuel cost recognized by the Company in 2004 was $65.7 million and $33.9 million in 2003. 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, 2004 and 2003. See Note 3 under “Retail Rate Adjustment Procedures” and Note 7 under “Purchased Power Commitments” for additional information.

     The Company has an agreement with SouthernLINC Wireless to provide digital wireless communications services to the Company. Costs for these services amounted to $5.3 million, $4.9 million, and $4.4 million during 2004, 2003, and 2002, respectively.

     Also, see Note 4 for information regarding the Company’s ownership in and PPA with Southern Electric Generating Company (SEGCO) and Note 5 for information on certain deferred tax liabilities due to affiliates.

     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.

Fuel Costs

Fuel costs are expensed as the fuel is used. Fuel expense includes the cost of purchased emission allowances as they are used. Fuel expense also 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 $61 million in 2004, $64 million in 2003, and $63 million in 2002. 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 nuclear fuel in 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. Construction of an on-site dry spent fuel storage facility at Plant Farley is in progress and scheduled for operation in 2005. The onsite storage facility is expected to provide adequate spent fuel storage through 2015 for both units and can be expanded to provide storage through 2025. See Note 7 under “Construction Program” for additional information.

     Also, the Energy Policy Act of 1992 established 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 at December 31, 2004 under this law to be approximately $9 million.

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

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NOTES (continued)
Alabama Power Company 2004 Annual Report

expected to be credited to customers through the ratemaking process.

     Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to:

                         
    2004     2003       Note
    (in millions)          
Deferred income tax charges
  $ 317     $ 321       (a )
Loss on reacquired debt
    109       111       (b )
DOE assessments
    9       13       (c )
Vacation pay
    36       36       (d )
Rate CNP under recovery
    18       17       (e )
Natural disaster reserve
    38       (13 )     (e )
Fuel-hedging assets
    6             (f )
Other assets
    14       (1 )     (e )
Asset retirement obligations
    (159 )     (127 )     (a )
Other cost of removal obligations
    (597 )     (573 )     (a )
Deferred income tax credits
    (148 )     (162 )     (a )
Deferred purchased power
    (19 )     (15 )     (e )
Other liabilities
    (2 )     (5 )     (e )
Mine reclamation & remediation
    (25 )     (33 )     (e )
Fuel-hedging liabilities
    (10 )     (6 )     (f )
         
Total
  $ (413 )   $ (437 )        
             

Notes:  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)   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.

     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 currently reflected in rates.

Revenues

Energy and other revenues are recognized as services are provided. Capacity revenues are generally recognized on a levelized basis over the appropriate contract periods. Unbilled revenues are accrued at the end of each fiscal period. 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 the actual recoverable costs and amounts billed 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. Investment tax credits utilized are deferred and amortized to income over the average life of the related property.

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 3.0 percent in 2004, 3.1 percent in 2003, and 3.2 percent in 2002. 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

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 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. Although Statement No. 143 does not permit the continued accrual of future

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retirement costs for long-lived assets that the Company does not have a legal obligation to retire, the Company has received accounting guidance from the Alabama PSC allowing such treatment. Accordingly, the accumulated removal costs for other obligations previously accrued will continue to be reflected on the balance sheets 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, 2004 was $446 million. In addition, the Company has retirement obligations related to various landfill sites and underground storage tanks. The Company has also identified retirement obligations related to certain transmission and distribution facilities, co-generation facilities, certain wireless communication towers, and certain structures authorized by the United States Army Corps of Engineers. However, 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 statements of income 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. See “Nuclear Decommissioning” herein for further information on amounts included in rates.

     Details of the asset retirement obligations included in the balance sheets are as follows:

                 
    2004     2003  
    (in millions)  
Balance beginning of year
  $ 359     $  
Liabilities incurred
          301  
Liabilities settled
           
Accretion
    25       23  
Cash flow revisions
          35  
 
Balance end of year
  $ 384     $ 359  
     

Nuclear Decommissioning

The Nuclear Regulatory Commission (NRC) requires licensees of commercial nuclear power reactors to establish a plan for providing reasonable assurance of funds for future 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 only 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, 2004, for Plant Farley were as follows:

         
Decommissioning periods:      
    Beginning year   2017  
    Completion year   2046  
      (in millions)  
Site study costs:
       
Radiated structures
  $ 892  
Non-radiated structures
    63  
   
Total
  $ 955  
   

     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.

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     Annual provisions for nuclear decommissioning are based on an annuity method as approved by the Alabama PSC. The amount expensed in 2004 and fund balances were as follows:

         
    (in millions)  
Amount expensed in 2004   $ 18  
Accumulated provisions:
       
External trust funds, at fair value
  $ 446  
Internal reserves
    29  
Total
  $ 475  

     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 adjust, if necessary, the amounts paid into the reserve and deposited into external trusts. Significant assumptions used to determine these costs for ratemaking were an inflation rate of 4.5 percent and a trust earnings rate of 7.0 percent.

     The Company filed an application with the NRC in September 2003 to extend the operating license for Plant Farley for an additional 20 years. The NRC is expected to rule on the application by July 2005. If the NRC approves the extension, the annual provision for nuclear decommissioning could decrease, subject to Alabama PSC approval.

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 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. All current construction costs are included in retail rates. The composite rate used to determine the amount of AFUDC was 8.6 percent in 2004, 9.0 percent in 2003, and 8.2 percent in 2002. AFUDC, net of income tax, as a percent of net income after dividends on preferred stock was 4.2 percent in 2004, 3.5 percent in 2003, and 3.3 percent in 2002.

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 2004, the Company accrued $22.6 million to the nuclear refueling outage reserve and at December 31, 2004 the reserve balance was a regulatory asset of $0.6 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 by either 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.

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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.

Natural Disaster Reserve

In accordance with an Alabama PSC order, the Company has established a natural disaster reserve to cover the cost of uninsured damages from major storms to transmission and distribution lines and to generation facilities and other property. 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 2004, the Company accrued $9.9 million, including an additional amount of $6.9 million, to the reserve and at December 31, 2004, the reserve balance was a regulatory asset of $37.7 million. See Note 3 under “Natural Disaster Cost Recovery” for further information.

Environmental Cost Recovery

The Company must comply with 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 may also incur substantial costs to clean up properties. The Company has received authority from the Alabama PSC to recover approved environmental compliance costs through specific retail rate clauses. Within limits approved by the Alabama PSC, these rates are adjusted annually. See Note 3 under “Retail Regulatory Matters” for additional information.

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 of Southern Company’s common stock 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.

     The pro forma impact of fair-value accounting for options granted on earnings is as follows:

                 
    As     Pro  
Net Income   Reported     Forma  
    (in thousands)  
2004
  $ 481,171     $ 478,317  
2003
    472,810       469,599  
2002
    461,355       457,928  
     

     The estimated fair values of stock options granted in 2004, 2003, and 2002 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:

                         
    2004     2003     2002  
Interest rate
    3.1 %     2.7 %     2.8 %
Average expected life of stock options (in years)
    5.0       4.3       4.3  
Expected volatility of common stock
    19.6 %     23.6 %     26.3 %
Expected annual dividends on common stock
  $ 1.40     $ 1.37     $ 1.34  
Weighted average fair value of stock options granted
  $ 3.29     $ 3.59     $ 3.37  
       

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.

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     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, 2004
  $ 4,389     $ 4,454  
At December 31, 2003
    3,903       3,958  
Preferred Securities:
               
At December 31, 2004
           
At December 31, 2003
    300       305  
     

     The fair values were based on either closing market price or closing price of comparable instruments. See “Variable Interest Entities” herein and Note 6 under “Mandatorily Redeemable Preferred Securities/Long-Term Debt Payable to Affiliate Trusts” for further information regarding the accounting treatment of the preferred securities, which underlie the Company’s long-term debt payable to affiliated trusts.

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 value of qualifying cash flow hedges and marketable securities, and changes in additional minimum pension liability, less income taxes and reclassifications for amounts included in net income.

Variable Interest Entities

On March 31, 2004, the Company prospectively adopted FASB Interpretation No. 46R, “Consolidation of Variable Interest Entities,” which requires the primary beneficiary of a variable interest entity to consolidate the related assets and liabilities. The adoption of Interpretation No. 46R had no impact on the net income of the Company. However, as a result of the adoption, the Company deconsolidated certain wholly-owned trusts established to issue preferred securities since the Company is not the primary beneficiary of the trusts. Therefore, the investments in these trusts are reflected as Other Investments, and the related loans from the trusts are reflected as Long-term Debt Payable to Affiliated Trusts on the balance sheets. This treatment resulted in a $9 million increase in both total assets and total liabilities as of March 31, 2004.

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 of 1974, as amended (ERISA), requirements. No contributions to the plan are expected for the year ending December 31, 2005. 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, 2005, postretirement trust contributions are expected to total approximately $25.3 million.

     The measurement date for plan assets and obligations is September 30 for each year.

Pension Plans

The accumulated benefit obligation for the pension plans was $1.21 billion in 2004 and $1.10 billion in 2003. Changes during the year in the projected benefit obligations, accumulated benefit obligations, and fair value of plan assets were as follows:

                 
    Projected  
    Benefit Obligations  
    2004     2003  
    (in millions)  
Balance at beginning of year
  $ 1,200     $ 1,088  
Service cost
    30       27  
Interest cost
    71       68  
Benefits paid
    (64 )     (61 )
Plan amendments
    1       3  
Actuarial (gain) loss
    87       75  
 
Balance at end of year
  $ 1,325     $ 1,200  
     
                 
    Plan Assets  
    2004     2003  
    (in millions)  
Balance at beginning of year
  $ 1,583     $ 1,419  
Actual return on plan assets
    157       226  
Benefits paid
    (64 )     (62 )
     
Balance at end of year
  $ 1,676     $ 1,583  
     

     Pension plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code of 1986, as amended (Internal Revenue Code). Southern Company’s investment policy covers a diversified mix of assets, including equity and fixed income securities, real estate,

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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. Southern Company primarily minimizes the risk of large losses through diversification but also monitors and manages other aspects of risk.

                         
    Plan Assets  
    Target     2004     2003  
Domestic equity
    37 %     36 %     37 %
International equity
    20       20       20  
Fixed income
    26       26       24  
Real estate
    10       10       11  
Private equity
    7       8       8  
       
Total
    100 %     100 %     100 %
       

     The reconciliations of the funded status with the accrued pension costs recognized in the balance sheets were as follows:

                 
    2004     2003  
    (in millions)  
Funded status
  $ 351     $ 383  
Unrecognized transition amount
          (5 )
Unrecognized prior service cost
    80       87  
Unrecognized net (gain) loss
    27       (37 )
     
Prepaid pension asset, net
  $ 458     $ 428  
     

     The prepaid pension asset, net is reflected in the balance sheets in the following line items:

                 
    2004     2003  
    (in millions)  
Prepaid pension asset
  $ 489     $ 446  
Employee benefit obligations
    (60 )     (39 )
Intangible asset
    10       8  
Accumulated other comprehensive income
    19       13  
 
Prepaid pension asset, net
  $ 458     $ 428  
     

     Components of the pension plans’ net periodic cost were as follows:

                         
    2004     2003     2002  
    (in millions)  
Service cost
  $ 30     $ 27     $ 26  
Interest cost
    71       68       74  
Expected return on plan assets
    (138 )     (138 )     (138 )
Recognized net gain
    (3 )     (12 )     (20 )
Net amortization
    4       3       2  
       
Net pension cost (income)
  $ (36 )   $ (52 )   $ (56 )
       

     Future benefit payments reflect expected future service and are estimated based on assumptions used to measure the projected benefit obligations for the pension plans. At December 31, 2004, estimated benefit payments were as follows:

         
    Benefit  
    Payments  
    (in millions)  
2005
  $ 63.9  
2006
    64.3  
2007
    65.3  
2008
    66.9  
2009
    69.4  
2010 to 2014
  $ 412.6  
   

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  
    2004     2003  
    (in millions)  
Balance at beginning of year
  $ 441     $ 405  
Service cost
    7       6  
Interest cost
    24       26  
Benefits paid
    (18 )     (20 )
Actuarial (gain) loss
    11       24  
 
Balance at end of year
  $ 465     $ 441  
     
                 
    Plan Assets  
    2004     2003  
    (in millions)  
Balance at beginning of year
  $ 186     $ 158  
Actual return on plan assets
    24       25  
Employer contributions
    20       23  
Benefits paid
    (18 )     (20 )
     
Balance at end of year
  $ 212     $ 186  
     

     Postretirement benefits plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal 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.

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    Plan Assets  
    Target     2004     2003  
Domestic equity
    46 %     46 %     50 %
International equity
    13       13       14  
Fixed income
    34       33       28  
Real estate
    4       5       5  
Private equity
    3       3       3  
         
Total
    100 %     100 %     100 %
         

     The accrued postretirement costs recognized in the balance sheets were as follows:

                 
    2004     2003  
    (in millions)  
Funded status
  $ (253 )   $ (255 )
Unrecognized transition obligation
    33       37  
Unrecognized prior service cost
    68       73  
Unrecognized net loss (gain)
    87       82  
Fourth quarter contributions
    9       6  
     
Accrued liability recognized in the balance sheets
  $ (56 )   $ (57 )  
     

     Components of the postretirement plans’ net periodic cost were as follows:

                         
    2004     2003     2002  
    (in millions)  
Service cost
  $ 7     $ 6     $ 5  
Interest cost
    24       25       25  
Expected return on plan assets
    (18 )     (17 )     (16 )
Net amortization
    9       9       9  
       
Net postretirement cost
  $ 22     $ 23     $ 23  
       

     In the third quarter 2004, the Company prospectively adopted FASB Staff Position (FSP) 106-2, Accounting and Disclosure Requirements related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (the Medicare Act). The Medicare Act provides a 28 percent prescription drug subsidy for Medicare eligible retirees. FSP 106-2 requires recognition of the impacts of the Medicare Act in the accumulated postretirement benefit obligation (APBO) and future cost of service for postretirement medical plans. The effect of the subsidy reduced the Company’s expenses for the six months ended December 31, 2004 by approximately $3.2 million and is expected to have a similar impact on future expenses. The subsidy’s impact on the postretirement medical plan APBO was a reduction of approximately $59.8 million. However, the ultimate impact on future periods is subject to federal regulations governing the subsidy created in the Medicare Act which are being finalized.

     Future benefit payments, including prescription drug benefits, reflect expected future service and are estimated based on assumptions used to measure the accumulated benefit obligation for the postretirement plans. Estimated benefit payments are reduced by drug subsidy receipts expected as a result of the Medicare Act as follows:

                         
    Benefit     Subsidy        
    Payments     Receipts     Total  
            (in millions)          
2005
  $ 20.7     $     $ 20.7  
2006
    22.0       (2.9 )     19.1  
2007
    23.3       (3.1 )     20.2  
2008
    25.2       (3.4 )     21.8  
2009
    27.8       (3.8 )     24.0  
2010 to 2014
  $ 173.2     $ (24.3 )   $ 148.9  
       

     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:

                         
    2004     2003     2002  
Discount
    5.75 %     6.00 %     6.50 %
Annual salary increase
    3.50       3.75       4.00  
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 obligations was a weighted average medical care cost trend rate of 11 percent for 2004, decreasing gradually to 5 percent through the year 2012, 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, 2004 as follows:

                 
    1 Percent     1 Percent  
    Increase     Decrease  
    (in millions)  
Benefit obligation
  $ 41     $ 32  
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

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percent of an employee’s base salary. Total matching contributions made to the plan for 2004, 2003, and 2002 were $13 million, $12 million, and $12 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.

Environmental Matters

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 related state laws with respect to coal-fired generating facilities at the Company’s Plants Miller, Barry, and Gorgas. The EPA concurrently issued to the Company a notice of violation relating to these specific facilities, as well as Plants Greene County and Gaston. In early 2000, the EPA filed a motion to amend its complaint to add the violations alleged in its notice of violation.

     The U.S. District Court in Georgia subsequently granted the Company’s motion to dismiss for lack of jurisdiction in Georgia. In March 2001, the court granted the EPA’s motion to add Savannah Electric as a defendant. 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 the Company in the U.S. District Court for the Northern District of Alabama. These civil complaints allege violations with respect to eight coal-fired generating facilities in Alabama and Georgia, and they request penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The EPA has not refiled against Gulf Power or Mississippi Power.

     The actions against the Company, Georgia Power, and Savannah Electric were effectively stayed in the spring of 2001 during the appeal of a similar NSR enforcement action against the Tennessee Valley Authority (TVA) before the U.S. Court of Appeals for the Eleventh Circuit. In June 2003, the Court of Appeals issued its ruling in the TVA case, dismissing the appeal for reasons unrelated to the issues in the cases pending against the Company, Georgia Power, and Savannah Electric. In May 2004, the U.S. Supreme Court denied the EPA’s petition for review of the case. In June 2004, the U.S. District Court for the Northern District of Alabama lifted the stay in the action against Alabama Power, placing the case back onto the Court’s active docket. At this time, no party to the case against Georgia Power and Savannah Electric has sought to reopen that case, which remains administratively closed in the District Court for the Northern District of Georgia.

     Since the inception of the NSR proceedings against the Company, Georgia 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. District courts addressing these cases have, to date, issued opinions that reached conflicting conclusions.

     The Company believes that it complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $32,500 per day, per violation at each generating unit, depending on the date of the alleged violation. 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.

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     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 (RMRR) exclusion. A coalition of states and environmental organizations has filed petitions for review of these revisions with the U.S. Court of Appeals for the District of Columbia Circuit. The October 2003 RMRR rules have been stayed by the Court of Appeals pending its review of the rules. 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, related legal challenges, and potential state rulemakings cannot be determined at this time.

Generation Interconnection Agreements

In July 2003, the FERC issued its final rule on the standardization of generation interconnection agreements and procedures (Order 2003). Order 2003 shifts much of the financial burden of new transmission investment from the generator to the transmission provider. The FERC has indicated that Order 2003, which was effective January 20, 2004, is to be applied prospectively to interconnection agreements. Subsidiaries of Tenaska, Inc., as counterparties to two previously executed interconnection agreements with the Company, have filed complaints at the FERC requesting that the FERC modify the agreements and that the Company refund a total of $11 million previously paid for interconnection facilities, with interest. The Company has also received similar requests from other entities totaling $2.5 million. The Company has opposed such relief, and the proceedings are still pending. The impact of Order 2003 and its subsequent rehearings on the Company and the final results of these matters cannot be determined at this time.

Market-Based Rate Authority

The Company has authorization from the FERC to sell power to nonaffiliates at market-based prices. 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, the retail operating companies, and Southern Power, and found them and others to be “pivotal suppliers” in their retail service territories 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. In April 2004, the FERC issued an order that abandoned the SMA test and adopted a new interim analysis for measuring generation market power. This new interim approach requires utilities to submit a pivotal supplier screen and a wholesale market share screen. If the applicant does not pass both screens, there will be a rebuttable presumption regarding generation market power. The FERC’s order also sets forth procedures for rebutting these presumptions and addresses mitigation measures for those entities that are found to have market power. In the absence of specific mitigation measures, the order includes several cost-based mitigation measures that would apply by default. The FERC also initiated a new rulemaking proceeding that, among other things, will adopt a final methodology for assessing generation market power.

     In July 2004, the FERC denied Southern Company’s request for rehearing, along with a number of others, and reaffirmed the interim tests that it adopted in April. In August 2004, Southern Company submitted a filing to the FERC that included results showing that Southern Company passed the pivotal supplier screen for all markets and the wholesale market share screen for all markets except the Southern Company retail service territory. Southern Company also submitted other analyses to demonstrate that it lacks generation market power. On December 17, 2004, the FERC initiated a proceeding to assess Southern Company’s generation dominance within its retail service territory. The ability to charge market- based rates in other markets is not at issue. As directed by this order, Southern Company submitted additional information on February 15, 2005 related to generation dominance in its retail service territory. Any new market based rate transactions in Southern Company’s retail service territory entered into after February 27, 2005 will be subject to refund to the level of the default cost-based rates, pending the outcome of the proceeding. Southern Company, along with other utilities, has also filed an appeal of the FERC’s April and July 2004 orders with the U.S. Court of Appeals for the District of Columbia Circuit. The FERC has asked the court to dismiss the appeal on the grounds that it is premature.

     In the event that the FERC’s default mitigation measures are ultimately applied, the Company may be required to charge cost-based rates for certain wholesale sales in Southern Company’s retail service

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territory, which may be lower than negotiated market-based rates. The final outcome of this matter will depend on the form in which the final methodology for assessing generation market power and mitigation rules may be ultimately adopted and cannot be determined at this time.

Natural Disaster Cost Recovery

In September 2004, Hurricane Ivan hit the Gulf Coast of Florida and Alabama and continued north through the Company’s service territory causing substantial damage. The related costs charged to the Company’s natural disaster reserve were $57.8 million. During 2004, the Company accrued $9.9 million to the reserve and at December 31, 2004, the reserve balance was a regulatory asset of $37.7 million.

     In February 2005, the Company requested and received Alabama PSC approval of an accounting order that allows the Company to immediately return certain regulatory liabilities to the retail customers. The order also allows the Company to simultaneously recover from customers an accrual of approximately $45 million to offset the costs of Hurricane Ivan and restore the natural disaster reserve. The combined effects of this order will have no impact on the Company’s net income in 2005.

Retail Regulatory Matters

The Alabama PSC has adopted a Rate Stabilization and Equalization plan (Rate RSE) that provides for periodic annual adjustments based upon the Company’s earned return on end-of-period retail common equity. Such annual adjustments are limited to 3 percent. Rates remain unchanged when the return on common equity ranges between 13.0 percent and 14.5 percent. The Alabama PSC has also approved a rate mechanism that provides 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 (Rate CNP). Both increases and decreases have been placed into effect since the adoption of these rates.

     In accordance with Rate RSE, a 2 percent increase in retail rates was effective in April 2002, amounting to an annual increase of $55 million. Also, to recover certificated purchased power costs under Rate CNP, an increase of 2.6 percent in retail rates, or $79 million annually, was effective July 2003. An additional increase of $25 million annually was effective July 2004 under Rate CNP for new certificated purchased power costs. In April 2005, an annual true-up adjustment to Rate CNP will decrease retail rates by approximately 0.5 percent, or $18.5 million annually.

     In October 2004, the Alabama PSC approved a request by the Company to amend Rate CNP to also provide for the recovery of retail costs associated with environmental laws and regulations, effective in January 2005. In conjunction with the Alabama PSC’s approval, the Company agreed to a moratorium until March 2007 on any retail rate increase under Rate RSE. Any increase in March 2007 would be based upon the earned return on retail common equity at December 31, 2006 and would become effective with the April 2007 billing.

     The Company’s fuel costs are recovered under Rate ECR (Energy Cost Recovery), which provides for the addition of a fuel and energy cost factor to base rates. In April 2005, this factor is scheduled to increase from its current level.

     The ratemaking procedures will remain in effect until the Alabama PSC votes to modify or discontinue them.

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, as well as 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 $86 million in 2004, $87 million in 2003, and $84 million in 2002 and is included in “Purchased power from affiliates” in the statements of income. The Company accounts for SEGCO using the equity method on the balance sheets.

     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. Also, the Company has guaranteed $50 million principal amount of unsecured senior notes issued by SEGCO for general corporate purposes. Georgia Power has agreed to reimburse

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the Company for the pro rata portion of such obligations corresponding to its then proportionate ownership of stock of SEGCO if the Company is called upon to make such payment under its guaranty.

     At December 31, 2004, the capitalization of SEGCO consisted of $59 million of equity and $88 million of debt on which the annual interest requirement is $3.2 million. SEGCO paid dividends totaling $12.0 million in 2004, $2.3 million in 2003, and $5.8 million in 2002, 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, 2004 is as follows:

                 
    Total        
    Megawatt     Company  
Facility (Type)   Capacity     Ownership  
Greene County (coal)
    500       60.00 %(1)
Plant Miller Units 1 and 2 (coal)
    1,320       91.84 %(2)
 
(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
  $ 114     $ 56  
Plant Miller Units 1 and 2
    776       356  
 

     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 operating expenses in the statements of income.

5. INCOME TAXES

Southern Company files a consolidated federal income tax return and a combined State of Georgia income tax return. Under a joint consolidated income tax allocation agreement, as required by the PUHCA, each subsidiary’s current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more expense than would be paid if they filed a separate income tax return. In accordance with IRS regulations, each company is jointly and severally liable for the tax liability.

     In 2004, in order to avoid the loss of certain federal income tax credits related to the production of synthetic fuel, Southern Company chose to defer certain deductions otherwise available to the subsidiaries. The cash flow benefit associated with the utilization of the tax credits was allocated to the subsidiary that otherwise would have claimed the available deductions on a separate company basis without the deferral. This allocation concurrently reduced the tax benefit of the credits allocated to those subsidiaries that generated the credits. As the deferred expenses are deducted, the benefit of the tax credits will be repaid to the subsidiaries that generated the tax credits. The Company has recorded $21.4 million and $2.3 million payable to these subsidiaries in “Accumulated Deferred Income Taxes” and “Accrued Taxes – Income Tax”, respectively, on the balance sheets.

     At December 31, 2004, the Company’s tax-related regulatory assets and liabilities were $317 million and $148 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:

                         
    2004     2003     2002  
    (in millions)  
Total provision for income taxes:
                       
Federal —
                       
Current
  $ 44     $ 111     $ 209  
Deferred
    219       137       41  
 
 
    263       248       250  
 
State —
                       
Current
    16       26       35  
Deferred
    34       16       7  
 
 
    50       42       42  
 
Total
  $ 313     $ 290     $ 292  
 

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     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:

                 
    2004     2003  
    (in millions)  
Deferred tax liabilities:
               
Accelerated depreciation
  $ 1,524     $ 1,319  
Property basis differences
    461       466  
Premium on reacquired debt
    45       46  
Pensions
    136       128  
Fuel clause under recovered
    48        
Other
    36       29  
 
Total
    2,250       1,988  
 
Deferred tax assets:
               
Federal effect of state deferred taxes
    112       100  
State effect of federal deferred taxes
    110       98  
Pole attachment rentals
    45       27  
Unbilled revenue
    22       23  
Pension and other benefits
    16       15  
Fuel clause over recovered
          2  
Other
    32       72  
 
Total
    337       337  
 
Total deferred tax liabilities, net
    1,913       1,651  
Portion included in current (liabilities) assets, net
    (28 )     34  
 
Accumulated deferred income taxes in the balance sheets
  $ 1,885     $ 1,685  
 

     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 2004, 2003, and 2002. At December 31, 2004, 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:

                         
    2004     2003     2002  
Federal statutory rate
    35.0 %     35.0 %     35.0 %
State income tax, net of federal deduction
    4.0       3.5       3.5  
Non-deductible book depreciation
    1.1       1.2       1.3  
Differences in prior years’ deferred and current tax rates
    (0.8 )     (0.9 )     (1.2 )
Other
    (1.0 )     (1.6 )     (0.5 )
 
Effective income tax rate
    38.3 %     37.2 %     38.1 %
 

6. FINANCING

Mandatorily Redeemable Preferred Securities/Long-Term Debt Payable to Affiliated Trusts

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 and are reflected on the balance sheets as Long-term Debt Payable to Affiliated 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, 2004, preferred securities of $300 million were outstanding. See Note 1 under “Variable Interest Entities” for additional information on the accounting treatment for these trusts and the related securities.

First Mortgage Bonds

The Company has 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 through October 2006. 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, 2004, $18.7 million of these bonds were held by the escrow agent under the contract.

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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 and Preferred Stock

The Company issued a total of $900 million of unsecured senior notes and $100 million of preferred stock in 2004. The proceeds of these issues were used to redeem or repay at maturity long-term debt, to repay short-term indebtedness, and for other general corporate purposes.

     At December 31, 2004 and 2003, the Company had $3.5 billion and $3.4 billion of senior notes outstanding, respectively. These senior notes are subordinate to all secured debt of the Company which amounted to approximately $286 million at December 31, 2004.

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:

                 
    2004     2003  
    (in millions)  
Capitalized leases
  $     $ 1  
Senior notes
    225       525  
 
Total
  $ 225     $ 526  
 

     Debt serial maturities through 2009 applicable to total long-term debt are as follows: $225 million in 2005; $715 million in 2006; $500 million in 2007; $410 million in 2008; and $250 million in 2009.

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 $868 million (including $504 million of such lines which are dedicated to funding purchase obligations relating to variable rate pollution control bonds), of which $643 million will expire at various times during 2005. $225 million of the credit facilities expiring in 2005 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 banks.

     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 arrangements. For purposes of calculating these covenants, long-term notes payable to affiliated trusts are excluded from debt but included in capitalization. Exceeding this debt level would result in a default under the credit arrangements. At December 31, 2004, 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, 2004 and 2003, the Company had no extendible commercial notes and no commercial paper outstanding. During 2004, the peak amount outstanding for commercial paper was $190 million and the average amount outstanding was $41.5 million. The average annual interest rate on commercial paper in 2004 was 1.51 percent. Commercial paper and extendible commercial notes are included in notes payable on the balance sheets.

     At December 31, 2004, the Company had regulatory approval to have outstanding up to $1 billion of short-term borrowings.

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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. There was no material ineffectiveness recorded in earnings in 2004 and 2003.

     At December 31, 2004, the fair value of derivative energy contracts was reflected in the financial statements as follows:

         
    Amounts  
    (in thousands)  
Regulatory liabilities, net
  $ 3,978  
Net income
    39  
 
Total fair value
  $ 4,017  
 

     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 has energy-related hedges in place through 2007.

     The Company also enters into derivatives to hedge exposure to changes in interest rates. Derivatives related to variable rate securities or forecasted transactions are accounted for as cash flow hedges. As the derivatives employed as hedging instruments are generally structured to match the critical terms of the hedged debt instruments, no material ineffectiveness has been recorded in earnings.

     At December 31, 2004, the Company had $981 million notional amount of interest rate swaps outstanding with net fair value losses of $7.2 million as follows:

Cash Flow Hedges

                         
    Weighted Average             Fair  
    Fixed             Value  
    Rate     Notional     Gain/  
Maturity   Paid     Amount     (Loss)  
            (in millions)  
2006
    1.89       $ 195     $ 3.2  
2007
       2.01*         536       5.6  
2035
    5.68         250       (16.0 )
 
*   Hedged using the Bond Market Association Municipal Swap Index.

     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 2004 and 2003, the Company settled gains (losses) of $5.5 million and $(8) million, respectively, upon termination of certain interest derivatives at the same time it issued debt. These gains (losses) have been deferred in other comprehensive income and will be amortized to interest expense over the life of the original interest derivative, which approximates to the underlying related debt.

     For the years 2004, 2003 and 2002, approximately $6.3 million, $11.3 million, and $2.1 million, respectively, of pre-tax losses were reclassified from other comprehensive income to interest expense. For 2005, pre-tax gains of approximately $0.7 million are expected to be reclassified from other comprehensive income to interest expense. The Company has interest-related hedges in place through 2035.

7. COMMITMENTS

Construction Program

The Company is engaged in continuous construction programs, currently estimated to total $902 million in 2005, $921 million in 2006, and $1.0 billion in 2007. These amounts include $24 million, $12 million, and $11 million in 2005, 2006, and 2007, respectively, for construction expenditures related to contractual purchase commitments for uranium and nuclear fuel conversion, enrichment, and fabrication services included 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, 2004, 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.

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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 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, 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 for facilities owned are currently estimated at $253 million over the term of the agreements, which are approximately 12 to 14 years per unit. At December 31, 2004, the remaining balance was approximately $193 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 either prepayments or other deferred charges and assets 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, 2004 were as follows:

                         
    Commitments  
            Non-        
Year   Affiliated     Affiliated     Total  
    (in millions)  
2005
  $ 50     $ 37     $ 87  
2006
    50       37       87  
2007
    50       38       88  
2008
    50       39       89  
2009
    50       40       90  
2010 and thereafter
    13       25       38  
 
Total commitments
  $ 263     $ 216     $ 479  
 

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. Coal commitments include forward contract purchases for sulfur dioxide emission allowances. 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 Exchange future prices at December 31, 2004. Total estimated minimum long-term commitments at December 31, 2004 were as follows:

                 
            Coal &  
    Natural     Nuclear  
Year   Gas     Fuel  
    (in millions)  
2005
  $ 249     $ 907  
2006
    195       804  
2007
    114       713  
2008
    26       225  
2009
    26       131  
2010 and thereafter
    108       97  
 
Total commitments
  $ 718     $ 2,877  
 

     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 $28.3

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million in 2004, $29.5 million in 2003, and $29.6 million in 2002. Of these amounts, $16.3 million, $19.4 million, and $19.1 million for 2004, 2003, and 2002, respectively, relates to the rail car leases and are recoverable through the Company’s Rate ECR clause. At December 31, 2004, estimated minimum rental commitments for noncancellable operating leases were as follows:

                         
    Rail     Vehicles        
Year   Cars     & Other     Total  
    (in millions)  
2005
  $ 17.7     $ 11.4     $ 29.1  
2006
    14.1       8.6       22.7  
2007
    6.9       5.7       12.6  
2008
    6.6       4.0       10.6  
2009
    4.8       3.6       8.4  
2010 and thereafter
    27.4       7.2       34.6  
 
Total minimum payments
  $ 77.5     $ 40.5     $ 118.0  
 

     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 2006 and 2009, and the Company’s maximum obligations are $66 million and $19.5 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, 2004, the Company had outstanding guarantees related to SEGCO’s purchase of certain pollution control facilities and issuance of senior notes, as discussed in Note 4, and to certain residual values of leased assets. See “Operating Leases” above.

8. STOCK OPTION PLAN

Southern Company provides non-qualified stock options to a large segment of the Company’s employees ranging from line management to executives. As of December 31, 2004, 1,111 current and former employees of the Company participated in this stock option plan. The maximum number of shares of Southern Company common stock that may be issued under the plan may not exceed 55 million. The prices of options granted to date have been at the fair market value of the shares on the dates of grant. Options granted to date become exercisable pro rata over a maximum period of three years from the date of grant. Options outstanding will expire no later than 10 years after the date of grant, unless terminated earlier by the Southern Company Board of Directors in accordance with the stock option plan. Activity from 2002 to 2004 for the options granted to the Company’s employees under the stock option plan is summarized below:

                 
    Shares     Average  
    Subject     Option Price  
    to Option     per Share  
 
Balance at December 31, 2001
    5,201,605     $ 17.56  
Options granted
    1,332,716       25.26  
Options canceled
    (12,515 )     22.59  
Options exercised
    (827,883 )     15.03  
 
Balance at December 31, 2002
    5,693,923       19.72  
Options granted
    1,201,677       27.98  
Options canceled
    (6,726 )     23.11  
Options exercised
    (1,043,013 )     16.16  
 
Balance at December 31, 2003
    5,845,861       22.05  
Options granted
    1,168,140       29.50  
Options canceled
    (3,379 )     28.82  
Options exercised
    (1,252,277 )     18.07  
 
Balance at December 31, 2004
    5,758,345       24.42  
 
 
               
 
Options exercisable:
               
At December 31, 2002
    2,702,614          
At December 31, 2003
    3,171,383          
At December 31, 2004
    3,404,264          
 

     The following table summarizes information about options outstanding at December 31, 2004:

                         
    Dollar Price  
    Range of Options  
    13-20     20-26     26-32  
Outstanding:
                       
Shares (in thousands)
    1,386       2,032       2,340  
Average remaining life (in years)
    5.7       6.8       8.6  
Average exercise price
  $ 17.56     $ 24.12     $ 28.74  
Exercisable:
                       
Shares (in thousands)
    1,386       1,609       409  
Average exercise price
  $ 17.56     $ 23.83     $ 28.00  
 

9. 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 $10.76 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

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NOTES (continued)
Alabama Power Company 2004 Annual Report

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 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 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 $39 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. 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.

10. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

Summarized quarterly financial information for 2004 and 2003 are as follows:

                         
                    Net Income  
                    After  
                    Dividends  
Quarter   Operating     Operating     on Preferred  
Ended   Revenues     Income     Stock  
    (in millions)  
March 2004
  $ 960     $ 202     $ 91  
June 2004
    1,059       239       104  
September 2004
    1,246       415       220  
December 2004
    971       164       66  
 
                       
March 2003
  $ 890     $ 211     $ 92  
June 2003
    950       227       107  
September 2003
    1,216       414       217  
December 2003
    904       163       57  
 

     The Company’s business is influenced by seasonal weather conditions.

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SELECTED FINANCIAL AND OPERATING DATA 2000-2004
Alabama Power Company 2004 Annual Report

                                         
   
    2004     2003     2002     2001     2000  
 
Operating Revenues (in thousands)
  $ 4,235,991     $ 3,960,161     $ 3,710,533     $ 3,586,390     $ 3,667,461  
Net Income after Dividends on Preferred Stock (in thousands)
  $ 481,171     $ 472,810     $ 461,355     $ 386,729     $ 419,916  
Cash Dividends on Common Stock (in thousands)
  $ 437,300     $ 430,200     $ 431,000     $ 393,900     $ 417,100  
Return on Average Common Equity (percent)
    13.53       13.75       13.80       11.89       13.58  
Total Assets (in thousands)
  $ 12,783,459     $ 12,102,796     $ 11,591,666     $ 11,303,605     $ 11,228,118  
Gross Property Additions (in thousands)
  $ 797,014     $ 661,154     $ 645,262     $ 635,540     $ 870,581  
 
Capitalization (in thousands):
                                       
Common stock equity
  $ 3,610,204     $ 3,500,660     $ 3,377,740     $ 3,310,877     $ 3,195,772  
Preferred stock
    465,047       372,512       247,512       317,512       317,512  
Mandatorily redeemable preferred securities
          300,000       300,000       347,000       347,000  
Long-term debt payable to affiliated trusts
    309,279                          
Long-term debt
    3,855,257       3,377,148       2,872,609       3,742,346       3,425,527  
 
Total (excluding amounts due within one year)
  $ 8,239,787     $ 7,550,320     $ 6,797,861     $ 7,717,735     $ 7,285,811  
 
Capitalization Ratios (percent):
                                       
Common stock equity
    43.8       46.4       49.7       42.9       43.9  
Preferred stock
    5.6       4.9       3.6       4.1       4.4  
Mandatorily redeemable preferred securities
          4.0       4.4       4.5       4.8  
Long-term debt payable to affiliated trusts
    3.8                          
Long-term debt
    46.8       44.7       42.3       48.5       46.9  
 
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
    AA-       A+       A+       A+       AA-  
Preferred Stock -
                                       
Moody’s
    Baa1       Baa1       Baa1       Baa1       a2  
Standard and Poor’s
    BBB+       BBB+       BBB+       BBB+       BBB+
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
    1,170,814       1,160,129       1,148,645       1,139,542       1,132,410  
Commercial
    208,547       204,561       203,017       196,617       193,106  
Industrial
    5,260       5,032       4,874       4,728       4,819  
Other
    753       757       789       751       745  
 
Total
    1,385,374       1,370,479       1,357,325       1,341,638       1,331,080  
 
Employees (year-end):
    6,745       6,730       6,715       6,706       6,871  
 

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SELECTED FINANCIAL AND OPERATING DATA 2000-2004 (continued)
Alabama Power Company 2004 Annual Report

                                         
   
    2004     2003     2002     2001     2000  
 
Operating Revenues (in thousands):
                                       
Residential
  $ 1,346,669     $ 1,276,800     $ 1,264,431     $ 1,138,499     $ 1,222,509  
Commercial
    980,771       913,697       882,669       829,760       854,695  
Industrial
    948,528       844,538       788,037       763,934       859,668  
Other
    16,860       16,428       16,080       15,480       15,835  
 
Total retail
    3,292,828       3,051,463       2,951,217       2,747,673       2,952,707  
Sales for resale — non-affiliates
    483,839       487,456       474,291       485,974       461,730  
Sales for resale — affiliates
    308,312       277,287       188,163       245,189       166,219  
 
Total revenues from sales of electricity
    4,084,979       3,816,206       3,613,671       3,478,836       3,580,656  
Other revenues
    151,012       143,955       96,862       107,554       86,805  
 
Total
  $ 4,235,991     $ 3,960,161     $ 3,710,533     $ 3,586,390     $ 3,667,461  
 
Kilowatt-Hour Sales (in thousands):
                                       
Residential
    17,368,321       16,959,566       17,402,645       15,880,971       16,771,821  
Commercial
    13,822,926       13,451,757       13,362,631       12,798,711       12,988,728  
Industrial
    22,854,399       21,593,519       21,102,568       20,460,022       22,101,407  
Other
    198,253       203,178       205,346       198,102       205,827  
 
Total retail
    54,243,899       52,208,020       52,073,190       49,337,806       52,067,783  
Sales for resale — non-affiliates
    15,483,420       17,085,376       15,553,545       15,277,839       14,847,533  
Sales for resale — affiliates
    7,233,880       9,422,301       8,844,050       8,843,094       5,369,474  
 
Total
    76,961,199       78,715,697       76,470,785       73,458,739       72,284,790  
 
Average Revenue Per Kilowatt-Hour (cents):
                                       
Residential
    7.75       7.53       7.27       7.17       7.29  
Commercial
    7.10       6.79       6.61       6.48       6.58  
Industrial
    4.15       3.91       3.73       3.73       3.89  
Total retail
    6.07       5.84       5.67       5.57       5.67  
Sales for resale
    3.49       2.88       2.72       3.03       3.11  
Total sales
    5.31       4.85       4.73       4.74       4.95  
Residential Average Annual Kilowatt-Hour Use Per Customer
    14,894       14,688       15,198       13,981       14,875  
Residential Average Annual Revenue Per Customer
  $ 1,155     $ 1,106     $ 1,104     $ 1,002     $ 1,084  
Plant Nameplate Capacity Ratings (year-end) (megawatts)
    12,216       12,174       12,153       12,153       12,122  
Maximum Peak-Hour Demand (megawatts):
                                       
Winter
    9,556       10,409       9,423       9,300       9,478  
Summer
    10,938       10,462       10,910       10,241       11,019  
Annual Load Factor (percent)
    63.2       64.1       62.9       62.5       59.3  
Plant Availability (percent):
                                       
Fossil-steam
    87.8       85.9       85.8       87.1       89.4  
Nuclear
    88.7       94.7       93.2       83.7       88.3  
 
Source of Energy Supply (percent):
                                       
Coal
    56.5       56.5       55.5       56.8       63.0  
Nuclear
    16.4       17.0       17.1       15.8       16.9  
Hydro
    5.6       7.0       5.1       5.1       2.9  
Gas
    8.9       7.6       11.6       10.7       4.9  
Purchased power -
                                       
From non-affiliates
    5.4       4.1       4.0       4.4       4.6  
From affiliates
    7.2       7.8       6.7       7.2       7.7  
 
Total
    100.0       100.0       100.0       100.0       100.0  
 

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GEORGIA POWER COMPANY

 
 
 
FINANCIAL SECTION
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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, 2004 and 2003, 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, 2004. 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.

     We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (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 consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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-143 to II-173) present fairly, in all material respects, the financial position of Georgia Power Company at December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004, 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
February 28, 2005

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2004 Annual Report

OVERVIEW

Business Activities

Georgia Power Company (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.

     Many factors affect the opportunities, challenges and risks 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 stringent environmental standards. In 2004, the Company completed a major retail rate proceeding that should help provide future earnings stability. This regulatory action will also enable the recovery of substantial capital investments to facilitate the continued reliability of the transmission and distribution network and continue environmental improvements at the generating plants. Appropriately balancing environmental expenditures with customer prices will continue to challenge the Company for the foreseeable future.

Key Performance Indicators

The Company strives to maximize shareholder value while providing low-cost energy to more than 2 million customers by focusing on several key indicators. These include customer satisfaction, peak season equivalent forced outage rate (Peak Season EFOR), and return on equity (ROE). The Company’s financial success is directly tied to the satisfaction of its customers. Key elements of ensuring that satisfaction include outstanding service, high reliability, and competitive prices. Management uses nationally recognized customer satisfaction surveys and reliability indicators to evaluate the Company’s results. Peak Season EFOR is an indicator of plant availability and efficient generation fleet operations during the months when generation needs are greatest. The rate is calculated by dividing the number of hours of forced outages by total generation hours. ROE is a performance standard used by the investment community and many regulatory agencies.

     The Company’s 2004 results compared to its targets for each of these indicators are reflected in the following chart.

                         
 
        2004     2004  
        Target     Actual  
  Key Performance Indicator     Performance     Performance  
 
Customer Satisfaction
    Top quartile performance on
national surveys
    Top quartile  
 
Peak Season EFOR
    2.90% or less       0.81 %  
 
ROE
      13.70 %       13.95 %  
 

     The strong financial performance achieved in 2004 reflects the focus that management places on these indicators, as well as the commitment shown by employees in achieving or exceeding management’s expectations.

Earnings

The Company’s 2004 earnings totaled $658 million representing a $27 million (4.3 percent) increase over 2003. Operating income increased in 2004 due to higher base retail revenues attributable to more favorable weather and customer growth during the year, partially offset by higher non-fuel operating expenses. In addition, lower depreciation and amortization expense in the final year of a Georgia Public Service Commission (PSC) retail rate plan that was effective January 2002 (2001 Retail Rate Plan) significantly offset increased purchased power capacity expenses. The 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 resulting from lower financing costs and a lower effective tax rate due to the realization of certain state tax credits. 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 the 2001 Retail Rate Plan.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2004 Annual Report

RESULTS OF OPERATIONS

A condensed income statement for the Company is as follows:

                                 
            Increase (Decrease)
    Amount     From Prior Year  
    2004     2004     2003     2002  
    (in millions)  
Operating revenues
  $ 5,371     $ 457     $ 92     $ (144 )
 
Fuel
    1,233       128       101       64  
Purchased power
    976       200       92       (87 )
Other operation and maintenance
    1,400       153       (78 )     85  
Depreciation and amortization
    275       (74 )     (54 )     (197 )
Taxes other than income taxes
    228       15       11       (1 )
 
Total operating expenses
    4,112       422       72       (136 )
 
Operating income
    1,259       35       20       (8 )
Total other income and (expense)
    (221 )     5       2       9  
Income taxes
    379       13       9       (7 )
 
Net income
    659       27       13       8  
Dividends on preferred stock
    1                    
 
Net income after dividends on preferred stock
  $ 658     $ 27     $ 13     $ 8  
 

Revenues

Operating revenues in 2004, 2003, and 2002 and the percent of change from the prior year are as follows:

                         
    Amount  
    2004     2003     2002  
    (in millions)  
Retail — prior year
  $ 4,310     $ 4,288     $ 4,349  
Change in -
                       
Base rates
                (118 )
Sales growth and other
    151       30       2  
Weather
    32       (66 )     82  
Fuel cost recovery and other
    284       58       (27 )
 
Retail — current year
    4,777       4,310       4,288  
 
Sales for resale -
                       
Non-affiliates
    247       260       271  
Affiliates
    166       175       98  
 
Total sales for resale
    413       435       369  
 
Other operating revenues
    181       169       165  
 
Total operating revenues
  $ 5,371     $ 4,914     $ 4,822  
 
Percent change
    9.3 %     1.9 %     (2.9 )%
 

     Retail base revenues of $3.2 billion in 2004 increased by $183 million (6.0 percent) from 2003 primarily due to an improved economy, customer growth, generally higher prices to the Company’s large business customers, and more favorable weather. Retail base revenues of $3 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. 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 2001 Retail Rate Plan and generally lower prices to large business customers.

     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. In August 2003, the Georgia PSC issued an order allowing the Company to increase customer fuel rates to recover existing under recovered deferred fuel costs. In recent months, the Company has experienced higher than expected fuel costs for coal and gas. Those higher fuel costs have increased the under recovered fuel costs. On February 18, 2005, the Company filed a

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request with the Georgia PSC for a fuel cost recovery rate increase. In the ordinary course, these new rates will be effective June 1, 2005 following a hearing before and approval by the Georgia PSC. In its filing, the Company asked that the Georgia PSC accept the new rate, effective April 1, 2005, prior to a formal hearing on the Company’s request. This action, if taken by the Georgia PSC, would serve to mitigate expected increases in the under recovered balance during April and May, but will not preclude the Georgia PSC from subsequently adjusting the rates. The requested increase, representing an annual increase in revenues of approximately 11.7 percent, will allow for the recovery of fuel costs based on an estimate of future fuel costs, as well as the collection of the existing under recovery of fuel costs. The Company’s under recovered fuel costs as of January 31, 2005 totaled $390 million. The Georgia PSC will examine the Company’s fuel expenditures and determine whether the proposed fuel cost recovery rate is just and reasonable before issuing its decision in May 2005. The final outcome of the filing cannot be determined at this time. See Note 3 to the financial statements under “Fuel Cost Recovery” for further information regarding this filing.

     Wholesale revenues from sales to non-affiliated utilities were:

                         
    2004     2003     2002  
    (in millions)  
Unit power sales —
                       
Capacity
  $ 31     $ 34     $ 34  
Energy
    33       31       34  
Other power sales —
                       
Capacity
    75       93       62  
Energy
    108       102       141  
 
Total
  $ 247     $ 260     $ 271  
 

     Revenues from unit power sales contracts remained relatively constant in 2004. Revenues from unit power contracts decreased slightly in 2003 due to decreased energy sales. Revenues from other non-affiliated sales decreased $12 million (6.2 percent), $8 million (3.9 percent), and $102 million (33.4 percent) in 2004, 2003, and 2002, respectively, 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. These affiliated sales and purchases are made in accordance with the affiliate company interchange agreement, as approved by the Federal Energy Regulatory Commission (FERC). In 2004, kilowatt-hour (KWH) energy sales to affiliates decreased 18.2 percent due to lower demand. However, the decline in associated revenues was only 4.9 percent due to higher fuel prices. In 2003, KWH 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 $11.7 million (6.9 percent) in 2004 primarily due to higher revenues from outdoor lighting of $4.2 million and pole attachment rentals of $4.9 million and higher gains on sales of emission allowances of $2 million. 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 revenues from the rental of electric property of $4 million. Other operating revenues in 2002 increased $14 million (9.5 percent) primarily due to the collection of new late payment fees approved under the 2001 Retail Rate Plan 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.

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Energy Sales

KWH sales for 2004 and the percent change by year were as follows:

                                 
    KWH     Percent Change  
    2004     2004     2003     2002  
    (in billions)                    
Residential
    22.9       5.3 %     (1.7 )%     10.1 %
Commercial
    28.0       4.0       (0.1 )     1.7  
Industrial
    26.4       2.5       (0.1 )     1.5  
Other
    0.6       1.1       0.4       1.7  
 
                             
Total retail
    77.9       3.8       (0.5 )     4.0  
 
                             
Sales for resale -
                               
Non-affiliates
    6.0       (32.5 )     9.5       (0.5 )
Affiliates
    4.8       (18.2 )     47.5       26.5  
 
                             
Total sales for resale
    10.8       (26.8 )     22.0       7.0  
 
                             
Total sales
    88.7       (1.2 )     2.6       4.4  
 

     Residential KWH sales increased 5.3 percent in 2004 due to more favorable weather and a 1.9 percent increase in residential customers. Commercial KWH sales increased 4.0 percent in 2004 due to an improved economy and a 2.8 percent increase in commercial customers. Industrial sales increased 2.5 percent in 2004 due to the improved economy. Residential KWH sales decreased 1.7 percent in 2003 due to the effect of the milder summer weather, despite the 2.0 percent increase in residential customers. Commercial KWH sales in 2003 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 in 2002 increased 1.7 percent and 1.5 percent, respectively, due to corresponding increases of 2.6 percent and 2.4 percent, respectively, in customers. Retail sales growth assuming normal weather is expected to be 1.9 percent on average from 2005 to 2009.

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, the average cost of fuel per net KWH generated, and the average cost of purchased power per net KWH were as follows:

                         
    2004     2003     2002  
Total generation (billions of KWH)
    71.5       73.1       70.4  
Sources of generation (percent) —
                       
Coal
    75.4       75.4       77.4  
Nuclear
    22.5       21.6       21.1  
Hydro
    2.0       2.7       1.2  
Oil and gas
    0.1       0.3       0.3  
Average cost of fuel per net KWH generated (cents) —
    1.55       1.46       1.42  
Average cost of purchased power per net KWH (cents) —
    5.17       4.03       3.29  
 

     Fuel expense increased 11.6 percent in 2004 primarily due to an increase in the average cost of fuel. 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.

     Purchased power expense increased $200 million (25.9 percent) in 2004 primarily due to a 38.5 percent increase in the average cost of fuel per net KWH and $65 million of additional capacity expense associated with new purchased power agreements (PPAs) between the Company and Southern Power that went into effect in June 2004 and June 2003. Purchased power expense increased $92 million (13.3 percent) in 2003 primarily due to $75 million of additional capacity expense associated with new PPAs between the Company and Southern Power that went into effect in 2003 and 2002. Purchased power expense decreased $87 million (11.2 percent) in 2002 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 PPAs between the Company and Southern Power.

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     A significant upward trend in the cost of coal and natural gas has emerged since 2003, and volatility in these markets is expected to continue. Increased coal prices have been influenced by a worldwide increase in demand as a result of rapid economic growth in China as well as by increases in mining costs. Higher natural gas prices in the United States are the result of slightly lower gas supplies despite increased drilling activity. Natural gas supply interruptions, such as those caused by the 2004 hurricanes, result in an immediate market response; however, the impact of this price volatility may be reduced by imports of natural gas and liquefied natural gas. Fuel expenses generally do not affect net income, since they are offset by fuel revenues under the Company’s fuel cost recovery provisions.

     In 2004, other operation and maintenance expenses increased $153 million (12.3 percent) due to the timing of generating plant maintenance of $39 million and transmission and distribution maintenance of $39 million. Increased employee benefit expense of $30 million related to pension and medical benefits and higher workers compensation expense of $8 million also contributed to the increase. 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.

     Depreciation and amortization decreased $74 million and $54 million in 2004 and 2003, respectively, primarily as a result of the amortization of a regulatory liability related to the inclusion of new certified PPAs in retail rates on a levelized basis as ordered by the Georgia PSC. 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 as part of the 2001 Retail Rate Plan. See Note 3 to the financial statements under “Retail Rate Orders” for additional information.

     Taxes other than income taxes increased $15 million (7.0 percent) in 2004 due to higher municipal gross receipts taxes associated with increased operating revenues. 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.

     Allowance for equity funds used during construction increased $15.9 million in 2004 primarily due to the Company’s acquisition of the Plant McIntosh combined cycle Units 10 and 11 construction project from Southern Power. See FUTURE EARNINGS POTENTIAL – “FERC and Georgia PSC Matters” and Note 3 to the financial statements under “Retail Rate Orders” and “Plant McIntosh Construction Project” for additional information.

     Interest income decreased $9 million in 2004 and increased $12 million in 2003 when compared to the prior year primarily due to interest on a favorable income tax settlement of $14.5 million in 2003. Interest income remained relatively constant in 2002.

     Interest expense remained relatively constant in 2004. Interest expense increased in 2003 primarily due to an increase in senior notes outstanding that was partially offset by a reduction in short-term debt outstanding. Interest expense decreased in 2002 primarily due to lower interest rates that offset new financing costs. The Company refinanced or retired $400 million, $665 million, and $929 million of securities in 2004, 2003, and 2002, respectively. Interest capitalized increased in 2004 due to the Plant McIntosh construction project referenced above and decreased in 2003 and 2002 due to the transfer of three generation projects to Southern Power in 2002 and 2001. See Note 3 to the financial statements under “Retail Rate Orders” and “Plant McIntosh Construction Project” for additional information regarding the Plant McIntosh construction project.

     Other income and (expense), net decreased in 2004 primarily due to the $13 million disallowance of Plant McIntosh construction costs pursuant to a Georgia PSC order issued on December 21, 2004 (2004 Retail Rate Plan), partially offset by a $7.5 million decrease in donations and $3.4 million in increased income from a customer pricing program. See Note 3 to the financial

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statements under “Retail Rate Orders” and “Plant McIntosh Construction Project” for additional information on the disallowance.

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, preferred stock, 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 Company operates as a vertically integrated company providing electricity to retail customers within its traditional service territory located within the State of Georgia and to wholesale customers in the southeastern United States. Prices for electricity provided by the Company to retail customers are set by the Georgia PSC 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 FERC. Retail rates and revenues are reviewed and adjusted periodically within certain limitations based on earned ROE. See ACCOUNTING POLICIES – “Application of Critical Accounting Policies and Estimates – Electric Utility Regulation” herein and Note 3 to the financial statements under “Retail Rate Orders” and “Market-Based Rate Authority” for additional information about this and other regulatory matters.

     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 that affect the opportunities, challenges, and risks of the Company’s business of selling electricity. These factors include the ability to maintain a stable regulatory environment, to recover costs related to growing demand, to achieve energy sales growth while containing costs, and to meet increasingly stringent 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.

     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, Inc. (SCS).

Environmental Matters

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, alleging that the Company had violated the New Source Review (NSR) provisions of the Clean Air Act and related state laws with respect to coal-fired generating facilities at plants Bowen and Scherer. The civil action requests penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The action against the Company was effectively stayed in the spring of 2001 pending the appeal of a similar NSR action against the Tennessee Valley Authority (TVA) before the U.S. Court of Appeals for the Eleventh Circuit. In June 2003, the Court of Appeals issued its ruling in the TVA case, dismissing the appeal for reasons unrelated to the issues in the case pending against the Company. At this time, no party to the case against the Company has sought to reopen the case, which remains administratively closed in the U.S.

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District Court for the Northern District of Georgia. See Note 3 to the financial statements under “New Source Review Actions” for additional information.

     The Company believes that it complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $32,500 per day, per violation at each generating unit, depending on the date of the alleged violation. 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 possibly financial condition if such costs are not recovered through regulated rates.

     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 (RMRR) exclusion. A coalition of states and environmental organizations has filed petitions for review of these revisions with the U.S. Court of Appeals for the District of Columbia Circuit. The October 2003 RMRR rules have been stayed by the Court of Appeals pending its review of the rules. In any event, the final regulations must also be adopted by the State of Georgia in order to apply to the Company’s facilities. The effect of these final regulations, related legal challenges, and potential rulemakings by the State of Georgia cannot be determined at this time.

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 for the Northern District of 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. The liability phase of the case has concluded with the Court ruling in favor of the Company in part and the plaintiffs in part. The Company has filed a petition for review of the decision with the U.S. Court of Appeals for the Eleventh Circuit. The district court case has been administratively closed pending that appeal. If necessary, the district court will hold a separate remedy trial which will address civil penalties and possible injunctive relief requested by the plaintiffs. See Note 3 to the financial statements under “Plant Wansley Environmental Litigation” for additional information. The ultimate outcome of this matter cannot currently be determined; however, an adverse outcome could result in 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.

Carbon Dioxide Litigation

On July 21, 2004, attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel of New York filed a complaint in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. A nearly identical complaint was filed by three environmental groups in the same court. The complaints allege that the companies’ emissions of carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs assert is a public nuisance. Under common law public and private nuisance theories, the plaintiffs seek a judicial order (1) holding each defendant jointly and severally liable for creating, contributing to, and/or maintaining, global warming and (2) requiring each of the defendants to cap its emissions of carbon dioxide and then reduce those emissions by a specified percentage each year for at least a decade. Plaintiffs have not, however, requested that damages be awarded in connection with their claims. Southern Company believes these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. Southern Company and the other defendants have filed motions to dismiss both lawsuits. Southern Company intends to vigorously defend against these claims. While the outcome of these matters cannot be determined at this time, an adverse judgment could result in substantial capital expenditures.

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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 involves 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 FINANCIAL CONDITION AND LIQUIDITY – “Capital Requirements and Contractual Obligations” herein. There is no assurance, however, that all such costs will, in fact, be recovered.

     Compliance with the 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 and resulted in total construction expenditures of approximately $206 million through 2000. Some of these previous 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 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 totaled $687.2 million through 2004, with an additional $6 million committed through 2007.

     To help 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 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 could be applied in Georgia. In April 2004, the EPA published final regional nitrogen oxide reduction rules applicable to Georgia, specifying a May 1, 2007 compliance date. However, in October 2004, the EPA announced that it would stay implementation of the rule as it relates to Georgia, while it initiates rulemakings to address issues raised in a petition for reconsideration filed by a coalition of Georgia industries. The impact of the nitrogen oxide reduction rules will depend on the outcome of the petition for reconsideration and/or any subsequent development and approval of Georgia’s state implementation plan and cannot be determined at this time.

     In September 2003, the EPA reclassified the Atlanta area from a “serious” to a “severe” nonattainment area for the one-hour ozone standard effective January 1, 2004. However, based on the last three years of data, the State of Georgia believes that the Atlanta area has attained the one-hour standard and is in the process of applying for redesignation from the EPA.

     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 and included development of an eight-hour ozone standard, as opposed to the previous one-hour ozone standard. 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. On April 30, 2004, the EPA published its eight-hour ozone nonattainment designations and a portion of the rules implementing the new eight-hour standard. Areas within the Company’s service territory that have been designated as nonattainment under the eight-hour ozone standard include Macon, Georgia and a 20-county area within metropolitan Atlanta. Under the implementation provisions of the new rule, the EPA announced that the one-hour ozone standard will be revoked on June 15, 2005, and that areas classified as “severe” nonattainment areas under the one-hour standard, such as Atlanta, will not be required to impose emissions fees if those areas fail to come into attainment with the one-hour standard. With respect to the eight-hour nonattainment areas, state implementation plans, including new emission control regulations necessary to bring those areas into attainment, could be required as early as 2007. These state implementation plans could require reductions in nitrogen oxide emissions from power plants. The impact of the eight-hour designations and the new standard will depend on the development and implementation of applicable state implementation plans and therefore cannot be determined at this time.

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     On December 17, 2004, the EPA issued its final “nonattainment” designations for the fine particulate national ambient air quality standard. Several areas within the Company’s service territory in Georgia were included in the EPA’s final particulate matter designations. The EPA plans to propose a fine particulate matter implementation rule in 2005 and finalize the implementation rule in 2006. State implementation plans addressing the nonattainment designations may be required by 2008 and could require reductions in sulfur dioxide emissions and further reductions in nitrogen oxide emissions from power plants. The impact of the fine particulate designations will depend on the development and implementation of applicable state implementation plans and therefore cannot be determined at this time.

     In January 2004, the EPA issued a proposed Clean Air Interstate Rule (CAIR) 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 in 2005. If finalized, the rule could modify or supplant other state requirements for attainment of the fine particulate matter standard, the eight-hour ozone standard, and other air quality regulations. 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.

     The Company has developed and maintains an environmental compliance strategy for the installation of additional control technologies and the purchase of emission allowances to assure continued compliance with current sulfur dioxide and nitrogen oxide emission regulations. Additional expenses associated with these regulations are anticipated to be incurred each year to maintain current and future compliance. Because the Company’s compliance strategy is impacted by factors such as changes to existing environmental laws and regulations, increases in the cost of emissions allowances, and any changes in the Company’s fuel mix, future environmental compliance costs 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 and to implement emission reduction requirements that make progress toward remedying current visibility impairment in certain natural areas. 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 implementation plans in 2008 that contain emission reduction strategies for implementing BART and for achieving sufficient progress toward the Clean Air Act’s visibility improvement goal. In response to litigation, the EPA proposed revised rules in May 2004, which it plans to finalize in April 2005. The impact of these regulations will depend on the promulgation of final rules and implementation of those rules by the states and, therefore, it is not possible to determine the effect of these rules on the Company at this time.

     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 March 2005, and compliance could be required as early as 2008. Because the regulations have not been finalized, the impact on the Company cannot be determined at this time.

     Major bills to amend the Clean Air Act to impose more stringent emissions limitations on power plants, including the Bush Administration’s Clear Skies Act, have been proposed in 2005. The Clear Skies Act is expected to further limit power plant emissions of sulfur dioxide, nitrogen oxides, and mercury and to supplement the proposed CAIR and mercury regulatory programs. Other proposals have also been introduced 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.

     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. In July 2004, the EPA published final rules that 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 and the actual limits established by the regulatory agencies.

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     The Company is installing cooling towers at additional facilities under the Clean Water Act to cool water prior to discharge. Near Atlanta, a cooling tower for one plant was completed in 2004 with two others scheduled for completion in 2008. The total estimated cost of these projects is $248 million, with $170 million remaining to be spent. Also, the Company is conducting a study of the aquatic environment at another facility to determine if further thermal controls are necessary at that plant.

     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 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.

Global Climate Issues

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 constraints on the emissions of greenhouse gases for a group of industrialized countries. The Bush Administration has not supported U.S. ratification of the Kyoto Protocol or other mandatory carbon dioxide reduction legislation and, in 2002, announced a goal to reduce the greenhouse gas intensity of the U.S. – the ratio of greenhouse gas emissions to the value of U.S. economic output — by 18 percent by 2012. A year later, the Department of Energy (DOE) announced the Climate VISION program to support this goal. Energy-intensive industries, including electricity generation, are the initial focus of this program. Southern Company is leading the development of a voluntary electric utility sector climate change initiative in partnership with the government. The utility sector has pledged to reduce its greenhouse gas emissions rate by 3 to 5 percent over the next decade and, on December 13, 2004, signed a memorandum of understanding with the DOE initiating this program under Climate VISION. Because efforts under this voluntary program are just beginning, the impact of this program on the Company cannot be determined at this time.

Environmental Remediation Reserves

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 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. See Note 3 to the financial statements under “Environmental Remediation” for additional information.

     Under Georgia PSC ratemaking provisions, $22 million has been deferred in a regulatory liability account for use in meeting future environmental remediation costs of the Company. Under the 2004 Retail Rate Plan, this regulatory liability will be amortized as a credit to expense over a three-year period beginning January 1, 2005. However, the Georgia PSC also approved an annual environmental accrual of $5.4 million. Environmental remediation expenditures will be charged against the reserve as they are incurred. The annual accrual amount will be reviewed and adjusted in future regulatory proceedings.

FERC and Georgia PSC Matters

Transmission

In December 1999, the FERC issued its final rule on Regional Transmission Organizations (RTOs). Since that time, there have been a number of additional proceedings at the FERC designed to encourage further voluntary formation of RTOs or to mandate their formation. However, at the current time, there are no active proceedings that would require the Company to participate in an RTO. Current FERC efforts that may potentially change the regulatory and/or operational structure of transmission include rules related to the standardization of generation interconnection, as well as

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an inquiry into, among other things, market power by vertically integrated utilities. See “Generation Interconnection Agreements” and “Market-Based Rate Authority” herein for additional information. The final outcome of these proceedings cannot now be determined. However, the Company’s financial condition, results of operations, and cash flows could be adversely affected by future changes in the federal regulatory or operational structure of transmission.

Generation Interconnection Agreements

In July 2003, the FERC issued its final rule on the standardization of generation interconnection agreements and procedures (Order 2003). Order 2003 shifts much of the financial burden of new transmission investment from the generator to the transmission provider. The FERC has indicated that Order 2003, which was effective January 20, 2004, is to be applied prospectively to interconnection agreements. Subsidiaries of Tenaska, Inc., as counterparties to previously executed interconnection agreements with the Company and another Southern Company subsidiary, have filed complaints at the FERC requesting that the FERC modify the agreements and that the Company refund a total of $7.9 million previously paid for interconnection facilities, with interest. The Company has opposed such relief and the proceedings are still pending. The impact of Order 2003 and its subsequent rehearings on the Company and the final results of these matters cannot be determined at this time.

Market-Based Rate Authority

The Company has authorization from the FERC to sell power to nonaffiliates at market-based prices. 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, the retail operating companies, and Southern Power, and found Southern Company and others to be “pivotal suppliers” in their retail service territories 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. In April 2004, the FERC issued an order that abandoned the SMA test and adopted a new interim analysis for measuring generation market power. This new interim approach requires utilities to submit a pivotal supplier screen and a wholesale market share screen. If the applicant does not pass both screens, there will be a rebuttable presumption regarding generation market power. The FERC’s order also sets forth procedures for rebutting these presumptions and addresses mitigation measures for those entities that are found to have market power. In the absence of specific mitigation measures, the order includes several cost-based mitigation measures that would apply by default. The FERC also initiated a new rulemaking proceeding that, among other things, will adopt a final methodology for assessing generation market power.

     In July 2004, the FERC denied Southern Company’s request for rehearing, along with a number of others, and reaffirmed the interim tests that it adopted in April 2004. In August 2004, Southern Company submitted a filing to the FERC which included results showing that Southern Company passed the pivotal supplier screen for all markets and the wholesale market share screen for all markets except the Southern Company retail service territory. Southern Company also submitted other analyses to demonstrate that it lacks generation market power. On December 17, 2004, the FERC initiated a proceeding to assess Southern Company’s generation dominance within its retail service territory. The ability to charge market-based rates in other markets is not at issue. As directed by this order, on February 15, 2005, Southern Company submitted additional information related to generation dominance in its retail service territory. Any new market-based rate transactions in the Southern Company retail service territory entered into after February 27, 2005 will be subject to refund to the level of the default cost-based rates, pending the outcome of the proceeding. Southern Company, along with other utilities, has also filed an appeal of the FERC’s April and July 2004 orders with the U.S. Court of Appeals for the District of Columbia Circuit. The FERC has asked the court to dismiss the appeal on the grounds that it is premature.

     In the event that the FERC’s default mitigation measures are ultimately applied, the Company may be required to charge cost-based rates for certain wholesale sales in the Southern Company retail service territory, which may be lower than negotiated

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market-based rates. The final outcome of this matter will depend on the form in which the final methodology for assessing generation market power and mitigation rules may be ultimately adopted and cannot be determined at this time.

Retail Rate Case

On December 21, 2004, the Georgia PSC approved the 2004 Retail Rate Plan for the three-year period ending December 31, 2007. Under the terms of the 2004 Retail Rate Plan, earnings will be evaluated annually against a retail ROE range of 10.25 percent to 12.25 percent. Two-thirds of any earnings above 12.25 percent will be applied to rate refunds, with the remaining one-third retained by the Company. Retail rates will be increased by approximately $194 million and customer fees will be increased by approximately $9 million effective January 1, 2005 to cover the higher costs of purchased power; operating and maintenance expenses; environmental compliance; and continued investment in new generation, transmission and distribution facilities to support growth and ensure reliability.

     The Company will not file for a general base rate increase unless its projected retail ROE falls below 10.25 percent. The Company is required to file a general rate case by July 1, 2007, in response to which the Georgia PSC would be expected to determine whether the 2004 Retail Rate Plan should be continued, modified or discontinued. See Note 3 to the financial statements under “Retail Rate Orders” for additional information.

Plant McIntosh Construction Project

In December 2002 after a competitive bidding process, the Georgia PSC certified PPAs between Southern Power and the Company and Savannah Electric and Power Company (Savannah Electric) for capacity from Plant McIntosh Units 10 and 11, construction of which is scheduled to be completed in June 2005. In April 2003, Southern Power applied for FERC approval of these PPAs. In July 2003, the FERC accepted the PPAs to become effective June 1, 2005, subject to refund, and ordered that hearings be held. Intervenors opposed the FERC’s acceptance of the PPAs, alleging that they did not meet the applicable standards for market-based rates between affiliates. To ensure the timely completion of the Plant McIntosh construction project and the availability of the units in the summer of 2005 for their retail customers, in May 2004, the Company and Savannah Electric requested the Georgia PSC to direct them to acquire the McIntosh construction project. The Georgia PSC issued such an order and the transfer occurred on May 24, 2004 at a total cost of approximately $415 million, including $14 million of transmission interconnection facilities. Subsequently, Southern Power filed a request to withdraw the PPAs and to terminate the ongoing FERC proceedings. In August 2004, the FERC issued a notice accepting the request to withdraw the PPAs and permitting such request to become effective by operation of law. However, the FERC made no determination on what additional steps may need to be taken with respect to testimony provided in the proceedings. The ultimate outcome of any additional FERC action cannot now be determined at this time.

     As directed by the Georgia PSC order, in June 2004, the Company and Savannah Electric filed an application to amend the resource certificate granted by the Georgia PSC in 2002 to change the character of the resource from a PPA to a self-owned, rate based asset and to describe the approximate construction schedule and the proposed rate base treatment. In connection with the 2004 Retail Rate Plan, the Georgia PSC approved the transfer of the Plant McIntosh construction project at a total fair market value of approximately $385 million. This value reflects an approximate $16 million disallowance, of which $13 million is attributable to the Company, and reduced the Company’s net income by approximately $8 million. The Georgia PSC also certified a total completion cost of $547 million for the project. The amount of the disallowance will be adjusted accordingly based on the actual completion cost of the project. Under the 2004 Retail Rate Plan, the Plant McIntosh revenue requirements impact will be reflected in the Company’s rates evenly over the three years ending 2007. See Note 3 to the financial statements under “Retail Rate Orders” and “Plant McIntosh Construction Project” for additional information.

Retail Fuel Cost Recovery

The Company has established fuel cost recovery rates approved by the Georgia PSC. In recent months, the Company has experienced higher than expected fuel costs for coal and gas. Those higher fuel costs have increased the under recovered fuel costs included in the balance sheets herein. On February 18, 2005, the Company filed a request with the Georgia PSC for a fuel cost recovery rate increase. In the ordinary course, these

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new rates will be effective June 1, 2005 following a hearing before and approval by the Georgia PSC. In its filing, the Company asked that the Georgia PSC accept the new rate, effective April 1, 2005, prior to a formal hearing on the Company’s request. This action, if taken by the Georgia PSC, would serve to mitigate expected increases in the under recovered balance during April and May, but will not preclude the Georgia PSC from subsequently adjusting the rates. The requested increase, representing an annual increase in revenues of approximately 11.7 percent, will allow for the recovery of fuel costs based on an estimate of future fuel costs, as well as the collection of the existing under recovery of fuel costs. The Company’s under recovered fuel costs as of January 31, 2005 totaled $390 million. The Georgia PSC will examine the Company’s fuel expenditures and determine whether the proposed fuel cost recovery rate is just and reasonable before issuing its decision in May 2005. The final outcome of the filing cannot be determined at this time. See Note 3 to the financial statements under “Fuel Cost Recovery” for further information regarding this filing.

Storm Damage Cost Recovery

During the month of September 2004, the Company’s service territory was impacted by Hurricanes Frances, Ivan and Jeanne. The Company maintains a reserve for property damage to cover the cost of damages from major storms to its transmission and distribution lines and the cost of uninsured damages to its generation facilities and other property as mandated by the Georgia PSC. The total amount of damage related to these hurricanes was estimated to be approximately $15 million and was charged to the storm damage reserve in 2004. These costs are expected to be recovered through regular monthly accruals which total $6.3 million annually under the 2004 Retail Rate Plan. See Note 3 to the financial statements under “Retail Rate Orders” for additional information.

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 $35 million, $54 million, and $59 million in 2004, 2003, and 2002, respectively. Future pension income is dependent on several factors including trust earnings and changes to the pension 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 $44 million, $41 million and $43 million in 2004, 2003, and 2002, respectively, and are expected to trend upward. A portion of pension income and postretirement benefit costs is capitalized based on construction-related labor charges. For the Company, 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.

     On October 22, 2004, President Bush signed the American Jobs Creation Act of 2004 (Jobs Act) into law. The Jobs Act includes a provision that allows a generation tax deduction for utilities. The Company is currently assessing the impact of the Jobs Act, including this deduction, as well as the related regulatory treatment, on its taxable income. However, the Company currently does not expect the Jobs Act to have a material impact on its financial statements.

     The Company is involved in various other 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. Southern Company 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.

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Electric Utility Regulation

The Company is subject to retail regulation by the Georgia 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, which requires the financial statements to reflect the effects of rate 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, 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 legislative, 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 herein 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:

•   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.
 
•   Changes in existing income tax regulations or changes in Internal Revenue Service interpretations of existing regulations.
 
•   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.
 
•   Identification and evaluation of other potential lawsuits or complaints in which the Company may be named as a defendant.
 
•   Resolution or progression of existing matters through the legislative process, the court systems, or the EPA.

Unbilled Revenues

Revenues related to the sale of electricity are recorded when electricity is delivered to customers. However, the determination of KWH sales to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month. At the end of each month, amounts of electricity delivered to customers, but not yet metered and billed, are estimated. Components of the unbilled revenue estimates include total KWH territorial supply, total KWH billed, estimated total electricity lost in delivery, and customer usage. These components can fluctuate as a result of a number of factors including weather, generation patterns, power delivery volume and other power delivery operational constraints. These factors can be unpredictable and can vary from historical trends. As a result, the overall estimate of unbilled revenues could be significantly affected, which could have a material impact on the Company’s results of operations.

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New Accounting Standards

On March 31, 2004, the Company prospectively adopted FASB Interpretation No. 46R, “Consolidation of Variable Interest Entities,” which requires the primary beneficiary of a variable interest entity to consolidate the related assets and liabilities. The adoption of FASB Interpretation No. 46R had no impact on the Company’s net income. However, as a result of the adoption, the Company deconsolidated certain wholly-owned trusts established to issue preferred securities since the Company did not meet the definition of primary beneficiary established by FASB Interpretation No. 46R. See Note 1 to the financial statements under “Variable Interest Entities” for additional information.

     In the third quarter 2004, the Company prospectively adopted FASB Staff Position (FSP) 106-2, Accounting and Disclosure Requirements related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (Medicare Act). The Medicare Act provides a 28 percent prescription drug subsidy for Medicare eligible retirees. FSP 106-2 requires recognition of the impacts of the Medicare Act in the accumulated postretirement benefit obligation (APBO) and future cost of service for postretirement medical plans. The effect of the subsidy reduced the Company’s expenses for the six months ended December 31, 2004 by approximately $5 million and is expected to have a similar impact on future expenses. The subsidy’s impact on the postretirement medical plan APBO was a reduction of approximately $72 million. However, the ultimate impact on future periods is subject to final interpretation of the federal regulations which were published on January 21, 2005. See Note 2 to the financial statements under “Postretirement Benefits” for additional information.

     FASB Statement No. 123R, Share-Based Payments, was issued in December 2004. This statement requires that compensation cost relating to share-based payment transactions be recognized in financial statements. That cost will be measured based on the grant date fair value of the equity or liability instruments issued. For the Company, this statement is effective beginning July 1, 2005. Although the compensation expense calculation required under the revised statement differs slightly, the impacts on the financial statements are expected to be similar to the pro forma disclosures included in Note 1 to the financial statements under “Stock Options.”

     See FUTURE EARNINGS POTENTIAL – “Other Matters” herein for information regarding the adoption of new tax legislation. In December 2004, the FASB issued FSP 109-1, Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax Deduction on Qualified Production Activities provided by the American Jobs Creation Act of 2004, which requires that the generation deduction be accounted for as a special tax deduction rather than as a tax rate reduction. The Company is currently assessing the Jobs Act and this pronouncement, as well as the related regulatory treatment, but currently does not expect a material impact on the Company’s financial statements.

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 costs of capital, achieved through the refinancing and/or redemption of higher-cost securities. Cash flow from operations decreased $219 million resulting primarily from the increase in under recovered deferred fuel costs.

     In 2004, gross utility plant additions were $1.1 billion. These additions were primarily related to the construction of Plant McIntosh Units 10 and 11, 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 and capital contributions from Southern Company. The statements of cash flows provide additional details.

     The Company’s ratio of common equity to total capitalization — including short-term debt — was 47.7 percent in 2004 and 48.3 percent in 2003 and 2002. 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 capital contributions from

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Southern Company and by the issuance of new debt securities, term loans, and short-term borrowings. 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 securities to meet its long-term external financing requirements.

     The issuance of securities by the Company is subject to regulatory approval by the Securities and Exchange Commission (SEC) under the Public Utility Holding Company Act of 1935, as amended (PUHCA), and by the Georgia PSC. Additionally, with respect to the public offering of securities, the Company must file registration statements with the SEC under the Securities Act of 1933, as amended (1933 Act). The amounts of securities authorized by the appropriate regulatory authorities, as well as the amounts registered under the 1933 Act, are continuously monitored and appropriate filings are made to ensure flexibility in the capital markets.

     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 PUHCA, most loans between affiliated companies must be approved in advance by the 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 $773.1 million of unused credit arrangements with banks at the beginning of 2005. 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. As of December 31, 2004, the Company had outstanding $208 million of commercial paper and no extendible commercial notes.

     At the beginning of 2005, the Company had not used any of its available credit arrangements. Bank credit arrangements are as follows:

                                 
          Expires  
Total   Unused   2005 2006       2007  
          (in millions)  
$773.1
  $ 773.1     $ 423.1           $ 350  
 

     The credit arrangements that expire in 2005 allow for the execution of term loans for an additional two-year period.

Financing Activities

During 2004, the Company issued $806 million of long-term debt including long-term debt payable to affiliated trusts. The issuances were used to refund $400 million of long-term debt, as well as to finance the Company’s purchase of the Plant McIntosh construction project from Southern Power. The remainder was used to reduce short-term debt and fund the Company’s ongoing construction program.

     Subsequent to December 31, 2004, the Company has issued $250 million of securities with the proceeds used to fund the February 2005 maturity of floating rate senior notes.

Credit Rating Risk

The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- or Baa3 or below. Generally, collateral may be provided for by a Southern Company guaranty, letter of credit or cash. These contracts are primarily for physical electricity purchases and sales. At December 31, 2004, the maximum potential collateral requirements at a BBB- or Baa3 rating were approximately $8 million. The

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maximum potential collateral requirements at a rating below BBB- or Baa3 were approximately $247 million. The Company is also party to certain derivative agreements that could require collateral and/or accelerated payment in the event of a credit rating change to below investment grade. These agreements are primarily for natural gas price and interest rate risk management activities. At December 31, 2004, the Company had no material exposure related to these 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 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 January 1, 2005 was 2.04 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 $8 million at January 1, 2005. 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.

     The Company has implemented a fuel hedging program at the instruction of the Georgia PSC. Fair value of changes in energy-related derivative contracts and year-end valuations were as follows at December 31:

                 
    Changes in Fair Value  
    2004     2003  
    (in millions)  
Contracts beginning of year
  $ 3.2     $ 0.1  
Contracts realized or settled
    (12.2 )     (0.4 )
New contracts at inception
           
Changes in valuation techniques
           
Current period changes (a)
    14.8       3.5  
 
Contracts end of year
  $ 5.8     $ 3.2  
 

(a)   Current period changes also include the changes in fair value of new contracts entered into during the period.
                         
    Source of 2004 Year-End Valuation Prices  
    Total     Maturity  
    Fair Value     Year 1     1-3 Years  
            (in millions)          
Actively quoted
  $ 4.8     $ 3.8     $ 1.0  
External sources
    1.0       1.0        
Models and other methods methods
                 
         
Contracts end of year
  $ 5.8     $ 4.8     $ 1.0  
         

     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. See Note 3 to the financial statements for information regarding the retail fuel hedging program. Gains and losses on derivative contracts that are not designated as hedges are recognized in the statements of income as incurred. At December 31, 2004, the fair value of derivative energy contracts was reflected in the financial statements as follows:

                 
    Amounts          
    (in millions)          
Regulatory liabilities, net
  $ 5.7          
Other comprehensive income
             
Net income
    0.1          
 
Total fair value
  $ 5.8          
 

     Unrealized gains (losses) recognized in income in 2004, 2003, and 2002 were not material. The Company

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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 $911 million for 2005, $1.1 billion for 2006, and $1.2 billion for 2007. Environmental expenditures included in these amounts are $127 million, $284 million, and $506 million for 2005, 2006, and 2007, 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 currently has under construction Plant McIntosh Units 10 and 11 scheduled for completion in June 2005. In addition, 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 Nuclear Regulatory Commission, 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 “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 Georgia PSC and the FERC.

     Other funding requirements related to obligations associated with scheduled maturities of long-term debt and preferred securities and the related interest, preferred stock dividends, leases, and other purchase commitments are as follows. See Notes 1, 6, and 7 to the financial statements for additional information.

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Contractual Obligations

                                         
            2006-     2008-     After        
    2005     2007     2009     2009     Total  
                    (in millions)                  
Long-term debt (a)
                                       
Principal
  $ 452     $ 456     $ 282     $ 3,942     $ 5,132  
Interest
    232       426       387       4,283       5,328  
Preferred stock dividends(b)
    1       1       1             3  
Operating leases
    32       52       42       63       189  
Purchase commitments(c)
                                       
Capital (d)
    911       2,277       2,571             5,759  
Coal and nuclear fuel
    1,731       2,722       771       96       5,320  
Natural gas(e)
    248       388       389       1,669       2,694  
Purchased power
    339       692       673       1,222       2,926  
Long-term service agreements
    6       19       22       150       197  
Trusts(f)
                                       
Nuclear decommissioning
    9       14       14       124       161  
Postretirement benefits
    8       24                   32  
DOE assessments
    3       4                   7  
 
Total
  $ 3,972     $ 7,075     $ 5,152     $ 11,549     $ 27,748  
 

(a)   All amounts are reflected based on final maturity dates. The Company plans to 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, 2005, 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 $1.4 billion, $1.2 billion, and $1.3 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, 2004, 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 Exchange future prices at December 31, 2004.

(f)   Projections of nuclear decommissioning trust contributions are based on the 2004 Retail Rate Plan. 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, including estimated benefit payments. Certain benefit payments will be made through the related trusts. Other benefit payments will be made from the Company’s corporate assets.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2004 Annual Report

Cautionary Statement Regarding Forward-Looking Statements

The Company’s 2004 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning retail sales growth, environmental regulations and expenditures, the Company’s projections for postretirement benefit trust contributions, completion of construction projects, and estimated construction and other expenditures. 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 similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:

•   the impact of recent and future federal and state regulatory change, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, and also changes in environmental, tax and other laws and regulations to which the Company is subject, as well as changes in application of existing laws and regulations;

•   current and future litigation, regulatory investigations, proceedings, or inquiries, including the pending EPA civil action against the Company;

•   the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates;

•   variations in demand for electricity, including those relating to weather, the general economy and population, and business growth (and declines);

•   available sources and costs of fuels;

•   ability to control costs;

•   investment performance of the Company’s employee benefit plans;

•   advances in technology;

•   state and federal rate regulations and the impact of pending and future rate cases and negotiations;

•   internal restructuring or other restructuring options that may be pursued;

•   potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to the Company;

•   the ability of counterparties of the Company to make payments as and when due;

•   the ability to obtain new short- and long-term contracts with neighboring utilities;

•   the direct or indirect effect on the Company’s business resulting from terrorist incidents and the threat of terrorist incidents;

•   interest rate fluctuations and financial market conditions and the results of financing efforts, including the Company’s credit ratings;

•   the ability of the Company to obtain additional generating capacity at competitive prices;

•   catastrophic events such as fires, earthquakes, explosions, floods, hurricanes, or other similar occurrences;

•   the direct or indirect effects on the Company’s business resulting from incidents similar to the August 2003 power outage in the Northeast;

•   the effect of accounting pronouncements issued periodically by standard-setting bodies; and

•   other factors discussed elsewhere herein and in other reports filed by the Company (including the Form 10-K) from time to time with the SEC.

The Company expressly disclaims any obligation to update any forward-looking statements.

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STATEMENTS OF INCOME
For the Years Ended December 31, 2004, 2003, and 2002
Georgia Power Company 2004 Annual Report

                         
    2004     2003     2002  
            (in thousands)          
Operating Revenues:
                       
Retail sales
  $ 4,776,985     $ 4,309,972     $ 4,288,097  
Sales for resale —
                       
Non-affiliates
    246,545       259,376       270,678  
Affiliates
    166,245       174,855       98,323  
Other revenues
    181,033       169,304       165,362  
 
Total operating revenues
    5,370,808       4,913,507       4,822,460  
 
Operating Expenses:
                       
Fuel
    1,232,496       1,103,963       1,002,703  
Purchased power —
                       
Non-affiliates
    304,978       258,621       264,814  
Affiliates
    671,098       516,944       419,839  
Other operations
    902,167       827,972       848,436  
Maintenance
    498,114       419,206       476,962  
Depreciation and amortization
    275,488       349,984       403,507  
Taxes other than income taxes
    227,806       212,827       201,857  
 
Total operating expenses
    4,112,147       3,689,517       3,618,118  
 
Operating Income
    1,258,661       1,223,990       1,204,342  
Other Income and (Expense):
                       
Allowance for equity funds used during construction
    26,659       10,752       7,622  
Interest income
    6,657       15,625       3,857  
Interest expense, net of amounts capitalized
    (182,370 )     (182,583 )     (168,391 )
Interest expense to affiliate trusts
    (44,565 )            
Distributions on mandatorily redeemable preferred securities
    (15,839 )     (59,675 )     (62,553 )
Other income (expense), net
    (11,362 )     (10,551 )     (9,259 )
 
Total other income and (expense)
    (220,820 )     (226,432 )     (228,724 )
 
Earnings Before Income Taxes
    1,037,841       997,558       975,618  
Income taxes
    379,170       366,311       357,319  
 
Net Income
    658,671       631,247       618,299  
Dividends on Preferred Stock
    670       670       670  
 
Net Income After Dividends on Preferred Stock
  $ 658,001     $ 630,577     $ 617,629  
 

The accompanying notes are an integral part of these financial statements.

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STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2004, 2003, and 2002
Georgia Power Company 2004 Annual Report

   
  2004 2003 2002
            (in thousands)          
Operating Activities:
                       
Net income
  $ 658,671     $ 631,247     $ 618,299  
Adjustments to reconcile net income to net cash provided from operating activities —
                       
Depreciation and amortization
    361,958       424,321       459,563  
Deferred income taxes and investment tax credits, net
    251,623       199,265       65,550  
Deferred expenses - affiliates
    (10,563 )     (7,399 )     (11,575 )
Allowance for equity funds used during construction
    (26,659 )     (10,752 )     (7,622 )
Pension, postretirement, and other employee benefits
    2,636       (16,162 )     (64,771 )
Tax benefit of stock options
    9,701       11,649       8,184  
Hedge settlements
    (12,394 )     (11,250 )     860  
Other, net
    (27,624 )     16,591       (82,190 )
Changes in certain current assets and liabilities —
                       
Receivables, net
    (225,454 )     (4,870 )     68,527  
Fossil fuel stock
    (46,730 )     (17,490 )     82,711  
Materials and supplies
    618       (7,677 )     15,874  
Other current assets
    (9,314 )     (2,352 )     (18,880 )
Accounts payable
    132,001       (62,553 )     64,902  
Accrued taxes
    (64,563 )     52,348       (6,540 )
Accrued compensation
    (6,664 )     (3,111 )     (29,749 )
Other current liabilities
    5,836       19,845       45,915  
 
Net cash provided from operating activities
    993,079       1,211,650       1,209,058  
 
Investing Activities:
                       
Gross property additions
    (786,314 )     (742,808 )     (883,968 )
Purchase of property from affiliates
    (339,750 )     (2 )      
Cost of removal net of salvage
    (21,756 )     (28,265 )     (60,912 )
Sale of property to affiliates
                387,212  
Change in construction payables, net of joint owner portion
    413       (32,223 )     (7,411 )
Other
    31,503       17,124       37,557  
 
Net cash used for investing activities
    (1,115,904 )     (786,174 )     (527,522 )
 
Financing Activities:
                       
Increase (decrease) in notes payable, net
    70,956       (220,400 )     (389,860 )
Proceeds —
                       
Senior notes
    600,000       1,000,000       500,000  
Mandatorily redeemable preferred securities
    200,000             740,000  
Capital contributions from parent company
    260,068       40,809       165,299  
Redemptions —
                       
First mortgage bonds
                (1,860 )
Pollution control bonds
                (7,800 )
Senior notes
    (200,000 )     (665,000 )     (330,000 )
Mandatorily redeemable preferred securities
    (200,000 )           (589,250 )
Capital distributions to parent company
                (200,000 )
Payment of preferred stock dividends
    (654 )     (696 )     (721 )
Payment of common stock dividends
    (565,500 )     (565,800 )     (542,900 )
Other
    (17,247 )     (22,563 )     (30,831 )
 
Net cash provided from (used for) financing activities
    147,623       (433,650 )     (687,923 )
 
Net Change in Cash and Cash Equivalents
    24,798       (8,174 )     (6,387 )
Cash and Cash Equivalents at Beginning of Period
    8,699       16,873       23,260  
 
Cash and Cash Equivalents at End of Period
  $ 33,497     $ 8,699     $ 16,873  
 
Supplemental Cash Flow Information:
                       
Cash paid during the period for —
                       
Interest (net of $8,920, $5,428, and $9,368 capitalized, respectively)
  $ 228,190     $ 215,463     $ 203,707  
Income taxes (net of refunds)
    127,115       145,048       326,698  
 

The accompanying notes are an integral part of these financial statements.

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BALANCE SHEETS
At December 31, 2004 and 2003
Georgia Power Company 2004 Annual Report

                 
 
Assets   2004 2003
    (in thousands)  
Current Assets:
               
Cash and cash equivalents
  $ 33,497     $ 8,699  
Receivables —
               
Customer accounts receivable
    317,937       261,771  
Unbilled revenues
    140,027       117,327  
Under recovered regulatory clause revenues
    345,542       151,447  
Other accounts and notes receivable
    94,377       101,783  
Affiliated companies
    17,042       52,413  
Accumulated provision for uncollectible accounts
    (7,100 )     (5,350 )
Fossil fuel stock, at average cost
    184,267       137,537  
Vacation pay
    57,372       50,150  
Materials and supplies, at average cost
    270,422       271,040  
Prepaid expenses
    32,696       114,882  
Other
    25,260       83  
 
Total current assets
    1,511,339       1,261,782  
 
Property, Plant, and Equipment:
               
In service
    18,681,533       18,171,862  
Less accumulated provision for depreciation
    7,217,607       6,898,725  
 
 
    11,463,926       11,273,137  
Nuclear fuel, at amortized cost
    124,745       129,056  
Construction work in progress
    766,140       341,783  
 
Total property, plant, and equipment
    12,354,811       11,743,976  
 
Other Property and Investments:
               
Equity investments in unconsolidated subsidiaries
    66,192       38,714  
Nuclear decommissioning trusts, at fair value
    459,194       423,319  
Other
    66,775       52,386  
 
Total other property and investments
    592,161       514,419  
 
Deferred Charges and Other Assets:
               
Deferred charges related to income taxes
    505,664       509,887  
Prepaid pension costs
    450,270       405,164  
Unamortized debt issuance expense
    77,925       75,245  
Unamortized loss on reacquired debt
    176,825       177,707  
Other regulatory assets
    72,639       84,901  
Other
    80,704       77,673  
 
Total deferred charges and other assets
    1,364,027       1,330,577  
 
Total Assets
  $ 15,822,338     $ 14,850,754  
 

The accompanying notes are an integral part of these financial statements.

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BALANCE SHEETS
   
At December 31, 2004 and 2003
   
Georgia Power Company 2004 Annual Report
   
 
   
 
                 
Liabilities and Stockholder’s Equity   2004     2003  
    (in thousands)  
Current Liabilities:
               
Securities due within one year
  $ 452,498     $ 2,304  
Notes payable
    208,233       137,277  
Accounts payable —
               
Affiliated
    194,253       134,884  
Other
    310,763       238,069  
Customer deposits
    115,661       103,756  
Accrued taxes —
               
Income taxes
    78,269       39,970  
Other
    129,520       166,892  
Accrued interest
    74,529       70,844  
Accrued vacation pay
    44,894       38,206  
Accrued compensation
    127,340       134,004  
Other
    75,699       105,234  
 
Total current liabilities
    1,811,659       1,171,440  
 
Long-term Debt (See accompanying statements)
    3,709,852       3,762,333  
 
Long-term Debt Payable to Affiliated Trusts (See accompanying statements)
    969,073        
 
Mandatorily Redeemable Preferred Securities (See accompanying statements)
          940,000  
 
Deferred Credits and Other Liabilities:
               
Accumulated deferred income taxes
    2,556,040       2,439,373  
Deferred credits related to income taxes
    170,973       186,625  
Accumulated deferred investment tax credits
    300,018       312,506  
Employee benefit obligations
    331,002       282,833  
Asset retirement obligations
    504,515       475,585  
Other cost of removal obligations
    411,692       412,161  
Miscellaneous regulatory liabilities
    92,611       249,687  
Other
    59,733       63,431  
 
Total deferred credits and other liabilities
    4,426,584       4,422,201  
 
Total Liabilities
    10,917,168       10,295,974  
 
Preferred Stock (See accompanying statements)
    14,609       14,569  
 
Common Stockholder’s Equity (See accompanying statements)
    4,890,561       4,540,211  
 
Total Liabilities and Stockholder’s Equity
  $ 15,822,338     $ 14,850,754  
 
Commitments and Contingent Matters (See notes)
   
 

The accompanying notes are an integral part of these financial statements.

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STATEMENTS OF CAPITALIZATION
At December 31, 2004 and 2003
Georgia Power Company 2004 Annual Report

                                 
 
    2004     2003     2004     2003  
    (in thousands)     (percent of total)
Long-Term Debt:
                               
Long-term notes payable —
                               
5.50% due December 1, 2005
  $ 150,000     $ 150,000                  
Variable rate (1.66% to 1.96% at 1/1/05) due 2005
    300,000       300,000                  
6.20% due February 1, 2006
    150,000       150,000                  
4.875% due July 15, 2007
    300,000       300,000                  
4.10% due August 15, 2009
    125,000                        
Variable rate (2.48% at 1/1/05) due 2009
    150,000                        
4.00% to 6.70% due 2010-2044
    1,225,000       1,100,000                  
 
Total long-term notes payable
    2,400,000       2,000,000                  
 
Other long-term debt —
                               
Pollution control revenue bonds — non-collateralized:
                               
1.08% to 5.45% due 2012-2034
    812,560       812,560                  
Variable rate (1.24% to 2.30% at 1/1/05) due 2011-2032
    873,330       873,330                  
 
Total other long-term debt
    1,685,890       1,685,890                  
 
Capitalized lease obligations
    76,982       79,286                  
 
Unamortized debt premium (discount), net
    (522 )     (539 )                
 
Total long-term debt (annual interest requirement — $172.7 million)
    4,162,350       3,764,637                  
Less amount due within one year
    452,498       2,304                  
 
Long-term debt excluding amount due within one year
    3,709,852       3,762,333       38.7 %     40.6 %
 
Long-term Debt Payable to Affiliated Trusts:
                               
4.875% through 2007 due 2042*
    309,279                        
5.875% to 7.125% due 2042 to 2044
    659,794                        
 
Total long-term debt payable to affiliated trusts (annual interest requirement — $59.5 million)
    969,073             10.1       0.0  
 
Mandatorily Redeemable Preferred Securities:
                               
$25 liquidation value —
                               
6.85% due 2029
          200,000                  
7.125% due 2042
          440,000                  
$1,000 liquidation value — 4.875% through 2007 due 2042*
          300,000                  
 
Total mandatorily redeemable preferred securities
          940,000       0.0       10.2  
 
Cumulative Preferred Stock:
                               
$100 stated value at 4.60% (annual dividend requirement — $0.7 million)
    14,609       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
    2,478,268       2,208,538                  
Retained earnings
    2,102,798       2,010,297                  
Accumulated other comprehensive income (loss)
    (34,755 )     (22,874 )                
 
Total common stockholder’s equity
    4,890,561       4,540,211       51.0       49.0  
 
Total Capitalization
  $ 9,584,095     $ 9,257,113       100.0 %     100.0 %
 


*The fixed rate thereafter is determined through remarketings for specific periods of varying length or at floating rates determined by reference to 3-month LIBOR plus 3.05%.
 
The accompanying notes are an integral part of these financial statements.

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STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
For the Years Ended December 31, 2004, 2003, and 2002
Georgia Power Company 2004 Annual Report

                                         
   
                            Other        
    Common     Paid-In     Retained     Comprehensive        
    Stock     Capital     Earnings     Income (loss)     Total  
    (in thousands)  
Balance at December 31, 2001
  $ 344,250     $ 2,182,597     $ 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       2,156,080       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       2,208,538       2,010,297       (22,874 )     4,540,211  
Net income after dividends on preferred stock
                658,001             658,001  
Capital contributions from parent company
          269,769                   269,769  
Other comprehensive income (loss)
                      (11,881 )     (11,881 )
Cash dividends on common stock
                (565,500 )           (565,500 )
Other
          (39 )                 (39 )
 
Balance at December 31, 2004
  $ 344,250     $ 2,478,268     $ 2,102,798     $ (34,755 )   $ 4,890,561  
 

The accompanying notes are an integral part of these financial statements.

STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2004, 2003, and 2002
Georgia Power Company 2004 Annual Report

                         
   
    2004     2003     2002  
    (in thousands)  
Net income after dividends on preferred stock
  $ 658,001     $ 630,577     $ 617,629  
 
Other comprehensive income (loss):
                       
Change in additional minimum pension liability, net of tax of $(3,861), $(5,133) and $(4,853), respectively
    (6,122 )     (8,138 )     (7,693 )
Change in fair value of marketable securities, net of tax of $(114)
    (181 )            
Changes in fair value of qualifying hedges, net of tax of $(5,046), $(3,241) and $(2,502), respectively
    (7,999 )     (5,550 )     (3,555 )
Less: Reclassification adjustment for amounts included in net income, net of tax of $1,528, $1,208 and $-, respectively
    2,421       2,217       (2 )
 
Total other comprehensive income (loss)
    (11,881 )     (11,471 )     (11,250 )
 
Comprehensive Income
  $ 646,120     $ 619,106     $ 606,379  
 

The accompanying notes are an integral part of these financial statements.

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NOTES TO FINANCIAL STATEMENTS
Georgia Power Company 2004 Annual Report

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General

Georgia Power Company (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 (SouthernLINC Wireless), 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. 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 the subsidiary companies. SouthernLINC Wireless 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 various other energy-related businesses. 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, as amended (PUHCA). Both Southern Company and its subsidiaries are subject to the regulatory provisions of the PUHCA. In addition, the Company is subject to regulation by the FERC and the Georgia Public Service Commission (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 operations. Costs for these services amounted to $292 million in 2004, $303 million in 2003, and $318 million in 2002. 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 $311 million in 2004, $289 million in 2003, and $301 million in 2002.

     The Company has an agreement with Southern Power under which the Company operates and maintains Southern Power owned plants Dahlberg, Franklin, Wansley, and Stanton at cost. Reimbursements under these agreements with Southern Power amounted to $4.9 million in 2004, $5.3 million in 2003, and $5.3 million in 2002.

     The Company has an agreement with SouthernLINC Wireless under which the Company receives digital wireless communications services and purchases digital equipment. Costs for these services amounted to $7.7

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NOTES (continued)
Georgia Power Company 2004 Annual Report

million in 2004, $7.4 million in 2003 and $5.9 million in 2002.

     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 $53 million in 2004 and $38 million in 2003. In addition, the Company purchases synthetic fuel from AFP for use at plants Branch, McDonough, and Bowen. Fuel purchases totaled $163 million in 2004 and $91 million in 2003.

     The Company has entered into several purchased power agreements (PPAs) with Southern Power for capacity and energy. Purchased power costs were $282 million, $203 million and $128 million in 2004, 2003 and 2002, respectively. Additionally, the Company recorded $11 million and $7 million of prepaid capacity expenses included on the balance sheets at December 31, 2004 and 2003, respectively. See Note 7 under “Purchased Power Commitments” for additional information.

     The Company has an agreement with Gulf Power under which Gulf Power jointly owns a portion of Plant Scherer. Under this agreement, the Company operates Plant Scherer and Gulf Power reimburses the Company for its proportionate share of the related expenses which were $6.8 million in 2004, $4.9 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 $3.3 million in 2004, $3.7 million in 2003, and $2.2 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 (SEGCO) and Note 5 for information on certain deferred tax liabilities due to affiliates.

     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” for additional information.

Revenues

Energy and other revenues are recognized as services are provided. Unbilled revenues are accrued at the end of each fiscal period. 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 costs and amounts billed 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 despite an increase in customer bankruptcies.

Fuel Costs

Fuel costs are expensed as the fuel is used. Fuel expense includes the cost of purchased emission allowances as they are used. Fuel expense also 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 $73 million in 2004, $74 million in 2003, and $71 million in 2002. The Company has contracts with the 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 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 2015. Construction of an on-site dry storage facility at Plant Vogtle is expected to begin in sufficient time to maintain pool full-core discharge capability. 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.

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NOTES (continued)
Georgia Power Company 2004 Annual Report

     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, ending in 2008. This fund will be used by the DOE for the decontamination and decommissioning of its nuclear fuel enrichment facilities. The law provides that utilities will recover these payments in the same manner as any other fuel expense. The Company — based on its ownership interest — estimates its remaining liability at December 31, 2004 under this law to be approximately $7 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.

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 percent to 8 percent of qualified 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 that they are more likely than not to be allowed by the Georgia Department of Revenue. Manufacturer’s tax credits of $12.9 million, $12.0 million, and $4.7 million were recorded on the Company’s books in 2004, 2003 and 2002, respectively.

Regulatory Assets and Liabilities

The Company is subject to the provisions of Financial Accounting Standards Board (FASB) Statement No. 71, Accounting for the Effects of Certain Types of Regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process.

     Regulatory assets and (liabilities) reflected in the Company’s balance sheets at December 31 relate to the following:

                     
    2004 2003 Note
    (in millions)
Deferred income tax charges
  $ 506   $ 510     (a)  
Premium on reacquired debt
    177     178     (b)  
Corporate building lease
    53     54     (f)  
Vacation pay
    57     50     (d)  
Postretirement benefits
    20     23     (f)  
DOE assessments
    10     13     (c)  
Generating plant outage costs
    40     49     (h)  
Other regulatory assets
    11     1     (f)  
Asset retirement obligation
    (20 )   (16 )   (a)  
Other cost of removal obligations
    (412 )   (412 )   (a)  
Accelerated cost recovery
        (111 )   (e)  
Deferred income tax credits
    (171 )   (187 )   (a)  
Environmental remediation reserve
    (22 )   (21 )   (g)  
Purchased power
        (77 )   (e)  
Other regulatory liabilities
    (6 )   (3 )   (f)  
 
Total
  $ 243   $ 51        
 
     
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 60 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 Georgia PSC.
 
   
(g)
  Amortized over a three-year period ending in 2007. See Note 3 under “Retail Rate Orders.”
 
   
(h)
  See “Property, Plant, and Equipment” herein.

     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 reflected in rates.

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NOTES (continued)
Georgia Power Company 2004 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 2.6 percent in 2004, 2.7 percent in 2003, and 2.9 percent in 2002. Under a new retail rate plan for the Company ending December 31, 2007 (2004 Retail Rate Plan), the depreciation rates have been revised by the Georgia PSC. 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 the three-year retail rate plan for the Company ending December 31, 2004 (2001 Retail Rate Plan), the Company discontinued recording accelerated depreciation and amortization. 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, the Company was ordered to recognize new Georgia PSC certified purchased power costs in rates evenly over the three years covered by the 2001 Retail Rate Plan. 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 recorded 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

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 costs 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. Although 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 received accounting guidance from the Georgia PSC allowing such treatment. Accordingly, the accumulated removal costs for other obligations previously accrued will continue to be reflected on the balance sheets 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, 2004 was $459 million. In addition, the Company has recognized 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, liabilities for the removal of these facilities have not been 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. In 2003, the Company revised the estimated cost to retire plants Hatch and Vogtle as a result of a new 2003 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” herein for further information on amounts included in rates.

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Georgia Power Company 2004 Annual Report

     Details of the asset retirement obligations included in the balance sheets are as follows:

                 
  2004 2003
    (in millions)
Balance beginning of year
  $ 476     $ 469  
Liabilities incurred
           
Liabilities settled
    (2 )      
Accretion
    31       31  
Cash flow revisions
          (24 )
 
Balance end of year
  $ 505     $ 476  
 

Nuclear Decommissioning

The Nuclear Regulatory Commission (NRC) requires licensees of commercial nuclear power reactors to establish a plan for providing reasonable assurance of funds for future 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 Georgia 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 Georgia PSC. The NRC’s minimum external funding requirements are based on a generic estimate of the cost to decommission only 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 based on the most current study as of December 31, 2004 for 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 these estimates.

     Annual provisions for nuclear decommissioning are based on an annuity method as approved by the Georgia PSC. The amount expensed in 2004 and fund balances were as follows:

                 
    Plant     Plant  
    Hatch     Vogtle  
    (in millions)  
Amount expensed in 2004
  $ 7     $ 2  
Accumulated provisions:
               
External trust funds, at fair value
  $ 294     $ 165  
Internal reserves
          2  
 
Total
  $ 294     $ 167  
 

     Based on the 2001 Retail Rate Plan, effective January 1, 2002, the Georgia PSC decreased the annual decommissioning costs for ratemaking to $9 million. This amount was based on the NRC generic estimate to decommission the radioactive portion of the facilities as of 2000. The estimates were $383 million and $282 million for plants Hatch and Vogtle, respectively. Significant assumptions used to determine the costs for ratemaking included an estimated inflation rate of 4.7 percent and an estimated trust earnings rate of 6.5 percent.

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Georgia Power Company 2004 Annual Report

     Effective January 1, 2005, the Georgia PSC has ordered the annual decommissioning costs for ratemaking be decreased from $9 million to $7 million. This amount is based on the NRC generic estimate to decommission the radioactive portion of the facilities as of 2003. The estimates are $421 million and $326 million for plants Hatch and Vogtle, respectively. Significant assumptions used to determine the costs for ratemaking include an estimated inflation rate of 3.1 percent and an estimated trust earnings rate of 5.1 percent. Another significant assumption used was the change in the operating license for Plant Hatch. 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 Company expects the Georgia PSC to periodically review and adjust, if necessary, the amounts collected in rates for the anticipated cost of decommissioning.

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. For the years 2004, 2003, and 2002, the average AFUDC rates were 8.22 percent, 5.51 percent, and 3.79 percent, respectively. AFUDC and interest capitalized, net of taxes, were 4.9 percent of net income after dividends on preferred stock for 2004 and less than 3 percent for 2003 and 2002.

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. As mandated by the Georgia PSC, the Company defers and amortizes nuclear refueling costs over the unit’s operating cycle before the next refueling. The refueling cycles are 18 and 24 months for plants Vogtle and Hatch, respectively. In accordance with the 2001 Retail Rate Plan, the Company defers the costs of certain significant inspection costs for the combustion turbines at Plant McIntosh and amortizes such costs over 10 years, which approximates the expected maintenance cycle.

Impairment of Long-Lived Assets and Intangibles

The Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by 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. See Note 3 under “Retail Rate Orders” and “Plant McIntosh Construction Project” for information regarding the disallowance of Plant McIntosh costs under the 2004 Retail Rate Plan.

Storm Damage Reserve

The Company maintains a reserve for property damage to cover the cost of damages from major storms to its transmission and distribution lines and the cost of uninsured damages to its generation facilities and other property as mandated by the Georgia PSC. These costs are expected to be recovered through regular monthly accruals which total $6.3 million annually under the 2004 Retail Rate Plan.

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Georgia Power Company 2004 Annual Report

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 costs of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed.

Stock Options

Southern Company provides non-qualified stock options to a large segment of the Company’s employees ranging from line management to executives. The Company accounts for its stock-based compensation plans in accordance with Accounting Principles Board Opinion No. 25. Accordingly, no compensation expense has been recognized because the exercise price of all options granted equaled the fair-market value of Southern Company’s common stock 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.

     The pro forma impact of fair-value accounting for options granted on earnings is as follows:

                 
    As     Pro  
Net Income   Reported     Forma  
    (in thousands)  
2004
  $ 658,001     $ 654,482  
 
               
2003
  $ 630,577     $ 626,738  
 
               
2002
  $ 617,629     $ 613,483  
 

     The estimated fair value of stock options granted in 2004, 2003, and 2002 were derived using the Black-Scholes stock option pricing model. The following table shows the assumptions and the weighted coverage. Fair values of stock options are as follows:

                         
    2004     2003     2002  
Interest rate
    3.10 %     2.70 %     2.80 %
Average expected life of stock options (in years)
    5.0       4.3       4.3  
Expected volatility of common stock
    19.60 %     23.60 %     26.30 %
Expected annual dividends on common stock
  $ 1.40     $ 1.37     $ 1.34  
Weighted average fair value of stock options granted
  $ 3.29     $ 3.59     $ 3.37  
 

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.

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Georgia Power Company 2004 Annual Report

     The Company’s financial instruments for which the carrying amounts did not equal fair value at December 31 were as follows:

                 
    Carrying     Fair  
    Amount     Value  
    (in millions)  
Long-term debt:
               
At December 31, 2004
  $ 5,055     $ 5,125  
At December 31, 2003
  $ 3,685     $ 3,739  
Preferred securities:
               
At December 31, 2004
           
At December 31, 2003
  $ 940     $ 976  
 

     The fair values were based on either closing market prices or closing prices of comparable instruments. See “Variable Interest Entities” herein and Note 6 under “Mandatorily Redeemable Preferred Securities/Long-Term Debt Payable to Affiliated Trusts” for further information.

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 value of marketable securities and qualifying cash flow hedges, and changes in additional minimum pension liability, less income taxes less reclassifications for amounts included in net income.

Variable Interest Entities

On March 31, 2004, the Company prospectively adopted FASB Interpretation No. 46R, “Consolidation of Variable Interest Entities,” which requires the primary beneficiary of a variable interest entity to consolidate the related assets and liabilities. The adoption of Interpretation No. 46R had no impact on the net income of the Company. However, as a result of the adoption, the Company deconsolidated certain wholly-owned trusts established to issue preferred securities since the Company is not the primary beneficiary of the trusts. Therefore, the investments in these trusts are reflected as Other Investments and the related loans from the trusts are reflected as Long-term Debt Payable to Affiliated Trusts on the balance sheets. This treatment resulted in a $29 million increase in both total assets and total liabilities as of March 31, 2004.

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 of 1974, as amended (ERISA), requirements. No contributions to the plan are expected for the year ending December 31, 2005. 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 Georgia PSC and the FERC. For the year ended December 31, 2005, such contributions are expected to total approximately $7.7 million.

     The measurement date for plan assets and obligations is September 30 for each year.

Pension Plans

The accumulated benefit obligation for the pension plans was $1.7 billion in 2004 and $1.6 billion in 2003. Changes during the year in the projected benefit obligations, accumulated benefit obligations, and the fair value of plan assets were as follows:

                 
    Projected  
    Benefit Obligation  
    2004     2003  
    (in millions)  
Balance at beginning of year
  $ 1,727     $ 1,564  
Service cost
    42       38  
Interest cost
    101       100  
Benefits paid
    (85 )     (83 )
Plan amendments
    1       6  
Actuarial loss
    99       102  
 
Balance at end of year
  $ 1,885     $ 1,727  
 

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NOTES (continued)
Georgia Power Company 2004 Annual Report

                 
    Plan Assets  
    2004     2003  
    (in millions)  
Balance at beginning of year
  $ 2,055     $ 1,838  
Actual return on plan assets
    207       294  
Benefits paid
    (81 )     (77 )
 
Balance at end of year
  $ 2,181     $ 2,055  
 

     Pension plan assets are managed and invested in accordance with all applicable requirements including ERISA and the Internal Revenue Code of 1986, as amended (Internal 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     2004     2003  
 
Domestic equity
    37 %     36 %     37 %
International equity
    20       20       20  
Fixed income
    26       26       24  
Real estate
    10       10       11  
Private equity
    7       8       8  
 
Total
    100 %     100 %     100 %
 

     The reconciliations of the funded status with the accrued pension costs recognized in the balance sheets were as follows:

                 
    2004     2003  
    (in millions)  
Funded status
  $ 295     $ 328  
Unrecognized transition amount
    (8 )     (13 )
Unrecognized prior service cost
    108       118  
Unrecognized net actuarial gain (loss)
    21       (66 )
 
Prepaid pension asset, net
  $ 416     $ 367  
 

     The prepaid pension asset, net is reflected in the balance sheets in the following line items:

                 
    2004     2003  
    (in millions)  
Prepaid pension asset
  $ 450     $ 405  
Employee benefit obligations
    (89 )     (82 )
Other property and investments - other
    19       18  
Accumulated other comprehensive income
    36       26  
 
Prepaid pension asset, net
  $ 416     $ 367  
 

     Components of the plans’ net periodic cost were as follows:

                         
    2004     2003     2002  
    (in millions)  
Service cost
  $ 42     $ 38     $ 36  
Interest cost
    101       100       107  
Expected return on plan assets
    (180 )     (179 )     (179 )
Recognized net gain
    (5 )     (19 )     (27 )
Net amortization
    7       6       4  
 
Net pension (income)
  $ (35 )   $ (54 )   $ (59 )
 

     Future benefit payments reflect expected future service and are estimated based on assumptions used to measure the projected benefit obligation for the pension plans. At December 31, 2004, estimated benefit payments were as follows:

         
    Benefit Payments  
    (in millions)  
2005
  $ 83  
2006
    83  
2007
    86  
2008
    89  
2009
    93  
2010 to 2014
  $ 568  
 

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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  
    2004     2003  
    (in millions)  
Balance at beginning of year
  $ 723     $ 627  
Service cost
    10       9  
Interest cost
    41       40  
Benefits paid
    (31 )     (29 )
Actuarial loss
    42       76  
Plan amendments
    (59 )      
 
Balance at end of year
  $ 726     $ 723  
 
                 
    Plan Assets        
    2004     2003  
    (in millions)  
Balance at beginning of year
  $ 265     $ 199  
Actual return on plan assets
    32       36  
Employer contributions
    33       59  
Benefits paid
    (31 )     (29 )
 
Balance at end of year
  $ 299     $ 265  
 

     Postretirement benefits plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal 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     2004     2003  
 
Domestic equity
    43 %     42 %     42 %
International equity
    20       23       21  
Domestic fixed income
    19       19        
Global fixed income
    13       11       32  
Real estate
    3       3       3  
Private equity
    2       2       2  
 
Total
    100 %     100 %     100 %
 

     The accrued postretirement costs recognized in the balance sheets were as follows:

                 
    2004     2003  
    (in millions)  
Funded status
  $ (428 )   $ (458 )
Unrecognized transition obligation
    78       87  
Unrecognized prior service cost
    27       91  
Unrecognized net loss
    203       171  
Fourth quarter contributions
    15       9  
 
Employee benefit obligations recognized in the balance sheets
  $ (105 )   $ (100 )
 

     Components of the postretirement plans’ net periodic cost were as follows:

                         
    2004     2003     2002  
    (in millions)  
Service cost
  $ 10     $ 9     $ 8  
Interest cost
    41       40       40  
Expected return on plan assets
    (25 )     (24 )     (20 )
Net amortization
    18       16       15  
 
Net postretirement cost
  $ 44     $ 41     $ 43  
 

     In the third quarter 2004, the Company prospectively adopted FASB Staff Position (FSP) 106-2, Accounting and Disclosure Requirements related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (Medicare Act). The Medicare Act provides a 28 percent prescription drug subsidy for Medicare eligible retirees. FSP 106-2 requires recognition of the impacts of the Medicare Act in the accumulated postretirement benefit obligation (APBO) and future cost of service for postretirement medical plans. The effect of the subsidy reduced the Company’s expenses for the six months ended December 31, 2004 by approximately $5 million and is expected to have a similar impact on future expenses. The subsidy’s impact on the postretirement medical plan APBO was a reduction of approximately $72 million. However, the ultimate impact on future periods is subject to federal regulations governing the subsidy created in the Medicare Act which are being finalized.

     Future benefit payments, including prescription drug benefits, reflect expected future service and are estimated based on assumptions used to measure the accumulated benefit obligation for the postretirement plans. Estimated benefit payments are reduced by drug

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subsidy receipts expected as a result of the Medicare Act as follows:

                         
    Benefit     Subsidy        
    Payments     Receipts     Total  
            (in millions)  
2005
  $ 28     $     $ 28  
2006
    31       (3 )     28  
2007
    34       (3 )     31  
2008
    37       (4 )     33  
2009
    41       (4 )     37  
2010 to 2014
  $ 257     $ (28 )   $ 229  
 

     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:

                         
    2004     2003     2002  
 
Discount
    5.75 %     6.00 %     6.50 %
Annual salary increase
    3.50       3.75       4.00  
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 11.0 percent for 2004, decreasing gradually to 5.0 percent through the year 2012, 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, 2004, as follows:

                 
    1 Percent     1 Percent  
    Increase     Decrease  
    (in millions)  
Benefit obligation
  $ 75     $ 59  
Service and interest costs
    5       4  
 

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 2004, 2003, and 2002 were $18 million, $18 million, and $17 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

On December 21, 2004, the Georgia PSC voted to approve the 2004 Retail Rate Plan. Under the terms of the 2004 Retail Rate Plan, earnings will be evaluated against a retail return on common equity range of 10.25 percent to 12.25 percent. Two-thirds of any earnings above 12.25 percent will be applied to rate refunds, with the remaining one-third retained by the Company. Retail rates will be increased by approximately $194 million and customer fees by approximately $9 million effective January 1, 2005 to cover the higher costs of purchased power; operating and maintenance expenses; environmental compliance; and continued investment in new generation, transmission and distribution facilities to support growth and ensure reliability.

     In the 2004 Retail Rate Plan, the Georgia PSC also approved the transfer of the Plant McIntosh construction project, which is scheduled for completion in June 2005, to the Company and Savannah Electric at a total fair market value of approximately $385 million. This value

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reflects an approximate $16 million disallowance, of which $13 million is attributable to the Company, and reduced the Company’s 2004 net income by approximately $8 million. The Georgia PSC also certified the total completion cost of $547 million for the project. The amount of the disallowance will be adjusted accordingly based on the actual completion cost of the project. Under the 2004 Retail Rate Plan, the Plant McIntosh revenue requirement impact will be reflected in the Company’s rates evenly over the three years ending 2007.

     The Company will not file for a general base rate increase unless its projected retail return on common equity falls below 10.25 percent. The Company is required to file a general rate case by July 1, 2007, in response to which the Georgia PSC would be expected to determine whether the rate order should be continued, modified, or discontinued.

     Under Georgia PSC ratemaking provisions, $22 million has been deferred in a regulatory liability account for use in meeting future environmental remediation costs. Under the 2004 Retail Rate Plan, this regulatory liability will be amortized over a three-year period beginning January 1, 2005. However, the Georgia PSC also approved an annual environmental accrual of $5.4 million. Environmental remediation expenditures will be charged against the reserve as they are incurred. The annual accrual amount will be reviewed and adjusted in future regulatory proceedings.

     Under the 2001 Retail Rate Plan, retail rates were decreased by $118 million effective January 1, 2002. Under the terms of the 2001 Retail Rate Plan, earnings were 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 were to be applied to rate refunds, with the remaining one-third retained by the Company. The Company’s earnings in 2004, 2003 and 2002 were within the common equity range.

     Under the 2001 Retail Rate Plan, 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 2001 Retail Rate Plan required the Company to recognize capacity and operating and maintenance costs related to new Georgia PSC-certified PPAs evenly in rates over a three-year period ended December 31, 2004.

Retail Fuel Hedging Program

Effective in January 2003, the Georgia PSC approved an order 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 hedging program will be shared with the retail customers receiving 75 percent and the Company retaining 25 percent of the total net gains. In 2004, the Company had a total net gain of $7.4 million, of which the Company retained $1.9 million.

Fuel Cost Recovery

On August 19, 2003, the Georgia PSC issued an order allowing 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 represented an average annual increase in rates paid by customers of approximately 1.6 percent. In recent months, the Company has experienced higher than expected fuel costs since the order was issued. Those higher fuel costs have increased the under recovered fuel costs. On February 18, 2005, the Company filed a request with the Georgia PSC for a fuel cost recovery rate increase. In the ordinary course, these new rates will be effective June 1, 2005 following a hearing before and approval by the Georgia PSC. In its filing, the Company asked that the Georgia PSC accept the new rate, effective April 1, 2005, prior to a formal hearing on the Company’s request. This action, if taken by the Georgia PSC, would serve to mitigate expected increases in the under recovered balance during April and May, but will not preclude the Georgia PSC from subsequently adjusting the rates. The requested increase, representing an annual increase in revenues of approximately 11.7 percent, will allow for the recovery of fuel costs based on an estimate of future fuel costs, as well as the collection of the existing under recovery of fuel costs. The Company’s under recovered fuel costs as of January 31, 2005 totaled $390 million. The Georgia

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PSC will examine the Company’s fuel expenditures and determine whether the proposed fuel cost recovery rate is just and reasonable before issuing its decision in May 2005. The final outcome of the filing cannot be determined at this time.

Nuclear Performance Standards

Through December 31, 2004, the Company has operated in accordance with the nuclear performance standard the Georgia PSC adopted 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. Such amounts flow through the fuel cost recovery mechanism. Any award or penalty for the 2002-2004 evaluation period will not be known until the second quarter of 2005.

     Effective January 1, 2005, the Georgia PSC has discontinued the nuclear performance standard.

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, alleging violations of the New Source Review (NSR) provisions of the Clean Air Act and related state laws 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 was stayed in the spring of 2001 during the appeal of a similar NSR enforcement action against the Tennessee Valley Authority (TVA) before the U.S. Court of Appeals for the Eleventh Circuit. In June 2003, the Court of Appeals issued its ruling in the TVA case, dismissing the appeal for reasons unrelated to the issues in the case pending against the Company. In May 2004, the U.S. Supreme Court denied the EPA’s petition for review of the case. At this time, no party to the case against the Company has sought to reopen the case, which remains administratively closed in the U.S. District Court for the Northern District of Georgia.

     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. District courts addressing these cases have, to date, issued opinions that reached conflicting conclusions.

     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 maximum civil penalties of $25,000 to $32,500 per day, per violation at each generating unit, depending on the date of the alleged violation. 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.

     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 (RMRR) exclusion. A coalition of states and environmental organizations has filed petitions for review of these revisions with the U.S. Court of Appeals for the District of Columbia Circuit. The October 2003 RMRR rules have been stayed by the Court of Appeals pending its review of the rules. 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, related legal challenges and potential rulemakings by the State of Georgia cannot be determined at this time.

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 for the Northern District of Georgia against the Company for

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alleged violations of the Clean Air Act at four of the 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.

     The court has concluded the liability phase of the action. The court ruled in favor of the Company on the allegations regarding the hazardous air pollutants, the allegations regarding emission offsets, and a majority of the allegations regarding the permit provision that requires the combined cycle units to operate above certain levels. The court ruled in favor of the plaintiffs on a majority of the opacity incidents. The Company has filed a petition for review of the decision with the U.S. Court of Appeals for the Eleventh Circuit. The district court case has been administratively closed pending that appeal. If necessary, the district court will hold a separate remedy trial which will address civil penalties and possible injunctive relief requested by the plaintiffs. The ultimate outcome of this matter cannot currently be determined; however, an adverse outcome could require substantial capital expenditures that cannot be determined at this time and could possibly require the 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 Remediation

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 $35 million in cumulative expenses through December 31, 2004 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, 2004, 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.

Race Discrimination Litigation

In July 2000, a lawsuit alleging race discrimination was filed by three of the Company’s 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, 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 U.S. Court of Appeals for the Eleventh Circuit subsequently denied plaintiff’s petition seeking permission to file an appeal of the October 2001 decision. In March 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. In April 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. On November 10, 2004, a three-judge panel of the U.S. Court of Appeals for the Eleventh Circuit issued an order affirming in all respects the district court’s

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rulings. On December 1, 2004, the plaintiffs filed a petition for rehearing seeking a review of the November 2004 order by the entire Eleventh Circuit panel of judges. If this petition is denied, the plaintiffs will have 90 days from the date of the court’s order denying the petition within which to file a petition for writ of certiorari to the U.S. Supreme Court. 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, have been named as defendants in numerous lawsuits brought by landowners since 2001. 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 exceed the easements or other property rights held by defendants. The plaintiffs assert claims for, among other things, trespass and unjust enrichment, and seek compensatory and punitive damages and injunctive relief.

     On January 14, 2005, the Superior Court of Decatur County, Georgia granted partial summary judgment in a lawsuit brought by landowners against the Company based on the plaintiffs’ declaratory judgment claim that the easements do not permit general telecommunications use. The Company is appealing this ruling to the Georgia Court of Appeals. The question of damages and other liabilities or remedies issues with respect to this action, if any, will be decided at a future trial. In the event of an adverse verdict in the case, the Company could appeal both liability and damages or other relief granted. Management believes that the Company 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 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, 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 it in pending and future right of way litigation. The Company believes that the plaintiff’s claims are without merit. In the fall of 2004, the trial court stayed the case until resolution of the underlying landowner litigation discussed above. On January 12, 2005, the Georgia Court of Appeals dismissed the telecommunications company’s appeal of the trial court’s order for lack of jurisdiction. 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.

Generation Interconnection Agreements

In July 2003, the FERC issued its final rule on the standardization of generation interconnection agreements and procedures (Order 2003). Order 2003 shifts much of the financial burden of new transmission investment from the generator to the transmission provider. The FERC has indicated that Order 2003, which was effective January 20, 2004, is to be applied prospectively to interconnection agreements. Subsidiaries of Tenaska, Inc., as counterparties to previously executed interconnection agreements with the Company and another Southern Company subsidiary, have filed complaints at the FERC requesting that the FERC modify the agreements and that the Company refund a total of $7.9 million previously paid for interconnection facilities, with interest. The Company has opposed such relief and the proceedings are still pending. The impact of Order 2003 and its subsequent rehearings on the Company and the final results of these matters cannot be determined at this time.

Market-Based Rate Authority

The Company has authorization from the FERC to sell power to nonaffiliates at market-based prices. 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, the retail operating companies,

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and Southern Power and found them to be “pivotal suppliers” in their retail service territories and ordered the implementation of certain mitigation measures. Southern Company and others sought rehearing of the FERC order, and the FERC delayed implementation of certain mitigation measures. In April 2004, the FERC issued an order that abandoned the SMA test and adopted a new interim analysis for measuring generation market power. This new interim approach requires utilities to submit a pivotal supplier screen and a wholesale market share screen. If the applicant does not pass both screens, there will be a rebuttable presumption regarding generation market power. The FERC’s order also sets forth procedures for rebutting these presumptions and addresses mitigation measures for those entities that are found to have market power. In the absence of specific mitigation measures, the order includes several cost-based mitigation measures that would apply by default. The FERC also initiated a new rulemaking proceeding that, among other things, will adopt a final methodology for assessing generation market power.

     In July 2004, the FERC denied Southern Company’s request for rehearing, along with a number of others, and reaffirmed the interim tests that it adopted in April. In August 2004, Southern Company submitted a filing to the FERC which included results showing that Southern Company passed the pivotal supplier screen for all markets and the wholesale market share screen for all markets except the Southern Company retail service territory. Southern Company also submitted other analyses to demonstrate that it lacks generation market power. On December 17, 2004, the FERC initiated a proceeding to assess Southern Company’s generation dominance within the Southern Company retail service territory. The ability to charge market-based rates in other markets is not at issue. As directed by this order, on February 15 2005, Southern Company submitted additional information related to generation dominance in the retail service territory. Any new market-based rate transactions in Southern Company’s retail service territory entered into after February 27, 2005 will be subject to refund to the level of the default cost-based rates, pending the outcome of the proceeding. Southern Company, along with other utilities, has also filed an appeal of the FERC’s April and July 2004 orders with the U.S. Court of Appeals for the District of Columbia Circuit. The FERC has asked the court to dismiss the appeal on the grounds that it is premature.

     In the event that the FERC’s default mitigation measures are ultimately applied, the Company may be required to charge cost-based rates for certain wholesale sales in the Southern Company retail service territory, which may be lower than negotiated market-based rates. The final outcome of this matter will depend on the form in which the final methodology for assessing generation market power and mitigation rules may be ultimately adopted and cannot be determined at this time.

Plant McIntosh Construction Project

In December 2002 after a competitive bidding process, the Georgia PSC certified PPAs between Southern Power and the Company and Savannah Electric for capacity from Plant McIntosh Units 10 and 11, construction of which is scheduled to be completed in June 2005. In April 2003, Southern Power applied for FERC approval of these PPAs. In July 2003, the FERC accepted the PPAs to become effective June 1, 2005, subject to refund, and ordered that hearings be held. Intervenors opposed the FERC’s acceptance of the PPAs, alleging that they did not meet the applicable standards for market-based rates between affiliates. To ensure the timely completion of the Plant McIntosh construction project and the availability of the units in the summer of 2005 for their retail customers, in May 2004, the Company and Savannah Electric requested the Georgia PSC to direct them to acquire the McIntosh construction project. The Georgia PSC issued such an order and the transfer occurred on May 24, 2004 at a total cost of approximately $415 million, including approximately $14 million of transmission interconnection facilities. Subsequently, Southern Power filed a request to withdraw the PPAs and to terminate the ongoing FERC proceedings. In August 2004, the FERC issued a notice accepting the request to withdraw the PPAs and permitting such request to become effective by operation of law. However, the FERC made no determination on what additional steps may need to be taken with respect to testimony provided in the proceedings. The ultimate outcome of any additional FERC action cannot be determined at this time.

     As directed by the Georgia PSC order, on June 3, 2004, the Company and Savannah Electric filed an application to amend the resource certificate granted by the Georgia PSC in 2002. In connection with the 2004 Retail Rate Plan, the Georgia PSC approved the transfer of the Plant McIntosh construction project at

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a total fair market value of approximately $385 million. This value reflects an approximate $16 million disallowance, of which $13 million is attributable to the Company, and reduced the Company’s net income by approximately $8 million. The Georgia PSC also certified a total completion cost of $547 million for the project. The amount of the disallowance will be adjusted accordingly based on the actual completion cost of the project. Under the 2004 Retail Rate Plan, the Plant McIntosh revenue requirements impact will be reflected in the Company’s rates evenly over the three years ending 2007. See “Retail Rate Orders” herein for additional information regarding the transfer of the Plant McIntosh construction project.

4. JOINT OWNERSHIP AGREEMENTS

The Company and an affiliate, Alabama 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, 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:

                         
    2004     2003     2002  
    (in millions)  
Energy
  $ 51     $ 55     $ 53  
Capacity
    36       34       32  
 
Total
  $ 87     $ 89     $ 85  
 

     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 combustion- turbine units 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.

     At December 31, 2004, 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 %   $ 3,304 *   $ 1,756  
Plant Hatch (nuclear)
    50.1       932       485  
Plant Wansley (coal)
    53.5       394       164  
Plant Scherer (coal)
                       
Units 1 and 2
    8.4       114       53  
Unit 3
    75.0       561       259  
Plant McIntosh Common Facilities (combustion-turbine)
    75.0       34       4  
Rocky Mountain (pumped storage)
    25.4       169 *     89  
Intercession City (combustion-turbine)
    33.3       12       2  
 


*Investment includes write-offs

     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 and a combined State of Georgia income tax return. Under a joint consolidated income tax allocation agreement, as required by the PUHCA, each subsidiary’s current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more expense than would be paid if they filed a separate tax return. In accordance with IRS regulations, each company is jointly and severally liable for the tax liability.

     In 2004, in order to avoid the loss of certain federal income tax credits related to the production of synthetic fuel, Southern Company chose to defer certain

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deductions otherwise available to the subsidiaries. The cash flow benefit associated with the utilization of the tax credits was allocated to the subsidiary that otherwise would have claimed the available deductions on a separate company basis without the deferral. This allocation concurrently reduced the tax benefit of the credits allocated to those subsidiaries that generated the credits. As the deferred expenses are deducted, the benefit of the tax credits will be repaid to the subsidiaries that generated the tax credits. The Company has recorded $25 million payable to these subsidiaries in Accumulated Deferred Income Taxes on the balance sheets at December 31, 2004.

     The transfer of the Plant McIntosh construction project from Southern Power to the Company resulted in a deferred gain to Southern Power for federal income tax purposes. The Company will reimburse Southern Power for the related $5.4 million deferred taxes reflected in Southern Power’s future taxable income. This payable to Southern Power is included in Other Deferred Credits on the balance sheets at December 31, 2004.

     The transfer of the Dahlberg, Wansley and Franklin projects to Southern Power from the Company in 2001 and 2002 also resulted in a deferred gain for federal income tax purposes. Southern Power will reimburse the Company for the remaining balance of the related deferred taxes of $13.3 million reflected in the Company’s future taxable income. This receivable from Southern Power is included in Other Deferred Debits on the balance sheets at December 31, 2004.

     At December 31, 2004, tax-related regulatory assets were $506 million and tax-related regulatory liabilities were $171 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:

                         
    2004     2003     2002  
    (in millions)  
Total provision for income taxes:
                       
Federal:
                       
Current
  $ 116     $ 143     $ 261  
Deferred
    221       181       60  
 
 
    337       324       321  
 
State:
                       
Current
    12       24       31  
Deferred
    30       16       5  
Deferred investment tax credits
          2        
 
Total
  $ 379     $ 366     $ 357  
 

     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:

                 
    2004     2003  
    (in millions)  
Deferred tax liabilities:
               
Accelerated depreciation
  $ 2,050     $ 1,966  
Property basis differences
    577       563  
Other
    449       329  
 
Total
    3,076       2,858  
 
Deferred tax assets:
               
Federal effect of state deferred taxes
    106       96  
Other property basis differences
    147       156  
Other deferred costs
    149       160  
Other
    52       75  
 
Total
    454       487  
 
Net deferred tax liabilities
    2,622       2,371  
Portion included in current (liabilities) assets, net
    (66 )     68  
 
Accumulated deferred income taxes in the balance sheets
  $ 2,556     $ 2,439  
 

     In accordance with regulatory requirements, deferred investment tax credits are amortized over the life of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of income. Credits amortized in this manner amounted to $12 million in 2004, $15 million in 2003, and $12 million in 2002. At December 31, 2004, all investment tax credits available to reduce federal income taxes payable had been utilized.

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Georgia Power Company 2004 Annual Report

     A reconciliation of the federal statutory tax rate to the effective income tax rate is as follows:

                         
    2004     2003     2002  
     
Federal statutory rate
    35 %     35 %     35 %
State income tax, net of federal deduction
    3       3       2  
Non-deductible book depreciation
    1       1       1  
Other
    (2 )     (2 )     (1 )
 
Effective income tax rate
    37 %     37 %     37 %
 

6. FINANCING

Mandatorily Redeemable Preferred Securities/Long-Term Debt Payable to Affiliated Trusts

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 $969 million, which constitute substantially all of the assets of the trusts and are reflected in the balance sheets as Long-Term Debt Payable to Affiliated 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, 2004, preferred securities of $940 million were outstanding. See Note 1 under “Variable Interest Entities” for additional information on the accounting treatment for these trusts and the related securities. The preferred securities are recognized as liabilities in the balance sheets.

Long-Term Debt Due Within One Year

A summary of the scheduled maturities and redemptions of securities due within one year at December 31 is as follows:

                 
    2004     2003  
    (in millions)  
Capital lease
  $ 2     $ 2  
Senior notes
    450        
 
Total
  $ 452     $ 2  

     Serial maturities through 2009 applicable to total long-term debt are as follows: $452 million in 2005; $153 million in 2006; $303 million in 2007; $3 million in 2008; and $279 million in 2009.

Pollution Control Bonds

Pollution control obligations represent loans to the Company from public authorities of funds derived from sales by such authorities of revenue bonds issued to finance pollution control facilities. The Company is required to make payments sufficient for the authorities to meet principal and interest requirements of such 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, 2004 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, 2004 and 2003, the Company had a capitalized lease obligation for its corporate headquarters building of $77 million and $79 million, respectively, with an interest rate of 8.1 percent. For ratemaking purposes, the Georgia PSC 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 Georgia PSC. At December 31, 2004 and 2003, the interest and lease amortization deferred on the balance sheets were $53 million and $54 million, respectively.

Bank Credit Arrangements

At the beginning of 2005, the Company had an unused credit arrangement with banks totaling $773.1 million. Of these facilities, $423.1 million expire at various times throughout 2005, with the remaining $350 million expiring in 2007. The facilities that expire in 2005 provide the option of converting borrowings into a two-year term loan. The agreements contain stated borrowing rates but also allow for competitive bid loans. All the agreements 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 the Company. Compensating balances are not legally

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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 arrangements. For purposes of these definitions, indebtedness excludes the long-term debt payable to affiliated trusts. 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 $773.1 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, 2004 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, 2004 was $208 million. There were no outstanding extendible commercial notes at December 31, 2004. The amount of commercial paper outstanding at December 31, 2003 was $137 million. During 2004, the peak amount of commercial paper outstanding was $391.5 million and the average amount outstanding was $130.7 million. The average annual interest rate on commercial paper in 2004 was 1.27 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 Georgia PSC. The Company also enters into hedges of forward electricity sales. There was no material ineffectiveness recorded in earnings in 2004 and 2003.

     At December 31, 2004, the fair value of derivative energy contracts was reflected in the financial statements as follows:

         
    Amounts  
    (in millions)  
Regulatory liabilities, net
  $ 5.7  
Other comprehensive income
     
Net income
    0.1  
Total fair value
  $ 5.8  
 

     The fair value gain or loss for cash flow hedges that are recoverable through the regulatory fuel clauses are recorded in regulatory assets and liabilities and are recognized in earnings at the same time the hedged items affect earnings. The Company has energy-related hedges in place up to and including 2007.

     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. In addition to interest rate swaps, the Company has also entered into certain options agreements that effectively cap its interest rate exposure in return for payment of a premium. In some cases, costless collars have been used that effectively establish a floor and a ceiling to interest rate expense.

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Notes (continued)
Georgia Power Company 2004 Annual Report

     At December 31, 2004, the Company had interest derivatives outstanding with net fair value losses as follows:

Cash Flow Hedges

                         
    Weighted                
    Average             Fair  
    Fixed             Value  
    Rate     Notional     Gain/  
Maturity   Paid     Amount     (Loss)  
            (in millions)  
 
2005
    1.56 %   $ 50     $ 0.1  
2005
    1.96       250       0.3  
2005-2007
    2.35-3.85 1     400       0.6  
2006
    6.00 2     150       (0.1 )
2015
    4.66       250       0.7  
2015
    5.03       100       (0.9 )


1.   Capped rate based on formula approximating the yield on short rate tax-exempt, auction rate securities.
 
2.   Costless collar with cap rate of 6.00 percent.

     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 2004, the Company settled losses totaling $12.4 million upon termination of certain interest derivatives at the same time it issued debt. For the years 2004 and 2003, approximately $3.9 million and $3.4 million, respectively, were reclassified from other comprehensive income to interest expense. For 2002, the amounts reclassified were immaterial. For 2005, pre-tax losses of approximately $0.4 million are expected to be reclassified from other comprehensive income to interest expense. The Company has interest-related hedges in place through 2017. Subsequent to December 31, 2004, the Company terminated an interest rate swap with a notional amount of $250 million at a gain of $1.2 million. The gain will be amortized to interest expense over a 10-year period.

7. COMMITMENTS

Construction Program

The Company currently estimates property additions to be approximately $911 million, $1.1 billion, and $1.2 billion in 2005, 2006, and 2007, respectively. These amounts include $40 million, $33 million, and $28 million in 2005, 2006, and 2007, respectively, for construction expenditures related to contractual purchase commitments for uranium and nuclear fuel conversion, enrichment, and fabrication services included under “Fuel 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, 2004, significant purchase commitments were outstanding in connection with the construction program.

     The Company currently has under construction Plant McIntosh Units 10 and 11 scheduled for completion in June 2005. In addition, construction related to new transmission and distribution facilities and capital improvements to existing generation, transmission and distribution facilities, including those needed to meet environmental standards, are ongoing.

Long-Term Service Agreements

The Company and Savannah Electric have entered into a Long-Term Service Agreement (LTSA) with General Electric (GE) for the purpose of securing maintenance support for the combustion turbines at the Plant McIntosh combine cycle facility. 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 each contract.

     In general, this LTSA is 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 this agreement are currently estimated at $182 million over the remaining term of the agreement, which may range up to 30 years. However, the LTSA contains various cancellation provisions at the option of the Company.

     The Company has entered into a LTSA with GE to provide all necessary labor and parts for neutron monitoring at Plant Hatch for a period of 10 years. Total payments to GE under this agreement are currently estimated at $14.9 million, of which $7.4 is

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Georgia Power Company 2004 Annual Report

expected to be billed to the joint owners.

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 Exchange future prices at December 31, 2004. Also the Company has entered into various long-term commitments for the purchase of electricity. Total estimated minimum long-term obligations at December 31, 2004 were as follows:

                 
            Coal and  
    Natural     Nuclear  
Year   Gas     Fuel  
    (in millions)  
2005
  $ 248     $ 1,731  
2006
    237       1,617  
2007
    151       1,105  
2008
    200       552  
2009
    189       219  
2010 and thereafter
    1,669       96  
 
Total commitments
  $ 2,694     $ 5,320  
 

     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.

Purchased Power Commitments

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 $55 million, $57 million, and $57 million in 2004, 2003, and 2002, respectively. The current projected Plant Vogtle capacity payments are:

         
Year   Capacity Payments  
    (in millions)  
2005
  $ 56  
2006
    55  
2007
    54  
2008
    54  
2009
    54  
2010 and thereafter
    315  
 
Total
  $ 588  
 

     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.

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Georgia Power Company 2004 Annual Report

     Estimated total long-term obligations at December 31, 2004 were as follows:

                 
            Non-  
Year   Affiliated     Affiliated  
    (in millions)  
2005
  $ 205     $ 78  
2006
    205       86  
2007
    205       87  
2008
    205       88  
2009
    205       67  
2010 and thereafter
    567       340  
 
Total
  $ 1,592     $ 746  
 

Operating Leases

The Company has entered into various operating leases with various terms and expiration dates. Rental expenses related to these operating leases totaled $38 million for 2004, $36 million for 2003, and $35 million for 2002. At December 31, 2004, estimated minimum rental commitments for these noncancelable operating leases were as follows:

                         
    Minimum Obligations
Year   Rail Cars     Other     Total  
    (in millions)
2005
  $ 15     $ 17     $ 32  
2006
    16       13       29  
2007
    13       10       23  
2008
    14       8       22  
2009
    13       7       20  
2010 and thereafter
    55       8       63  
 
Total
  $ 126     $ 63     $ 189  
 

     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 2011, and the Company’s maximum obligation is $72 million. 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 Georgia PSC.

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, 2004, the outstanding loans guaranteed by the Company were $5.1 million and loan loss reserves of $1.1 million have been recorded.

     Alabama Power has guaranteed unconditionally the obligation of SEGCO under an installment sale agreement for the purchase of certain pollution control facilities at SEGCO’s generating units, pursuant to which $24.5 million principal amount of pollution control revenue bonds are outstanding. 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. 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, 2004, 1,547 current and former employees of the Company participated in the stock option plan. The maximum number of shares of Southern Company 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

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rata over a maximum period of three years from the date of grant. Options outstanding will expire no later than 10 years after the date of grant, unless terminated earlier by the Southern Company Board of Directors in accordance with the stock option plan. Activity from 2002 to 2004 for the options granted to the Company’s employees under the stock option plan is summarized below:

                 
    Shares     Average  
    Subject     Option Price  
    To Option     Per Share  
 
Balance at December 31, 2001
    6,597,517     $ 17.41  
Options granted
    1,781,940       25.27  
Options canceled
    (40,607 )     16.67  
Options exercised
    (1,160,253 )     15.18  
 
Balance at December 31, 2002
    7,178,597       19.73  
Options granted
    1,455,517       27.98  
Options canceled
    (54,860 )     25.47  
Options exercised
    (1,428,273 )     16.92  
 
Balance at December 31, 2003
    7,150,981       21.92  
Options granted
    1,434,915       29.50  
Options canceled
    (5,802 )     25.99  
Options exercised
    (1,450,309 )     18.25  
 
Balance at December 31, 2004
    7,129,785     $ 24.19  
 
 
               
Options exercisable:
               
At December 31, 2002
    3,405,398          
At December 31, 2003
    3,956,234          
At December 31, 2004
    4,304,091          
 

     The following table summarizes information about options outstanding at December 31, 2004:

                         
    Dollar Price  
    Range of Options  
    13-20     20-26     26-32  
 
Outstanding:
                       
Shares (in thousands)
    1,914       2,411       2,805  
Average remaining life (in years)
    5.6       6.8       8.6  
Average exercise price
  $ 17.42     $ 24.26     $ 28.76  
Exercisable:
                       
Shares (in thousands)
    1,914       1,906       483  
Average exercise price
  $ 17.42     $ 23.99     $ 28.01  
 

9. 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 $10.76 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

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NOTES (continued)
Georgia Power Company 2004 Annual Report

accumulated funds available to the insurer under that policy. The current maximum annual assessments for the Company under the NEIL policies would be $43 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 condition after an accident. Any remaining proceeds are to be applied next toward the costs of decontamination and debris removal operations ordered by the NRC, and any further remaining proceeds are to be paid either to the Company or to its bond trustees as may be appropriate under the policies and applicable trust indentures.

     All retrospective assessments, whether generated for liability, property, or replacement power, may be subject to applicable state premium taxes.

10. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

Summarized quarterly financial information for 2004 and 2003 is as follows:

                         
                    Net Income  
                    After  
                    Dividends on  
    Operating     Operating     Preferred  
Quarter Ended   Revenues     Income     Stock  
    (in millions)  
     
March 2004
  $ 1,199     $ 285     $ 144  
June 2004
    1,353       322       156  
September 2004
    1,582       486       287  
December 2004
    1,237       166       71  
 
                       
March 2003
  $ 1,126     $ 262     $ 133  
June 2003
    1,190       293       159  
September 2003
    1,487       490       265  
December 2003
    1,111       179       74  
 

     The Company’s business is influenced by seasonal weather conditions.

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SELECTED FINANCIAL AND OPERATING DATA 2000-2004
Georgia Power Company 2004 Annual Report

                                         
 
    2004     2003     2002     2001     2000  
 
Operating Revenues (in thousands)
  $ 5,370,808     $ 4,913,507     $ 4,822,460     $ 4,965,794     $ 4,870,618  
Net Income after Dividends on Preferred Stock (in thousands)
  $ 658,001     $ 630,577     $ 617,629     $ 610,335     $ 559,420  
Cash Dividends on Common Stock (in thousands)
  $ 565,500     $ 565,800     $ 542,900     $ 527,300     $ 549,600  
Return on Average Common Equity (percent)
    13.95       14.05       13.99       14.12       13.66  
Total Assets (in thousands)
  $ 15,822,338     $ 14,850,754     $ 14,342,656     $ 14,447,973     $ 13,971,211  
Gross Property Additions (in thousands)
  $ 1,126,064     $ 742,810     $ 883,968     $ 1,389,751     $ 1,078,163  
 
Capitalization (in thousands):
                                       
Common stock equity
  $ 4,890,561     $ 4,540,211     $ 4,434,447     $ 4,397,485     $ 4,249,544  
Preferred stock
    14,609       14,569       14,569       14,569       14,569  
Mandatorily redeemable preferred securities
          940,000       940,000       789,250       789,250  
Long-term debt payable to affiliated trusts
    969,073                          
Long-term debt
    3,709,852       3,762,333       3,109,619       2,961,726       3,041,939  
 
Total (excluding amounts due within one year)
  $ 9,584,095     $ 9,257,113     $ 8,498,635     $ 8,163,030     $ 8,095,302  
 
Capitalization Ratios (percent):
                                       
Common stock equity
    51.0       49.0       52.2       53.9       52.5  
Preferred stock
    0.2       0.2       0.2       0.2       0.2  
Mandatorily redeemable preferred securities
          10.2       11.1       9.6       9.7  
Long-term debt payable to affiliated trusts
    10.1                          
Long-term debt
    38.7       40.6       36.5       36.3       37.6  
 
Total (excluding amounts due within one year)
    100.0       100.0       100.0       100.0       100.0  
 
Security Ratings:
                                       
Preferred Stock -
                                       
Moody’s
  Baa1     Baa1     Baa1     Baa1       a2  
Standard and Poor’s
  BBB+     BBB+     BBB+     BBB+     BBB+  
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
    1,801,426       1,768,662       1,734,430       1,698,407       1,669,566  
Commercial
    265,543       258,276       250,993       244,674       237,977  
Industrial
    7,676       7,899       8,240       8,046       8,533  
Other
    3,482       3,434       3,328       3,239       3,159  
 
Total
    2,078,127       2,038,271       1,996,991       1,954,366       1,919,235  
 
Employees (year-end):
    8,731       8,714       8,837       9,048       8,860  
 

N/A = Not Applicable.

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SELECTED FINANCIAL AND OPERATING DATA 2000-2004 (continued)
Georgia Power Company 2004 Annual Report

                                         
 
    2004     2003     2002     2001     2000  
 
Operating Revenues (in thousands):
                                       
Residential
  $ 1,736,072     $ 1,583,082     $ 1,600,438     $ 1,507,031     $ 1,535,684  
Commercial
    1,812,096       1,661,054       1,631,130       1,682,918       1,620,466  
Industrial
    1,172,936       1,012,267       1,004,288       1,106,420       1,154,789  
Other
    55,881       53,569       52,241       52,943       6,399  
 
Total retail
    4,776,985       4,309,972       4,288,097       4,349,312       4,317,338  
Sales for resale - non-affiliates
    246,545       259,376       270,678       366,085       297,643  
Sales for resale - affiliates
    166,245       174,855       98,323       99,411       96,150  
 
Total revenues from sales of electricity
    5,189,775       4,744,203       4,657,098       4,814,808       4,711,131  
Other revenues
    181,033       169,304       165,362       150,986       159,487  
 
Total
  $ 5,370,808     $ 4,913,507     $ 4,822,460     $ 4,965,794     $ 4,870,618  
 
Kilowatt-Hour Sales (in thousands):
                                       
Residential
    22,930,372       21,778,582       22,144,559       20,119,080       20,693,481  
Commercial
    28,014,357       26,940,572       26,954,922       26,493,255       25,628,402  
Industrial
    26,357,271       25,703,421       25,739,785       25,349,477       27,543,265  
Other
    602,202       595,742       593,202       583,007       568,906  
 
Total retail
    77,904,202       75,018,317       75,432,468       72,544,819       74,434,054  
Sales for resale - non-affiliates
    5,969,983       8,835,804       8,069,375       8,110,096       6,463,723  
Sales for resale - affiliates
    4,782,873       5,844,196       3,962,559       3,133,485       2,435,106  
 
Total
    88,657,058       89,698,317       87,464,402       83,788,400       83,332,883  
 
Average Revenue Per Kilowatt-Hour (cents):
                                       
Residential
    7.57       7.27       7.23       7.49       7.42  
Commercial
    6.47       6.17       6.05       6.35       6.32  
Industrial
    4.45       3.94       3.90       4.36       4.19  
Total retail
    6.13       5.75       5.68       6.00       5.80  
Sales for resale
    3.84       2.96       3.07       4.14       4.43  
Total sales
    5.85       5.29       5.32       5.75       5.65  
Residential Average Annual Kilowatt-Hour Use Per Customer
    12,838       12,421       12,867       11,933       12,520  
Residential Average Annual Revenue Per Customer
  $ 972     $ 903     $ 930     $ 894     $ 929  
Plant Nameplate Capacity Ratings (year-end) (megawatts)
    13,978       13,980       14,059       14,474       15,114  
Maximum Peak-Hour Demand (megawatts):
                                       
Winter
    12,208       13,153       11,873       11,977       12,014  
Summer
    15,180       14,826       14,597       14,294       14,930  
Annual Load Factor (percent)
    61.5       61.0       60.4       61.7       61.6  
Plant Availability (percent):
                                       
Fossil-steam
    90.3       87.6       80.9       88.5       86.1  
Nuclear
    94.8       94.2       88.8       94.4       91.5  
 
Source of Energy Supply (percent):
                                       
Coal
    57.9       58.6       59.5       58.5       62.3  
Nuclear
    17.3       16.8       16.2       18.1       17.4  
Hydro
    1.5       2.1       0.9       1.1       0.7  
Oil and gas
    0.1       0.3       0.3       0.4       1.8  
Purchased power -
                                       
From non-affiliates
    7.0       7.5       6.3       7.8       8.1  
From affiliates
    16.2       14.7       16.8       14.1       9.7  
 
Total
    100.0       100.0       100.0       100.0       100.0  
 

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GULF POWER COMPANY

 
 
 
FINANCIAL SECTION
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

II-176


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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, 2004 and 2003, 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, 2004. 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.

     We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (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 consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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-196 to II-219) present fairly, in all material respects, the financial position of Gulf Power Company at December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004, 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
February 28, 2005

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION

Gulf Power Company 2004 Annual Report

OVERVIEW

Business Activities

Gulf Power Company (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 (PSC).

     Many 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 more stringent environmental standards.

     On September 15 and 16, 2004, Hurricane Ivan hit the Gulf Coast of Florida and Alabama causing substantial damage. Nearly 90% of the Company’s customers were without electric service immediately after the hurricane. Almost 95% of those without power had service restored within one week, and two weeks after the storm, power had been restored to all who could receive service. The hurricane’s financial impact to the Company is provided herein, along with management’s discussion and analysis.

Key Performance Indicators

In striving to maximize shareholder value while providing low-cost energy to nearly 400,000 customers, the Company focuses on several key indicators. These indicators include customer satisfaction, peak season equivalent forced outage rate (Peak Season EFOR), and return on equity (ROE). The Company’s financial success is directly tied to the satisfaction of its customers. Key elements of ensuring satisfaction include outstanding service, high reliability, and competitive prices. Management uses nationally recognized customer satisfaction surveys and reliability indicators to evaluate the Company’s results. Peak Season EFOR is an indicator of plant availability and efficient generation fleet operations during the months when generation needs are greatest. The rate is calculated by dividing the number of hours of forced outages by total generation hours. ROE is a performance standard used by both the investment community and many regulatory agencies. The Company’s 2004 results compared with its targets for each of these indicators are reflected in the following chart.

                         
 
        2004     2004  
  Key Performance Indicator     Target Performance     Actual Performance  
 
Customer Satisfaction
    Top quartile performance
in national and regional
surveys
    Top quartile  
 
Peak Season EFOR
      2.33%         2.64%    
 
ROE
    12.33%       11.83%    
 

     The financial performance achieved in 2004 reflects the focus that management places on these indicators, as well as the commitment shown by the Company’s employees in achieving or exceeding management’s expectations. The Company’s 2004 actual ROE was below the targeted performance level primarily due to an additional discretionary accrual made to the property insurance reserve. The Peak Season EFOR target was not achieved due to outages caused by Hurricane Ivan. See Note 1 to the financial statements under “Provision for Property Damage” for additional information.

Earnings

The Company’s 2004 net income after dividends on preferred stock was $68.2 million, a decrease of $0.8 million from the previous year. In 2003, earnings were $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. The decrease in earnings in 2004 is due primarily to higher operating expenses related to storm damage reserves and employee benefits. The improvement in earnings in 2003 was primarily due 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 was primarily due 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.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

Gulf Power Company 2004 Annual Report

RESULTS OF OPERATIONS

A condensed statement of income follows:

                                 
            Increase (Decrease)  
    Amount     From Prior Year  
    2004     2004     2003     2002  
    (in thousands)  
Operating revenues
  $ 960,131     $ 82,434     $ 57,230     $ 95,264  
 
Fuel
    367,155       50,652       42,643       73,227  
Purchased power
    65,897       15,740       (12,841 )     (43,247 )
Other operation and maintenance
    229,712       19,012       10,625       22,488  
Depreciation and amortization
    82,799       477       5,308       8,796  
Taxes other than income taxes
    69,856       3,741       5,082       5,772  
 
Total operating expenses
    815,419       89,622       50,817       67,036  
 
Operating income
    144,712       (7,188 )     6,413       28,228  
Total other income and (expense)
    (36,577 )     5,219       (706 )     (13,615 )
Income taxes
    39,695       (1,182 )     3,733       5,884  
 
Net Income
    68,440       (787 )     1,974       8,729  
Dividends on Preferred Stock
    217                    
 
Net Income after Dividends on Preferred Stock
  $ 68,223     $ (787 )   $ 1,974     $ 8,729  
 

Revenues

Operating revenues increased in 2004 when compared to 2003 and 2002. The following table summarizes the changes in operating revenues for the past three years:

                         
    2004     2003     2002  
    (in thousands)  
Retail – Prior Year
  $ 699,174     $ 665,836     $ 584,591  
Change in -
                       
Base rates
          22,000       31,200  
Sales growth
    4,896       7,040       16,557  
Weather
    3,313       (6,757 )     9,497  
Fuel and other cost recovery
    29,487       11,055       23,991  
 
Retail—Current Year
    736,870       699,174       665,836  
 
Sales for resale —
                       
Non-affiliates
    73,537       76,767       77,171  
Affiliates
    110,264       63,268       40,391  
 
Total sales for resale
    183,801       140,035       117,562  
Other operating revenues
    39,460       38,488       37,069  
 
Total operating revenues
  $ 960,131     $ 877,697     $ 820,467  
 
Percent change
    9.4 %     7.0 %     13.1 %
 

     Retail revenues increased $37.7 million, or 5.4 percent, in 2004, $33.3 million, or 5.0 percent, in 2003, and $81.2 million, or 13.9 percent, in 2002. The significant factors driving these changes are shown in the table above. See Note 3 to the financial statements under “Retail Regulatory Matters” for additional information on the base rate increase that became effective in May 2002.

     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 Note 1 to the financial statements under “Revenues” and “Environmental Cost Recovery” for additional information.

     Sales for resale were $183.8 million in 2004, an increase of $43.8 million, or 31.3 percent, as compared to 2003, primarily due to increased energy sales to affiliates at a higher unit cost resulting from higher incremental fuel prices. Sales for resale were $140.0 million in 2003, an increase of $22.5 million, or 19.1 percent, as compared to 2002, primarily due to increased energy sales to affiliates reflecting the availability of additional generation

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

Gulf Power Company 2004 Annual Report

following the commercial operation of Plant Smith Unit 3. Sales for resale were $117.6 million in 2002, an increase of $8.1 million, or 7.4 percent, as compared to 2001, primarily due to increased energy sales to affiliates reflecting the commercial operation of Plant Smith Unit 3. Sales to affiliated companies, as well as purchases, vary from year to year depending on demand and the availability and cost of generating resources at each company. These affiliate sales and purchases are made in accordance with the affiliate company interchange agreement, as approved by the Federal Energy Regulatory Commission (FERC). 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 revenues through the Company’s fuel cost recovery clause.

     Sales for resale to non-affiliates are predominantly unit power sales under long-term contracts to other Florida utilities. Revenues from 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. The capacity and energy components under these unit power contracts were as follows:

                         
    2004     2003     2002  
    (in thousands)  
Unit Power —
                       
Capacity
  $ 18,780     $ 18,598     $ 19,898  
Energy
    29,360       30,892       28,560  
 
Total
  $ 48,140     $ 49,490     $ 48,458  
 

     During 2004, the Company entered into agreements with Florida Power & Light (FP&L), Progress Energy Florida, and Flint Electric Membership Corporation to provide capacity beginning in June 2010. The new contracts will extend the sale of the capacity discussed above. See FUTURE EARNINGS POTENTIAL – “Other Matters” herein for additional information.

     Other operating revenues increased $1.0 million, $1.4 million, and $3.3 million in 2004, 2003, and 2002, respectively, primarily due to an increase in franchise fees, which are proportional to changes in revenue. Other operating revenues for 2002 also increased as a result of a $1.7 million settlement related to a purchased power agreement (PPA) and a $0.9 million increase in revenues from the transmission of electricity to others.

Energy Sales

Kilowatt-hour (KWH) sales for 2004 and the percent changes by year were as follows:

                                 
    KWH     Percent Change  
    2004     2004     2003     2002  
    (millions)                          
Residential
    5,215       2.2 %     (0.8 )%     9.1 %
Commercial
    3,695       2.2       1.7       4.0  
Industrial
    2,113       (1.6 )     4.5       1.8  
Other
    23       0.4       4.7        
     
Total retail
    11,046       1.5       1.0       5.9  
Sales for resale
                               
Non-affiliates
    2,257       (9.9 )     16.1       3.1  
Affiliates
    3,125       28.1       41.8       78.4  
     
Total
    16,428       3.8       8.0       10.7  
 

     Residential sales increased 2.2 percent in 2004 due to more favorable weather conditions and customer growth, as compared to 2003. Residential sales decreased 0.8 percent in 2003 primarily due to milder summer weather, as 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. Residential sales are expected to increase just over 2 percent annually over the next five years, given normal weather conditions.

     Commercial sales increased 2.2 percent in 2004, as compared to 2003, primarily due to more favorable weather conditions and customer growth. Commercial sales increased 1.7 percent in 2003, as compared to 2002, primarily due to customer growth, which offset milder summer weather. In 2002, commercial sales increased 4.0 percent primarily due to more extreme weather as compared to 2001. Commercial sales are expected to increase approximately 3 percent annually over the next five years, given normal weather conditions.

     Industrial sales decreased 1.6 percent in 2004, as compared to 2003, primarily due to the short-term outage experienced as a result of Hurricane Ivan in September 2004. 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 are expected to increase approximately 1 percent annually over the next five years.

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     Sales for resale to non-affiliates decreased 9.9 percent in 2004, increased 16.1 percent in 2003, and increased 3.1 percent in 2002 primarily as a result of fluctuations in the fuel cost to produce energy sold to Florida utilities under long-term contracts and energy sold to other non-affiliated utilities under short-term contracts. The degree to which oil and natural gas prices, which are the primary fuel sources for these customers, differ from the Company’s fuel costs will influence these changes in sales. However, these fluctuations in energy sales under long-term contracts have a minimal effect on earnings because the energy is generally sold at marginal cost.

Expenses

Total operating expenses increased $89.6 million, or 12.3 percent, in 2004, and $50.8 million, or 7.5 percent, in 2003 over the amount recorded in the prior year primarily due to higher fuel and operation and maintenance expenses. In 2002, total operating expenses increased $67.0 million, or 11 percent, compared to 2001 primarily due to higher fuel and maintenance costs.

     In 2004, other operation and maintenance expenses increased $19.0 million, or 9.0 percent, primarily due to increases of $7.9 million in the accumulated provision for property damage, $2.9 million in the accrued expenses for uninsured litigation and workers compensation claims, $3.4 million for employee benefit expenses, and $2.5 million for production expenses. See Notes 1 and 3 to the financial statements under “Provision for Property Damage” and “Retail Regulatory Matters,” respectively, for additional information. In 2003, other operation and maintenance expenses increased $10.6 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. In 2002, other operation and maintenance expenses increased $22.5 million, or 12.7 percent, mainly due to scheduled generating plant maintenance.

     Depreciation and amortization expense remained flat in 2004 due to no significant change in depreciable assets. Depreciation and amortization expense increased $5.3 million, or 6.9 percent, and $8.8 million, or 12.9 percent, in 2003 and 2002, respectively, primarily due to the commercial operation of Plant Smith Unit 3 beginning in April 2002. The 2003 increase also reflects the amortization of a regulatory asset related to corporate facilities, in accordance with an order from the Florida PSC.

Fuel and Purchased Power Expenses

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. Fuel expense increased $50.7 million, or 16.0 percent, in 2004 and $42.6 million, or 15.6 percent, in 2003, compared to the prior year primarily due to increased generation to meet the demand for energy and higher average costs of fuel. Fuel expense in 2002, compared to 2001, increased $73.2 million, or 36.5 percent, primarily due to the commercial operation of Plant Smith Unit 3 beginning in April 2002.

     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:

                         
    2004     2003     2002  
     
Total generation (millions of kilowatt-hours)
    15,841       14,988       13,142  
Sources of generation (percent)
                       
Coal
    84       87       82  
Gas
    16       13       18  
Average cost of fuel per net kilowatt-hour generated (cents)
    2.32       2.11       2.08  
Average cost of purchased power per net kilowatt-hour (cents)
    4.97       3.29       2.79  
 

     Purchased power expense in 2004 increased $15.7 million, or 31.4 percent, as compared to 2003, primarily due to increased power purchases from merchant generation resources to minimize total system production cost. Purchased power expense decreased in 2003 by $12.8 million, or 20.4 percent, as compared to 2002, 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, as compared to 2001, primarily due to the additional generating capacity from the Company’s Plant Smith Unit 3.

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     A significant upward trend in the cost of coal and natural gas has emerged since 2003, and volatility in these markets is expected to continue. Increased coal prices have been influenced by a worldwide increase in demand as a result of rapid economic growth in China as well as by increases in mining costs. Higher natural gas prices in the United States are the result of slightly lower gas supplies despite increased drilling activity. Natural gas supply interruptions, such as those caused by the 2004 hurricanes, result in an immediate market response, however, the impact of this price volatility may be reduced by imports of natural gas and liquefied natural gas.

     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.

Other Income and (Expense)

The equity portion of the allowance for funds used during construction (AFUDC) increased $1.1 million in 2004 primarily due to ongoing construction activities related to the installation of pollution control equipment at Plant Crist. AFUDC 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 in April 2002. See FUTURE EARNINGS POTENTIAL – “Environmental Matters — Environmental Statutes and Regulations” herein and Note 1 to the financial statements under “AFUDC” for additional information.

     Interest expense decreased $2.1 million, or 5.5 percent, in 2004 and $1.8 million, or 4.6 percent, in 2003 primarily as the result of refinancing higher cost securities. Interest expense increased $8.5 million, or 26.9 percent, in 2002 primarily due to the issuance of $180 million of senior notes in 2001 and 2002 that were used to finance the construction of Plant Smith Unit 3.

Effects of Inflation

The Company is subject to rate regulation based on the recovery of historical costs. In addition, the income tax laws are based on historical costs. Therefore, inflation creates an economic loss because the Company is recovering its cost of investments in dollars that have less purchasing power. While the inflation rate has been relatively low in recent years, it continues to have an adverse effect on the Company because of the large investment in utility plant with long economic lives. Conventional accounting for historical cost does not recognize this economic loss nor the partially offsetting gain that arises through financing facilities with fixed-money obligations, such as long-term debt and preferred securities. Any recognition of inflation by regulatory authorities is reflected in the rate of return allowed in the Company’s approved electric rates.

FUTURE EARNINGS POTENTIAL

General

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 PSC 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 FERC. See ACCOUNTING POLICIES – “Application of Critical Accounting Policies and Estimates – Electric Utility Regulation” herein and Note 3 to the financial statements for additional information about these and other regulatory matters.

     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 more stringent 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.

     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

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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.

Environmental Matters

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 and Georgia Power. The complaint alleged violations of the New Source Review (NSR) provisions of the Clean Air Act and related state laws at 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. See Note 4 to the financial statements 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. 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.

     The Company believes that it has complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $32,500 per day, per violation at each generating unit, depending on the date of the alleged violation. 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.

     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 (RMRR) exclusion. A coalition of states and environmental organizations has filed petitions for review of these revisions with the U.S. Court of Appeals for the District of Columbia Circuit. The October 2003 RMRR rules have been stayed by the Court of Appeals pending its review of the rules. In any event, the final regulations must be adopted by the individual states within the Company’s service territory in order to apply to the Company’s facilities. The effect of these final regulations, related legal challenges, and potential state rulemaking cannot be determined at this time.

Carbon Dioxide Litigation

On July 21, 2004, attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel for New York City filed a complaint in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. A nearly identical complaint was filed by three environmental groups in the same court. The complaints allege that the companies’ emissions of carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs assert is a public nuisance. Under common law public and private nuisance theories, the plaintiffs seek a judicial order (1) holding each defendant jointly and severally liable for creating, contributing to, and/or maintaining global warming and (2) requiring each of the defendants to cap its emissions of carbon dioxide and then reduce those emissions by a specified percentage each year for at least a decade. Plaintiffs have not, however, requested that damages be awarded in connection with their claims. Southern Company believes these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. Southern Company and the other defendants have filed motions to dismiss both lawsuits. Southern Company intends to vigorously defend against these claims. While the outcome of these matters cannot be determined at this time, an adverse judgment in either of these actions could result in substantial capital expenditures.

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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 involves 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 discussed under FINANCIAL CONDITION AND LIQUIDITY – “Capital Requirements and Contractual Obligations” herein. The Florida Legislature has adopted legislation that allows a utility to petition the Florida PSC 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 Remediation.” 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 (ECRC). There is no assurance, however, that all such costs will, in fact, be recovered.

     Compliance with the 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 (NOx) emissions and resulted in total construction expenditures of approximately $42 million through 2000.

     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 and included development of an eight-hour ozone standard, as opposed to the one-hour ozone standard previously established by the EPA. 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. On April 30, 2004, the EPA published its eight-hour ozone nonattainment designations and a portion of the rules implementing the new eight-hour ozone standard. Based on recommendations from the State of Florida, the EPA designated the entire State of Florida as in attainment for the eight-hour ozone standard. The Company is, however, a partial owner of a plant in Georgia that is located in an area determined by the EPA to be in nonattainment for the standard. State implementation plans, including new emission control regulations necessary to bring nonattainment areas into attainment, could be required as early as 2007. These state implementation plans could require reductions in NOx emissions from power plants. The impact of the eight-hour designations and the new standard will depend on the development and implementation of applicable state implementation plans and therefore cannot be determined at this time.

     On December 17, 2004, the EPA issued its final “nonattainment” designations for the fine particulate national ambient air quality standard. The Company is a partial owner of a plant in Georgia that is located in an area included in the EPA’s final particulate matter designations. The EPA plans to propose a fine particulate matter implementation rule in 2005 and finalize the implementation rule in 2006. State implementation plans addressing the nonattainment designations may be required by 2008 and could require reductions in sulfur dioxide emissions and further reductions in NOx emissions from power plants. The impact of the fine particulate designations will depend on the development and implementation of applicable state implementation plans and therefore cannot be determined at this time.

     In August 2002, the Company entered into an agreement with the Florida Department of Environmental Protection (FDEP) calling for NOx emission reductions at Plant Crist to help ensure attainment of the new standards in the Pensacola area. Under the agreement, the Company will install selective catalytic reduction controls and a new precipitator on Plant Crist Unit 7 during 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 $138 million, of which $43.6 million remains to be spent. Costs for implementation of the agreement have been approved for recovery through the ECRC. See Note 1 to the financial statements under “Environmental Cost Recovery” for additional information.

     In January 2004, the EPA issued a proposed Clean Air Interstate Rule (CAIR) to address interstate transport of ozone and fine particles. This proposed rule would require additional year-round sulfur dioxide and NOx emission reductions from power plants in the eastern United States in two phases – in 2010 and 2015. The EPA

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currently plans to finalize this rule in 2005. If finalized, the rule could modify or supplant other state requirements for attainment of the fine particulate matter standard and the eight-hour ozone standard, as well as other air quality regulations. 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.

     The Company has developed and maintains an environmental compliance strategy for the installation of additional control technologies and the purchase of emission allowances to assure continued compliance with current sulfur dioxide and NOx emission regulations. Additional expenses associated with these regulations are anticipated to be incurred each year to maintain current and future compliance. Because the Company’s compliance strategy is impacted by factors such as changes to existing environmental laws and regulations, increases in the cost of emissions allowances, and any changes in the Company’s fuel mix, future environmental compliance costs cannot be determined at this time.

     Further reductions in sulfur dioxide and NOx 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 and to implement emission reduction requirements that make progress toward remedying current visibility impairment in certain natural areas. 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 implementation plans in 2008 that contain emission reduction strategies for implementing BART and for achieving sufficient progress toward the Clean Air Act’s visibility improvement goal. In response to litigation, the EPA proposed revised rules in May 2004, which it plans to finalize in April 2005. The impact of these regulations will depend on the promulgation of final rules and implementation of those rules by the states and, therefore, 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. This will begin taking place in 2005 for the Company’s affected units. Field testing information collected in 2002, 2003, and 2004 was used to develop CAM protocols which were successfully adopted into the Title V permit renewals at all affected Company plants.

     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 March 2005, and compliance could be required as early as 2008. Because the regulations have not been finalized, the impact on the Company cannot be determined at this time.

     Major bills to amend the Clean Air Act to impose more stringent emissions limitations on power plants, including the Bush Administration’s Clear Skies Act, have been re-proposed in 2005. The Clear Skies Act is expected to further limit power plant emissions of sulfur dioxide, NOx, and mercury and to supplement the proposed CAIR and mercury regulatory programs. Other proposals to limit emissions of carbon dioxide have also been introduced. The cost impacts of such legislation would depend upon the specific requirements enacted and cannot be determined at this time.

     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. In July 2004, the EPA published final rules that 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 and the actual limits established by the regulatory agencies.

     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, 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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The full impact of any such changes cannot, however, be determined at this time.

Global Climate Issues

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 constraints on the emissions of greenhouse gases for a group of industrialized countries. The Bush Administration has not supported U.S. ratification of the Kyoto Protocol or other mandatory carbon dioxide reduction legislation and, in 2002, announced a goal to reduce the greenhouse gas intensity of the U.S. – the ratio of greenhouse gas emissions to the value of U.S. economic output — by 18 percent by 2012. A year later, the Department of Energy (DOE) announced the Climate VISION program to support this goal. Energy-intensive industries, including electricity generation, are the initial focus of this program. Southern Company is leading the development of a voluntary electric utility sector climate change initiative in partnership with the government. The utility sector has pledged to reduce its greenhouse gas emissions rate by 3 to 5 percent over the next decade and, on December 13, 2004, signed a memorandum of understanding with the DOE initiating this program under Climate VISION. Because efforts under this voluntary program are just beginning, the impact of this program on the Company cannot be determined at this time.

Environmental Remediation Reserves

The Company must comply with 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 may incur substantial costs to remediate properties. The Company conducts studies to determine the extent of any required remediation and has recognized in the financial statements costs to remediate known sites. During the third quarter 2004, the Company increased its estimated liability for the estimated costs of environmental remediation projects by approximately $47 million. This increase relates to new regulations and more stringent site closure criteria by the FDEP for impacts to soil and groundwater from herbicide applications at certain substation sites. Because FDEP approval is required prior to the issuance of site closure, a timeframe for the completion of the remediation projects cannot be determined. The projects have been approved by the Florida PSC for recovery, as expended, through the Company’s ECRC; therefore, there was no impact on the Company’s net income as a result of these revised estimates. Amounts for actual cleanup and ongoing monitoring costs were not material for any year presented. The Company may be liable for some or all required remediation costs for additional sites that may require environmental remediation. See Note 3 to the financial statements under “Environmental Remediation” for additional information.

FERC and Florida PSC Matters

Transmission

In December 1999, the FERC issued its final rule on Regional Transmission Organizations (RTOs). Since that time, there have been a number of additional proceedings at the FERC designed to encourage further voluntary formation of RTOs or to mandate their formation. However, at the current time, there are no active proceedings that would require the Company to participate in an RTO. Current FERC efforts that may potentially change the regulatory and/or operational structure of transmission include rules related to the standardization of generation interconnection, as well as an inquiry into, among other things, market power by vertically integrated utilities. See “Generation Interconnection Agreements” and “Market-Based Rate Authority” herein for additional information. The final outcome of these proceedings cannot now be determined. However, the Company’s financial condition, results of operations, and cash flows could be adversely affected by future changes in the federal regulatory or operational structure of transmission.

Generation Interconnection Agreements

In July 2003, the FERC issued its final rule on the standardization of generation interconnection agreements and procedures (Order 2003). Order 2003 shifts much of the financial burden of new transmission investment from the generator to the transmission provider. The FERC has indicated that Order 2003, which was effective January 20, 2004, is to be applied prospectively to interconnection agreements. Subsidiaries of Tenaska, Inc., as counterparties to three previously executed interconnection agreements with other subsidiaries of Southern Company, have filed complaints at the FERC requesting that the FERC modify the agreements and that Southern Company refund amounts previously paid for interconnection facilities, with interest. The Company has received

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similar requests from other entities totaling $6.6 million. The Company has opposed such relief, and these matters are still outstanding. The impact of Order 2003 and its subsequent rehearings on the Company and the final results of these matters cannot be determined at this time.

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, the retail operating companies, and Southern Power, and found Southern Company and others to be “pivotal suppliers” in their retail service territories 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. In April 2004, the FERC issued an order that abandoned the SMA test and adopted a new interim analysis for measuring generation market power. This new interim approach requires utilities to submit a pivotal supplier screen and a wholesale market share screen. If the applicant does not pass both screens, there will be a rebuttable presumption regarding generation market power. The FERC’s order also sets forth procedures for rebutting these presumptions and addresses mitigation measures for those entities that are found to have market power. In the absence of specific mitigation measures, the order includes several cost-based mitigation measures that would apply by default. The FERC also initiated a new rulemaking proceeding that, among other things, will adopt a final methodology for assessing generation market power.

     In July 2004, the FERC denied Southern Company’s request for rehearing, along with a number of others, and reaffirmed the interim tests that it adopted in April 2004. In August 2004, Southern Company submitted a filing to the FERC that included results showing that Southern Company passed the pivotal supplier screen for all markets and the wholesale market share screen for all markets except the Southern Company retail service territory. Southern Company also submitted other analyses to demonstrate that it lacks generation market power. On December 17, 2004, the FERC initiated a proceeding to assess Southern Company’s generation dominance within its retail service territory. The ability to charge market-based rates in other markets is not at issue. As directed by this order, on February 15, 2005, Southern Company submitted additional information related to generation dominance in its retail service territory. Any new market-based rate transactions in the Southern Company retail service territory entered into after February 27, 2005 will be subject to refund to the level of the default cost-based rates, pending the outcome of the proceeding. Southern Company, along with other utilities, has also filed an appeal of the FERC’s April and July 2004 orders with the U.S. Court of Appeals for the District of Columbia Circuit. The FERC has asked the court to dismiss the appeal on the grounds that it is premature.

     In the event that the FERC’s default mitigation measures are ultimately applied, the Company may be required to charge cost-based rates for certain wholesale sales in the Southern Company retail service territory, which may be lower than negotiated market-based rates. The final outcome of this matter will depend on the form in which the final methodology for assessing generation market power and mitigation rules may be ultimately adopted and cannot be determined at this time.

Florida PSC and FDEP Report on Renewable Energy

The Florida PSC, 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 Florida PSC and the FDEP in January 2003. This report describes various renewable and green energy options. The report provided the Florida PSC, 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 Florida Legislature and policymakers a sound starting point if they consider new legislation in this area. While the Company is actively pursuing a renewable energy portfolio that may be incorporated into its offering to its customers, the pursuit of a mandatory renewable portfolio standard or 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.

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Retail Fuel Cost Recovery

The Company has established fuel cost recovery rates approved by the Florida PSC. The Company experienced higher than projected fuel costs for coal and natural gas which increased the under recovered fuel costs included in the balance sheet in 2003. At December 31, 2004, the under recovered amount was $7.9 million, a decrease of $12.4 million, or 61 percent, when compared to 2003, primarily due to more sales for resale which reduced the net amount of fuel expense to be recovered from retail customers. 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.

Storm Damage Cost Recovery

On September 15 and 16, 2004, Hurricane Ivan hit the Gulf Coast of Florida and Alabama causing substantial damage. Nearly 90% of the Company’s customers were without electric service immediately after the hurricane. Almost 95% of those without power had service restored within one week, and two weeks after the storm, power had been restored to all who could receive service.

     Under authority granted by the Florida PSC, the Company maintains a reserve for property damage to cover the cost of damages from major storms to its transmission and distribution lines and the cost of uninsured damages to its generation facilities and other property. Prior to Hurricane Ivan, the Company’s reserve balance was approximately $27.8 million. The Company’s estimated total cost of Hurricane Ivan is $141.5 million. Of this amount, approximately $17.2 million is covered by insurance. As a result, the accumulated reserve had a deficit balance of approximately $96.5 million to be addressed through future accruals to the reserve or other alternative recovery mechanisms. The Company’s current annual accrual to the property damage reserve, as approved by the Florida PSC, is $3.5 million. The Florida PSC has also authorized the Company to make additional accruals at the Company’s discretion.

     On February 2, 2005, the Citizens of the State of Florida through the Office of Public Counsel, the Florida Industrial Power Users Group, and the Company filed a Stipulation and Settlement with the Florida PSC to resolve all matters regarding the effects of Hurricane Ivan on the Company’s reserve for property damage (Stipulation).

     Under the terms of the Stipulation, the Company will recover the retail portion of $51.7 million of Hurricane Ivan storm damage costs, plus interest and revenue taxes, through a monthly surcharge applied to retail customer bills for a 24-month period. For purposes of the Stipulation, such recovery amount excludes $44.8 million from the amount to be recovered, including $26.4 million in capital that will be included in retail rate base, and a $15 million discretionary accrual to the reserve recorded by the Company in 2004 pursuant to the agreement between the parties reached in the Stipulation.

     Except under circumstances provided for within the Stipulation, the Company has agreed that it will not seek any additional increase in its base rates and charges to become effective on or before March 1, 2007. The Stipulation is subject to the approval of the Florida PSC, which is expected to rule on the Stipulation at its next meeting in March 2005. The ultimate outcome of this matter cannot now be determined. See Notes 1 and 3 to the financial statements under “Provision for Property Damage” and “Retail Regulatory Matters,” respectively, for additional information.

Income Tax Matters

American Jobs Creation Act of 2004

On October 22, 2004, President Bush signed the American Jobs Creation Act of 2004 (Jobs Act) into law. The Jobs Act includes a provision that allows a generation tax deduction for utilities. The Company is currently assessing the impact of the Jobs Act, including this deduction, as well as the related regulatory treatment, on its taxable income. However, the Company currently does not expect the Jobs Act to have a material impact on its financial statements.

Other Matters

On August 12, 2004, Georgia Power and the Company entered into a PPA with FP&L. Under the agreement, Georgia Power and the Company will provide FP&L with 165 megawatts of capacity annually from the jointly owned Plant Scherer Unit 3 for the period from June 2010 through December 2015. The contract provides for fixed capacity payments and variable energy payments based on actual energy delivered. The Florida PSC approved the

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contract on January 24, 2005; however, it is still contingent on certain events.

     On November 29, 2004, Georgia Power and the Company entered into a PPA with Progress Energy Florida. Under the PPA, Georgia Power and the Company will provide Progress Energy with 74 megawatts of capacity annually from the jointly owned Plant Scherer Unit 3 for the period from June 2010 through December 2015. The contract provides for fixed capacity payments and variable energy payments based on actual energy delivered. The contract is contingent upon certain events, including approval of the Florida PSC. A hearing has been scheduled for March 2005. The final outcome of this matter cannot now be determined.

     Also in 2004, Georgia Power and the Company entered into a PPA with Flint Electric Membership Corporation. Under the agreement, Georgia Power and the Company will provide Flint Electric Membership Corporation with 75 megawatts of capacity annually from the jointly owned Plant Scherer Unit 3 for the period from June 2010 through December 2019. The contract provides for fixed capacity payments and variable energy payments based on actual energy delivered.

     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 $2.5 million, $4.9 million, and $5.6 million in 2004, 2003, and 2002, respectively. Future pension income is dependent on several factors including trust earnings and changes to the pension 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 $5.1 million, $4.9 million, and $4.5 million in 2004, 2003, and 2002, 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 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.

     The Company is involved in various other 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. Southern Company 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.

Electric Utility Regulation

The Company is subject to retail regulation by the Florida 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, which requires the financial statements to reflect the effects of rate 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 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, 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,

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adverse legislative, 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 herein 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:

•   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.

•   Changes in existing income tax regulations or changes in Internal Revenue Service interpretations of existing regulations.

•   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.

•   Identification and evaluation of other potential lawsuits or complaints in which the Company may be named as a defendant.

•   Resolution or progression of existing matters through the legislative process, the court systems, or the EPA.

Unbilled Revenues

Revenues related to the sale of electricity are recorded when electricity is delivered to customers. However, the determination of KWH sales to individual customers is based on the reading of their meters, which is performed on a systematic basis through the month. At the end of each month, amounts of electricity delivered to customers, but not yet metered and billed, are estimated. Components of the unbilled revenue estimates include total KWH territorial supply, total KWH billed, estimated total electricity lost in delivery, and customer usage. These components can fluctuate as a result of a number of factors including weather, generation patterns, power delivery volume, and other operational constraints. These factors can be unpredictable and can vary from historical trends. As a result, the overall estimate of unbilled revenues could be significantly affected, which could have a material impact on the Company’s results of operations.

New Accounting Standards

On March 31, 2004, the Company prospectively adopted FASB Interpretation No. 46R, Consolidation of Variable Interest Entities, which requires the primary beneficiary of a variable interest entity to consolidate the related assets and liabilities. The adoption of FASB Interpretation No. 46R had no impact on the Company’s net income. However, as a result of the adoption, the Company deconsolidated certain wholly-owned trusts established to issue preferred securities since the Company does not meet the definition of primary beneficiary established by FASB Interpretation No. 46R. See Note 1 to the financial statements under “Variable Interest Entities” for additional information.

     In the third quarter 2004, the Company prospectively adopted FASB Staff Position (FSP) 106-2, Accounting and Disclosure Requirements related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (Medicare Act). The Medicare Act provides a 28 percent prescription drug subsidy for Medicare eligible retirees. FSP 106-2 requires recognition of the impacts of the Medicare Act in the accumulated postretirement benefit obligation (APBO) and future cost of service for postretirement medical plans. The effect of the subsidy reduced the Company’s expenses for the six months ended December 31, 2004 by approximately $0.5 million and is expected to have a similar impact on future years. The subsidy’s impact on the postretirement medical plan APBO was a reduction of approximately $8.0 million. However, the ultimate impact on future periods is subject to final interpretation of the federal regulations which were published on January 21, 2005. See Note 2 to the financial statements under “Postretirement Benefits” for additional information.

     FASB Statement No. 123R, Share-Based Payment was issued in December 2004. This statement requires

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that compensation cost relating to share-based payment transactions be recognized in financial statements. That cost will be measured based on the grant date fair value of the equity or liability instruments issued. For the Company, this statement is effective beginning on July 1, 2005. Although the compensation expense required under the revised statement differs slightly, the impacts on the financial statements are expected to be similar to the pro forma disclosures included in Note 1 to the financial statements under “Stock Options.”

     See FUTURE EARNINGS POTENTIAL – “Income Tax Matters — American Jobs Creation Act of 2004” herein for information regarding the adoption of new tax legislation. In December 2004, the FASB issued FSP 109-1, Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004, which requires that the generation deduction be accounted for as a special tax deduction rather than as a tax rate reduction. The Company is currently assessing the Jobs Act and this pronouncement, as well as the related regulatory treatment, but currently does not expect a material impact on the Company’s financial statements.

FINANCIAL CONDITION AND LIQUIDITY

Overview

The Company’s financial condition continued to be strong at December 31, 2004. Net cash flow from operating activities totaled $143.2 million, $191.2 million, and $135.9 million for 2004, 2003, and 2002, respectively. The majority of the decrease from 2003 to 2004 is due to payments related to storm damage from Hurricane Ivan. The increase from 2002 to 2003 is primarily due to an increase in prepayments, reduced accounts receivable from customers and the recovery of additional fuel costs. Gross property additions were $161.2 million in 2004. 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.

     Significant balance sheet changes include the $50 million increase in securities due within one year due to bank notes issued to temporarily finance costs associated with Hurricane Ivan restoration.

     The Company’s ratio of common equity to total capitalization — including short-term debt — was 43.2 percent in 2004, 45.3 percent in 2003, and 44.0 percent in 2002. See Note 6 to the financial statements for additional information.

     The Company has received investment grade ratings from the major rating agencies.

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 flows and the issuance of unsecured debt and preferred securities, as well as 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 in order 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 that the Company will be permitted to issue in the future will depend upon market conditions and other factors prevailing at that time.

     The issuance of securities, including financing associated with the issuance of pollution control bonds, is subject to regulatory approval by the Securities and Exchange Commission (SEC) under the Public Utility Holding Company Act of 1935 as amended (PUHCA), and the Florida PSC pursuant to its rules and regulations. In recent years, financings primarily have utilized unsecured debt and preferred securities. Additionally, with respect to the public offering of securities, the Company must file registration statements with the SEC under the Securities Act of 1933, as amended (1933 Act). The amounts of securities authorized by the appropriate regulatory authorities, as well as the amounts registered under the 1933 Act, are continuously monitored and appropriate filings are made to ensure flexibility in the capital markets.

     The Company obtains financing separately without credit support from any affiliate. The Southern Company system does not maintain a centralized cash or money

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pool. Therefore, funds of the Company are not commingled with funds of any other company. In accordance with PUHCA, most loans between affiliated companies must be approved in advance by the SEC.

     The Company’s current liabilities exceed current assets due to the scheduled maturity of $100 million in bank notes issued to temporarily finance costs associated with Hurricane Ivan repairs. See “Financing Activities” herein for additional information.

     To meet short-term cash needs and contingencies, the Company has various internal and external sources of liquidity. At the beginning of 2005, the Company had approximately $64.8 million of cash and cash equivalents, along with $56.3 million of unused committed lines of credit with banks to meet its short-term cash needs. These bank credit arrangements will expire during 2005. The Company plans to renew these lines of credit during 2005. In addition, the Company has substantial cash flow from operating activities. 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, 2004, the Company had no commercial paper or extendible commercial notes outstanding.

Financing Activities

During 2004, the Company issued $110 million of senior notes. The issuances were used to refund $75 million of senior notes and to pay at maturity $50 million of senior notes due August 15, 2004. In addition, on October 27, 2004, the Company issued $100 million of bank notes due October 28, 2005. This issuance was used to temporarily finance costs associated with Hurricane Ivan repairs. See FUTURE EARNINGS POTENTIAL – “Storm Damage Cost Recovery” herein for additional information.

     Composite financing rates for long-term debt have decreased from 5.34 percent in 2002, to 4.60 percent in 2003, and 4.18 percent in 2004.

Credit Rating Risk

The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- or Baa3, or below. Generally, collateral may be provided for by a Southern Company guaranty, letter of credit, or cash. These contracts are primarily for physical electricity purchases and sales. At December 31, 2004, the maximum potential collateral requirements at a BBB- or Baa3 rating were approximately $5 million. The maximum potential collateral requirements at a rating below BBB- or Baa3 were approximately $10 million. The Company is also party to certain derivative agreements that could require collateral and/or accelerated payment in the event of a credit rating change to below investment grade. These agreements are primarily for natural gas price and interest rate risk management activities. At December 31, 2004, the Company had no material exposure related to these agreements.

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 risk management practices. Company policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including but not limited to market valuation, value at risk, stress testing, and sensitivity analysis.

     The weighted average interest rate on $144.6 million variable long-term debt that has not been hedged at January 1, 2005 was 1.97 percent. If the Company sustained a 100 basis point change in interest rates for all variable rate long-term debt, the change would affect annualized interest expense by approximately $1.4 million

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at January 1, 2005. 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.

     The changes in fair value of energy-related derivative contracts and year-end valuations were as follows at December 31:

                 
    Changes in Fair Value  
    2004     2003  
    (in thousands)  
Contracts beginning of year
  $ 2,503     $ 2,336  
Contracts realized or settled
    (8,409 )     (5,098 )
New contracts at inception
           
Changes in valuation techniques
           
Current period changes (a)
    6,223       5,265  
 
Contracts end of year
  $ 317     $ 2,503  
 


(a)   Current period changes also include the changes in fair value of new contracts entered into during the period.
                         
    Source of 2004 Year-End  
    Valuation Prices  
    Total     Maturity  
    Fair Value     2005     2006-2007  
    (in thousands)  
 
Actively quoted
  $310       $(17 )   $327  
External sources
    7       7        
Models and other methods
                 
 
Contracts end of Year
    $317       $(10 )     $327  
 

     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 statements of income as incurred. At December 31, 2004, the fair value of derivative energy contracts was reflected in the financial statements as follows:

         
    Amounts  
    (in thousands)  
Regulatory liabilities, net
  $309  
Other comprehensive income
     
Net income
    8  
 
Total fair value
    $317  
 

     Unrealized gains (losses) recognized in income were not material in any year presented. 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. See Notes 1 and 6 to the financial statements under “Financial Instruments” for additional information.

Capital Requirements and Contractual Obligations

The construction program of the Company is currently estimated to be $154 million in 2005, $112 million in 2006, and $103 million in 2007. These amounts include $40 million and $4 million in 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 Florida PSC authorized the Company to recover the costs related to these environmental projects through the ECRC. The construction program also includes $15 million in 2005, $9 million in 2006, and $23 million in 2007 for other environmental expenditures. 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 2007. 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.

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     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 FERC.

     Other funding requirements related to obligations associated with scheduled maturities of long-term debt and preferred securities, as well as the related interest, preferred stock dividends, leases, and other purchase commitments are as follows. See Notes 1, 6, and 7 to the financial statements for additional information.

                                         
            2006-     2008-     After        
Contractual Obligations   2005     2007     2009     2009     Total  
    (in thousands)  
Long-term debt(a)
                                       
Principal
  $ 100,000     $ 37,075     $     $ 594,721     $ 731,796  
Interest
    32,169       57,359       55,100       567,003       711,631  
Preferred stock dividends(b)
    217       434       434             1,085  
Operating leases
    2,481       4,844       4,136       6,238       17,699  
Purchase commitments(c)
                                       
Capital(d)
    153,630       215,340                   368,970  
Coal
    196,159       228,610                   424,769  
Natural gas(e)
    95,604       129,151       37,772       240,269       502,796  
Purchased power
    311                         311  
Long-term service agreements
    5,925       13,623       15,009       46,677       81,234  
Postretirement benefit trusts(f)
    70       140                   210  
 
Total
  $ 586,566     $ 686,576     $ 112,451     $ 1,454,908     $ 2,840,501  
 


(a)   All amounts are reflected based on final maturity dates. The Company plans to 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, 2005, 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 $230 million, $211 million, and $200 million, respectively.
 
(d)   The Company forecasts capital expenditures over a three-year period. Amounts represent current estimates of total expenditures. At December 31, 2004, 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 Exchange future prices at December 31, 2004.
 
(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 and postretirement plans, including estimated benefit payments. Certain benefit payments will be made through the related trusts. Other benefit payments will be made from the Company’s corporate assets.

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Cautionary Statement Regarding Forward-Looking Statements

The Company’s 2004 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning the strategic goals for the Company’s retail sales growth, environmental regulations and expenditures, storm damage cost recovery, the Company’s projections for postretirement benefit trust contributions, and estimated construction and other expenditures. 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 similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:

•   the impact of recent and future federal and state regulatory change, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, and also changes in environmental, tax and other laws and regulations to which the Company is subject, as well as changes in application of existing laws and regulations;

•   current and future litigation, regulatory investigations, proceedings or inquiries actions against the Company;

•   the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates;

•   variations in demand for electricity and gas, including those relating to weather, the general economy and population and business growth (and declines);

•   available sources and costs of fuels;

•   ability to control costs;

•   investment performance of the Company’s employee benefit plans;

•   advances in technology;

•   state and federal rate regulations and the impact of pending and future rate cases and negotiations;

•   internal restructuring or other restructuring options that may be pursued;

•   potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to the Company;

•   the ability of counterparties of the Company to make payments as and when due;

•   the ability to obtain new short- and long-term contracts with neighboring utilities;

•   the direct or indirect effect on the Company’s business resulting from terrorist incidents and the threat of terrorist incidents;

•   interest rate fluctuations and financial market conditions and the results of financing efforts, including the Company’s credit ratings;

•   the ability of the Company to obtain additional generating capacity at competitive prices;

•   catastrophic events such as fires, earthquakes, explosions, floods, hurricanes or other similar occurrences;

•   the direct or indirect effects on the Company’s business resulting from incidents similar to the August 2003 power outage in the Northeast;

•   the effect of accounting pronouncements issued periodically by standard setting bodies; and

•   other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed by the Company from time to time with the SEC.

The Company expressly disclaims any obligation to update any forward-looking statements.

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STATEMENTS OF INCOME
For the Years Ended December 31, 2004, 2003, and 2002
Gulf Power Company 2004 Annual Report

                         
 
    2004     2003     2002  
    (in thousands)  
Operating Revenues:
                       
Retail sales
  $ 736,870     $ 699,174     $ 665,836  
Sales for resale —
                       
Non-affiliates
    73,537       76,767       77,171  
Affiliates
    110,264       63,268       40,391  
Other revenues
    39,460       38,488       37,069  
 
Total operating revenues
    960,131       877,697       820,467  
 
Operating Expenses:
                       
Fuel
    367,155       316,503       273,860  
Purchased power —
                       
Non-affiliates
    30,720       17,137       23,797  
Affiliates
    35,177       33,020       39,201  
Other operations
    160,635       140,166       124,654  
Maintenance
    69,077       70,534       75,421  
Depreciation and amortization
    82,799       82,322       77,014  
Taxes other than income taxes
    69,856       66,115       61,033  
 
Total operating expenses
    815,419       725,797       674,980  
 
Operating Income
    144,712       151,900       145,487  
Other Income and (Expense):
                       
Allowance for equity funds used during construction
    1,855       712       2,980  
Interest income
    1,224       888       572  
Interest expense, net of amounts capitalized
    (31,482 )     (31,069 )     (31,452 )
Interest expense to affiliate trusts
    (3,443 )            
Distributions on mandatorily redeemable preferred securities
    (1,113 )     (7,085 )     (8,524 )
Other income (expense), net
    (3,618 )     (5,242 )     (4,666 )
 
Total other income and (expense)
    (36,577 )     (41,796 )     (41,090 )
 
Earnings Before Income Taxes
    108,135       110,104       104,397  
Income taxes
    39,695       40,877       37,144  
 
Net Income
    68,440       69,227       67,253  
Dividends on Preferred Stock
    217       217       217  
 
Net Income After Dividends on Preferred Stock
  $ 68,223     $ 69,010     $ 67,036  
 

The accompanying notes are an integral part of these financial statements.

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STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2004, 2003, and 2002
Gulf Power Company 2004 Annual Report
                         
   
    2004     2003     2002  
   
    (in thousands)  
 
Operating Activities:
                       
Net income
  $ 68,440     $ 69,227     $ 67,253  
Adjustments to reconcile net income to net cash provided from operating activities —
                       
Depreciation and amortization
    88,772       87,949       82,230  
Deferred income taxes
    46,255       2,303       9,619  
Pension, postretirement, and other employee benefits
    (895 )     (717 )     (8,170 )
Tax benefit of stock options
    3,063       1,768       1,043  
Hedge settlements
          (3,266 )      
Other, net
    10,101       6,828       5,756  
Changes in certain current assets and liabilities —
                       
Receivables, net
    1,741       8,223       (25,954 )
Fossil fuel stock
    2,355       1,837       10,464  
Materials and supplies
    (831 )     (1,091 )     (5,982 )
Other current assets
    (29,622 )     12,207       (14,178 )
Accounts payable
    (51,876 )     (1,208 )     20,235  
Accrued taxes
    629       (549 )     1,117  
Accrued compensation
    1,946       104       (1,067 )
Other current liabilities
    3,111       7,576       (6,470 )
 
Net cash provided from operating activities
    143,189       191,191       135,896  
 
Investing Activities:
                       
Gross property additions
    (161,205 )     (99,284 )     (106,624 )
Cost of removal net of salvage
    (10,259 )     (7,881 )     (7,978 )
Other
    36,391       (4,440 )     (9,745 )
 
Net cash used for investing activities
    (135,073 )     (111,605 )     (124,347 )
 
Financing Activities:
                       
Increase (decrease) in notes payable, net
    12,334       9,187       (58,831 )
Proceeds —
                       
Pollution control bonds
          61,625       55,000  
Senior notes
    110,000       225,000       45,000  
Other long-term debt
    100,000              
Mandatorily redeemable preferred securities
                40,000  
Capital contributions from parent company
    29,481       13,315       42,766  
Redemptions —
                       
Pollution control bonds
          (61,625 )     (55,000 )
Senior notes
    (125,000 )     (151,757 )     (454 )
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
    (70,000 )     (70,200 )     (65,500 )
Other
    (2,433 )     (10,644 )     (3,279 )
 
Net cash provided from (used for) financing activities
    54,165       (90,316 )     (515 )
 
Net Change in Cash and Cash Equivalents
    62,281       (10,730 )     11,034  
Cash and Cash Equivalents at Beginning of Period
    2,548       13,278       2,244  
 
Cash and Cash Equivalents at End of Period
  $ 64,829     $ 2,548     $ 13,278  
 
Supplemental Cash Flow Information:
                       
Cash paid during the period for —
                       
Interest (net of $819, $314, and $1,392 capitalized, respectively)
  $ 28,796     $ 37,468     $ 39,604  
Income taxes (net of refunds)
    24,130       23,777       34,048  
 

The accompanying notes are an integral part of these financial statements.

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BALANCE SHEETS
At December 31, 2004 and 2003
Gulf Power Company 2004 Annual Report

                 
   
Assets
  2004     2003  
 
  (in thousands)  
Current Assets:
               
Cash and cash equivalents
  $ 64,829     $ 2,548  
Receivables —
               
Customer accounts receivable
    44,255       44,001  
Unbilled revenues
    35,889       31,548  
Under recovered regulatory clause revenues
    9,283       21,812  
Other accounts and notes receivable
    7,177       6,179  
Affiliated companies
    16,218       9,826  
Accumulated provision for uncollectible accounts
    (2,144 )     (947 )
Fossil fuel stock, at average cost
    32,999       35,354  
Vacation pay
    5,446       5,254  
Materials and supplies, at average cost
    36,761       35,930  
Prepaid income taxes
    34,812       4  
Prepaid expenses
    3,563       6,310  
Other
    8,732       4,981  
 
Total current assets
    297,820       202,800  
 
Property, Plant, and Equipment:
               
In service
    2,367,189       2,306,959  
Less accumulated provision for depreciation
    844,617       847,519  
 
 
    1,522,572       1,459,440  
Construction work in progress
    74,004       49,438  
 
Total property, plant, and equipment
    1,596,576       1,508,878  
 
Other Property and Investments
    6,425       13,339  
 
Deferred Charges and Other Assets:
               
Deferred charges related to income taxes
    17,566       18,263  
Prepaid pension costs
    45,384       42,014  
Unamortized debt issuance expense
    6,615       6,877  
Unamortized loss on reacquired debt
    19,197       19,389  
Other regulatory assets
    107,994       19,058  
Other
    13,086       8,435  
 
Total deferred charges and other assets
    209,842       114,036  
 
Total Assets
  $ 2,110,663     $ 1,839,053  
 

The accompanying notes are an integral part of these financial statements.

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BALANCE SHEETS
At December 31, 2004 and 2003
Gulf Power Company 2004 Annual Report

                 
   
Liabilities and Stockholder’s Equity   2004     2003  
 
    (in thousands)  
Current Liabilities:
               
Securities due within one year
  $ 100,000     $ 50,000  
Notes payable
    50,000       37,666  
Accounts payable —
               
Affiliated
    35,359       26,945  
Other
    77,452       21,952  
Customer deposits
    18,470       18,271  
Accrued taxes —
               
Income taxes
    1,927       6,405  
Other
    9,250       8,621  
Accrued interest
    7,665       8,077  
Accrued vacation pay
    5,446       5,254  
Accrued compensation
    16,989       13,456  
Other
    12,988       9,694  
 
Total current liabilities
    335,546       206,341  
 
Long-term Debt (See accompanying statements)
    550,989       515,827  
 
Long-term Debt Payable to Affiliated Trusts (See accompanying statements)
    72,166        
 
Mandatorily Redeemable Preferred Securities (See accompanying statements)
          70,000  
 
Deferred Credits and Other Liabilities:
               
Accumulated deferred income taxes
    229,909       175,685  
Deferred credits related to income taxes
    23,354       26,545  
Accumulated deferred investment tax credits
    18,489       20,451  
Employee benefit obligations
    54,869       52,395  
Other cost of removal obligations
    155,831       151,229  
Miscellaneous regulatory liabilities
    2,048       27,903  
Other
    71,192       27,083  
 
Total deferred credits and other liabilities
    555,692       481,291  
 
Total Liabilities
    1,514,393       1,273,459  
 
Preferred Stock (See accompanying statements)
    4,098       4,236  
 
Common Stockholder’s Equity (See accompanying statements)
    592,172       561,358  
 
Total Liabilities and Stockholder’s Equity
  $ 2,110,663     $ 1,839,053  
 
Commitments and Contingent Matters (See notes)
               
 

The accompanying notes are an integral part of these financial statements.

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STATEMENTS OF CAPITALIZATION
At December 31, 2004 and 2003
Gulf Power Company 2004 Annual Report

                                 
 
    2004     2003     2004     2003  
 
    (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 —
                               
7.05% due August 15, 2004
          50,000                  
Variable rate (2.36% at 1/1/05) due October 8, 2005
    100,000                        
4.35% to 6.10% due 2013-2044
    335,000       300,000                  
 
Total long-term notes payable
    435,000       350,000                  
 
Other long-term debt —
                               
Pollution control revenue bonds —
                               
Collateralized: 5.25% due April 1, 2006
    12,075       12,075                  
Non-collateralized:
                               
4.80% due September 1, 2028
    13,000       13,000                  
Variable rates (1.90% to 2.27% at 1/1/05) due 2022-2037
    144,555       144,555                  
 
Total other long-term debt
    169,630       169,630                  
 
Unamortized debt premium (discount), net
    (8,641 )     (8,803 )                
 
Total long-term debt (annual interest requirement — $27.6 million)
    650,989       565,827                  
Less amount due within one year
    100,000       50,000                  
 
Long-term debt excluding amount due within one year
    550,989       515,827       45.2 %     44.7 %
 
Long-term Debt Payable to Affiliated Trusts:
                               
7.375% due 2041
    30,928                        
5.60% through 2007 due 2042*
    41,238                        
 
Total long-term debt payable to affiliated trusts (annual interest requirement — $4.6 million)
    72,166             5.9       0.0  
 
Mandatorily Redeemable Preferred Securities:
                               
$25 liquidation value — 7.375% due 2041
          30,000                  
$1,000 liquidation value — 5.60% through 2007 due 2042*
          40,000                  
 
Total mandatorily redeemable preferred securities
          70,000       0.0       6.1  
 
Cumulative Preferred Stock:
                               
$100 par value
                               
4.64%
    1,150       1,250                  
5.16%
    1,329       1,357                  
5.44%
    1,619       1,629                  
 
Total cumulative preferred stock (annual dividend requirement — $0.2 million)
    4,098       4,236       0.3       0.4  
 
Common Stockholder’s Equity:
                               
Common stock, without par value —
                               
Authorized and outstanding -
                               
992,717 shares in 2004 and 2003
    38,060       38,060                  
Paid-in capital
    397,396       364,864                  
Retained earnings
    159,581       161,208                  
Accumulated other comprehensive income (loss)
    (2,865 )     (2,774 )                
 
Total common stockholder’s equity
    592,172       561,358       48.6       48.8  
 
Total Capitalization
  $ 1,219,425     $ 1,151,421       100.0 %     100.0 %
 


*   The fixed rate thereafter is 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.

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STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
For the Years Ended December 31, 2004, 2003, and 2002
Gulf Power Company 2004 Annual Report

                                         
 
                            Other        
    Common     Paid-In     Retained     Comprehensive        
    Stock     Capital     Earnings     Income (Loss)     Total  
 
    (in thousands)  
Balance at December 31, 2001
  $ 38,060     $ 305,972     $ 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       349,781       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       364,864       161,208       (2,774 )     561,358  
Net income after dividends on preferred stock
                68,223             68,223  
Capital contributions from parent company
          32,544                   32,544  
Other comprehensive income (loss)
                      (91 )     (91 )
Cash dividends on common stock
                (70,000 )           (70,000 )
Other
          (12 )     150             138  
 
Balance at December 31, 2004
  $ 38,060     $ 397,396     $ 159,581     $ (2,865 )   $ 592,172  
 

The accompanying notes are an integral part of these financial statements.

STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2004, 2003, and 2002
Gulf Power Company 2004 Annual Report

                         
 
    2004     2003     2002  
 
    (in thousands)  
Net income after dividends on preferred stock
  $ 68,223     $ 69,010     $ 67,036  
 
Other comprehensive income (loss):
                       
Changes in additional minimum pension liability, net of tax of $(184), $(84) and $(461), respectively
    (292 )     (134 )     (734 )
Change in fair value of marketable securities, net of tax of $35
    56              
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 $91 and $63
    145       100        
 
Total other comprehensive income (loss)
    (91 )     (2,040 )     (734 )
 
Comprehensive Income
  $ 68,132     $ 66,970     $ 66,302  
 

The accompanying notes are an integral part of these financial statements.

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NOTES TO FINANCIAL STATEMENTS

Gulf Power Company 2004 Annual Report

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General

Gulf Power Company (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 (SouthernLINC Wireless), 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 the subsidiary companies. SouthernLINC Wireless 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 various other energy-related businesses. 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, as amended (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 (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.

     The equity method is used for subsidiaries in which the Company has significant influence but does not control and for variable interest entities where the Company is not the primary beneficiary. 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, $55 million, and $49 million during 2004, 2003, and 2002, 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 $6.8 million, $4.9 million, and $4.5 million and Mississippi Power $17.8 million, $17.7 million, and $16.6 million in 2004, 2003, and 2002, respectively, for its proportionate share of related expenses. See Note 4 and Note 7 under “Operating Leases” for additional information. Also, see Note 5 for information on certain deferred tax liabilities due to affiliates.

     The retail operating companies (including the Company), Southern Power, and Southern Company GAS

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NOTES (continued)

Gulf Power Company 2004 Annual Report

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

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 for differences between the actual recoverable costs and amounts billed in current regulated 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.

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:

                         
    2004     2003     Note  
    (in thousands)          
Asset retirement obligations
  $ 1,453     $ 1,019       (a )
Other cost of removal obligations
    (155,831 )     (151,229 )     (a )
Deferred income tax charges
    17,566       18,263       (a )
Loss on reacquired debt
    19,197       19,389       (b )
Vacation pay
    5,446       5,254       (c )
Deferred income tax credits
    (23,354 )     (26,545 )     (a )
Accumulated provision for property damage
    48,284       (26,244 )     (d )
Environmental remediation
    59,364       12,878       (f )
Fuel-hedging liabilities, net
    (309 )     (2,501 )     (e )
Other assets
    5,656       8,198       (d )
Other liabilities
    (1,967 )     (3,177 )     (d )
         
Total
  $ (24,495 )   $ (144,695 )        
         

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 Florida PSC.
 
(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.

     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 currently reflected in rates.

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

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NOTES (continued)

Gulf Power Company 2004 Annual Report

and amortized to income over the average life of the related property.

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 2004, 3.8 percent in 2003, and 3.9 percent in 2002. When property subject to depreciation is retired or otherwise disposed of in the normal course of business, its cost — together with the cost of removal, less salvage — is charged to the accumulated provision for depreciation. Minor items of property included in the original cost of the plant are retired when the related property unit is retired.

Asset Retirement Obligations and Other Costs of Removal

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 present value of the ultimate cost 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. Although 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 received accounting guidance from the Florida PSC allowing such treatment. Accordingly, the accumulated removal costs for other obligations previously accrued will continue to be reflected on the balance sheets 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 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 statements of income allowed removal costs in accordance with its regulatory treatment. Any differences 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:

                 
    2004     2003  
    (in thousands)  
Balance beginning of year
  $ 4,271     $  
Liabilities incurred
          3,998  
Liabilities settled
           
Accretion
    316       273  
Cash flow revisions
    1,202        
 
Balance end of year
  $ 5,789     $ 4,271  
 

Allowance for Funds Used During Construction (AFUDC)

In accordance with regulatory treatment, the Company records AFUDC on certain 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 2004, 2003, and 2002, the average AFUDC rates were 7.48 percent, 7.48 percent, and 7.35 percent, respectively. AFUDC, net of taxes, as a percentage of net income after dividends on preferred stock was 3.46 percent, 1.31 percent, and 5.72 percent, respectively, for 2004, 2003, and 2002.

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 as incurred or performed. The cost of replacements of property — exclusive of minor items of property — is capitalized.

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NOTES (continued)

Gulf Power Company 2004 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 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.

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 of Southern Company’s common stock 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.

     The pro forma impact of fair-value accounting for options granted on earnings is as follows:

                 
    As     Pro  
Net income (in thousands)   Reported     Forma  
 
2004
  $ 68,223     $ 67,587  
2003
  $ 69,010     $ 68,336  
2002
  $ 67,036     $ 66,327  

     The estimated fair values of stock options granted in 2004, 2003, and 2002 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:

                         
    2004     2003     2002  
         
Interest rate
    3.1 %     2.7 %     2.8 %
Average expected life of stock options (in years)
    5.0       4.3       4.3  
Expected volatility of common stock
    19.6 %     23.6 %     26.3 %
Expected annual dividends on common stock
  $ 1.40     $ 1.37     $ 1.34  
Weighted average fair value of stock options granted
  $ 3.29     $ 3.59     $ 3.37  
         

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

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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, 2004
  $ 723,155     $ 729,821  
At December 31, 2003
    565,827       572,899  
Preferred Securities
               
At December 31, 2004
  $     $  
At December 31, 2003
    70,000       73,376  
 

     The fair values were based on either closing market price or closing price of comparable instruments. See “Variable Interest Entities” herein and Note 6 under “Mandatorily Redeemable Preferred Securities/ Long-Term Debt Payable to Affiliated Trusts” for additional information.

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 value of qualifying cash flow hedges and marketable securities, 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 accrues for the uninsured costs of injuries and damages by charges to income amounting to $1.6 million annually. The Florida PSC has also given the Company the flexibility to increase its annual accrual above $1.6 million to the extent the balance in the accumulated provision does not exceed $2 million. The cost of settling claims is charged to the provision. The accumulated provision of $1.7 million and $0.1 million at December 31, 2004 and 2003, respectively, is included in other current liabilities in the balance sheets. See Note 3 under “Personal Injury Litigation” for additional information. In addition to the accumulated provision, at December 31, 2004, the Company had a liability with a corresponding regulatory asset of $4.8 million for estimated liabilities related to outstanding claims and suits.

Provision for Property Damage

The Company accrues for the cost of repairing damages from major storms and other uninsured property damages, including damages to transmission and distribution lines and the cost of uninsured damages to its generation facilities and other property. The cost of such damages is charged to the accrual. The Florida PSC 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 Florida PSC also authorized the Company to make additional accruals above the $3.5 million at the Company’s discretion. The Company accrued total expenses of $18.5 million in 2004, $10.6 million in 2003, and $3.5 million in 2002. At December 31, 2004, the accumulated provision for property damage was $(48.3) million and is included in miscellaneous regulatory assets in the balance sheets. See Note 3 to the financial statements under “Retail Regulatory Matters” for additional information.

Environmental Cost Recovery

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 may also incur substantial costs to clean up properties. The Company received authority from the Florida PSC to recover approved environmental compliance costs through the ECRC. The Florida PSC reviews costs and adjusts rates up or down annually. See Note 3 under “Environmental Remediation” for information on additional environmental remediation accruals in 2004.

Variable Interest Entities

On March 31, 2004, the Company prospectively adopted FASB Interpretation No. 46R, Consolidation of Variable Interest Entities, which requires the primary beneficiary of a variable interest entity to consolidate the related assets and liabilities. The adoption of Interpretation No. 46R had no impact on the net income

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of the Company. However, as a result of the adoption, the Company deconsolidated certain wholly-owned trusts established to issue preferred securities since the Company is not the primary beneficiary of the trusts. Therefore, the investments in these trusts are reflected as Other Investments for the Company. The related loans from the trusts are reflected as Long-term Debt Payable to Affiliated Trusts on the balance sheets. This treatment resulted in an increase of $2.2 million in both total assets and total liabilities as of March 31, 2004.

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 of 1974, as amended (ERISA), requirements. No contributions to the plan are expected for the year ending December 31, 2005. 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 Florida PSC and the FERC. For the year ended December 31, 2005, postretirement trust contributions are expected to total approximately $70,000.

     The measurement date for plan assets and obligations is September 30 of each year.

Pension Plans

The accumulated benefit obligation for the pension plans was $204 million in 2004 and $186 million in 2003. Changes during the year in the projected benefit obligations, accumulated benefit obligations, and fair value of plan assets were as follows:

                 
    Projected  
    Benefit Obligations
    2004     2003  
 
    (in thousands)  
Balance at beginning of year
  $ 206,486     $ 184,987  
Service cost
    5,915       5,225  
Interest cost
    12,136       11,733  
Benefits paid
    (9,499 )     (8,785 )
Actuarial (gain)/loss and employee transfers, net
    13,207       13,326  
Plan Amendments
    169        
 
Balance at end of year
  $ 228,414     $ 206,486  
 
                 
    Plan Assets
    2004     2003  
 
    (in thousands)  
Balance at beginning of year
  $ 236,345     $ 211,166  
Actual return on plan assets
    23,152       33,672  
Employer Contributions
    550       491  
Benefits paid
    (9,499 )     (8,785 )
Employee transfers
    (310 )     (199 )
 
Balance at end of year
  $ 250,238     $ 236,345  
 

     Pension plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code of 1986, as amended (Internal 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     2004     2003  
 
Domestic equity
    37 %     36 %     37 %
International equity
    20       20       20  
Fixed income
    26       26       24  
Real estate
    10       10       11  
Private equity
    7       8       8  
 
Total
    100 %     100 %     100 %
 

     The reconciliations of the funded status with the accrued pension costs recognized in the balance sheets were as follows:

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    Accrued Pension Costs
    2004     2003  
 
    (in thousands)  
Funded status
  $ 21,824     $ 29,859  
Unrecognized transition amount
    (721 )     (1,441 )
Unrecognized prior service cost
    12,434       13,471  
Unrecognized net (gain) loss
    7,511       (3,985 )
 
Prepaid pension asset, net
  $ 41,048     $ 37,904  
 

     The prepaid pension asset, net is reflected in the balance sheets in the following line items:

                 
    2004     2003  
 
    (in thousands)  
Prepaid pension asset
  $ 45,384     $ 42,014  
Employee benefit obligations
    (7,316 )     (6,434 )
Other Property and Investments — Other
    1,091       911  
Accumulated other comprehensive income
    1,889       1,413  
 
Prepaid pension asset, net
  $ 41,048     $ 37,904  
 

     Components of the pension plans’ net periodic cost were as follows:

                         
    2004     2003     2002  
 
    (in thousands)  
Service cost
  $ 5,915     $ 5,225     $ 4,910  
Interest cost
    12,136       11,733       12,394  
Expected return on plan assets
    (20,689 )     (20,564 )     (20,431 )
Recognized net gain
    (317 )     (1,819 )     (2,746 )
Net amortization
    486       486       298  
 
Net pension income
  $ (2,469 )   $ (4,939 )   $ (5,575 )
 

     Future benefit payments reflect expected future service and are estimated based on assumptions used to measure the projected benefit obligation for the pension plans. At December 31, 2004, estimated benefit payments were as follows:

         
    Benefit
Payments
 
 
    (in thousands)  
2005
  $ 9,709  
2006
    10,026  
2007
    10,316  
2008
    10,655  
2009
    11,063  
2010 to 2014
  $ 65,742  
 

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
    2004     2003  
 
    (in thousands)  
Balance at beginning of year
  $ 72,903     $ 63,675  
Service cost
    1,275       1,128  
Interest cost
    4,080       4,059  
Benefits paid
    (2,447 )     (2,332 )
Actuarial (gain)/loss
    (6,625 )     6,373  
 
Balance at end of year
  $ 69,186     $ 72,903  
 
                 
    Plan Assets
    2004     2003  
 
    (in thousands)  
Balance at beginning of year
  $ 12,642     $ 10,893  
Actual return on plan assets
    1,594       1,616  
Employer contributions
    2,507       2,465  
Benefits paid
    (2,447 )     (2,332 )
 
Balance at end of year
  $ 14,296     $ 12,642  
 

     Postretirement benefits plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal 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     2004     2003  
 
Domestic equity
    35 %     34 %     35 %
International equity
    19       19       19  
Fixed income
    30       30       29  
Real estate
    9       10       10  
Private equity
    7       7       7  
 
Total
    100 %     100 %     100 %
 

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     The accrued postretirement costs recognized in the balance sheets were as follows:

                 
    2004     2003  
 
    (in thousands)  
Funded status
  $ (54,891 )   $ (60,261 )
Unrecognized transition obligation
    2,944       3,301  
Unrecognized prior service cost
    4,657       5,003  
Unrecognized net loss
    8,074       15,313  
Fourth quarter contributions
    829       195  
 
Accrued liability recognized in the balance sheets
  $ (38,387 )   $ (36,449 )
 

     Components of the postretirement plans’ net periodic cost were as follows:

                         
    2004     2003     2002  
 
    (in thousands)  
Service cost
  $ 1,275     $ 1,128     $ 948  
Interest cost
    4,081       4,058       3,991  
Expected return on plan assets
    (1,220 )     (1,139 )     (1,100 )
Transition obligation
    355       356       356  
Prior service cost
    346       346       346  
Recognized net (gain)/loss
    241       113       (19 )
 
Net postretirement cost
  $ 5,078     $ 4,862     $ 4,522  
 

     In the third quarter 2004, the Company prospectively adopted FASB Staff Position (FSP) 106-2, Accounting and Disclosure Requirements related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (Medicare Act). The Medicare Act provides a 28 percent prescription drug subsidy for Medicare eligible retirees. FSP 106-2 requires recognition of the impacts of the Medicare Act in the accumulated postretirement benefit obligation (APBO) and future cost of service for postretirement medical plan. The effect of the subsidy reduced the Company’s expenses for the six months ended December 31, 2004 by approximately $0.5 million and is expected to have a similar impact on future years. The subsidy’s impact on the postretirement medical plan APBO was a reduction of approximately $8.0 million. However, the ultimate impact on future periods is subject to federal regulations governing the subsidy created in the Medicare Act which are being finalized.

     Future benefit payments, including prescription drug benefits, reflect expected future service and are estimated based on the assumptions used to measure the accumulated benefit obligation for the postretirement plan. Estimated benefit payments are reduced by drug subsidy receipts expected as a result of the Medicare Act as follows:

                         
    Benefit     Subsidy        
    Payments     Receipts     Total  
 
    (in thousands)  
2005
  $ 2,787     $     $ 2,787  
2006
    3,085       (367 )     2,718  
2007
    3,343       (399 )     2,944  
2008
    3,664       (441 )     3,223  
2009
    4,003       (499 )     3,504  
2010 to 2014
  $ 25,277     $ (3,175 )   $ 22,102  
 

     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:

                         
    2004     2003     2002  
 
Discount
    5.75 %     6.00 %     6.50 %
Annual salary increase
    3.50 %     3.75 %     4.00 %
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 11 percent for 2004, decreasing gradually to 5 percent through the year 2012, 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, 2004 as follows:

                 
    1 Percent
    Increase     Decrease  
 
    (in thousands)  
Benefit obligation
  $ 4,877     $ 3,883  
Service and interest costs
  $ 353     $ 310  
 

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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 2004, 2003, and 2002, 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 and Georgia Power, alleging violations of the New Source Review (NSR) provisions of the Clean Air Act and related state laws at five coal-fired generating facilities in Alabama and Georgia. The EPA concurrently issued to each of 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.

     The U.S. District Court in Georgia subsequently granted Alabama Power’s motion to dismiss and denied the EPA’s motion to add the Company and Mississippi Power for lack of jurisdiction in Georgia. In March 2001, the court granted the EPA’s motion to add Savannah Electric as a defendant and to add allegations regarding two additional generating facilities owned by Alabama Power. 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 civil complaints allege violations with respect to eight coal-fired generating facilities in Alabama and Georgia, and they request penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The EPA has not refiled against the Company or Mississippi Power.

     The actions against Alabama Power, Georgia Power, and Savannah Electric were effectively stayed in the spring of 2001 during the appeal of a similar NSR enforcement action against the Tennessee Valley Authority (TVA) before the U.S. Court of Appeals for the Eleventh Circuit. In June 2003, the Court of Appeals issued its ruling in the TVA case, dismissing the appeal for reasons unrelated to the issues in the cases pending against Alabama Power, Georgia Power and Savannah Electric. In May 2004, the U.S. Supreme Court denied the EPA’s petition for review of the case. In June 2004, the U.S. District Court for the Northern District of Alabama lifted the stay in the action against Alabama Power, placing the case back onto the court’s active docket. At this time, no party to the case against Georgia Power and Savannah Electric has sought to reopen that case, which remains administratively closed in the District Court for the Northern District of Georgia.

     Since the inception of the NSR proceedings against Alabama Power, Georgia 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. District courts addressing these cases have, to date, issued opinions

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that reached conflicting conclusions.

     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 maximum civil penalties of $25,000 to $32,500 per day, per violation at each generating unit, depending on the date of the alleged violation. 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.

     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 (RMRR) exclusion. A coalition of states and environmental organizations has filed petitions for review of these revisions with the U.S. Court of Appeals for the District of Columbia Circuit. The October 2003 RMRR rules have been stayed by the Court of Appeals pending its review of the rules. In any event, the final regulations must be adopted by the individual states within the Company’s service territory in order to apply to the Company’s facilities. The effect of these final regulations, related legal challenges and potential state rulemaking cannot be determined at this time.

Generation Interconnection Agreements

In July 2003, the FERC issued its final rule on the standardization of generation interconnection agreements and procedures (Order 2003). Order 2003 shifts much of the financial burden of new transmission investment from the generator to the transmission provider. The FERC has indicated that Order 2003, which was effective January 20, 2004, is to be applied prospectively to interconnection agreements. Subsidiaries of Tenaska, Inc., as counterparties to three previously executed interconnection agreements with other subsidiaries of Southern Company, have filed complaints at the FERC requesting that the FERC modify the agreements and that Southern Company refund amounts previously paid for interconnection facilities, with interest. The Company has received similar requests from other entities totaling $6.6 million. Southern Company has opposed such relief and these matters are still outstanding. The impact of Order 2003 and its subsequent rehearings on the Company and the final results of these matters cannot be determined at this time.

Market-Based Rate Authority

The Company has authorization from the FERC to sell power to nonaffiliates at market-based prices. 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, the retail operating companies, and Southern Power, and found them and others to be “pivotal suppliers” in their retail service territories and ordered the implementation of several mitigation measures. Southern Company sought rehearing of the FERC order, and the FERC delayed the implementation of certain mitigation measures. In April 2004, the FERC issued an order that abandoned the SMA test and adopted a new interim analysis for measuring generation market power. This new interim approach requires utilities to submit a pivotal supplier screen and a wholesale market share screen. If the applicant does not pass both screens, there will be a rebuttable presumption regarding generation market power. The FERC’s order also sets forth procedures for rebutting these presumptions and addresses mitigation measures for those entities that are found to have market power. In the absence of specific mitigation measures, the order includes several cost-based mitigation measures that would apply by default. The FERC also initiated a new rulemaking proceeding that, among other things, will adopt a final methodology for assessing generation market power.

     In July 2004, the FERC denied Southern Company’s request for rehearing, along with a number of others, and reaffirmed the interim tests that it adopted in April 2004. In August 2004, Southern Company submitted a filing to the FERC that included results showing that Southern Company passed the pivotal supplier screen for all markets and the wholesale market share screen for all markets except the Southern Company retail service territory. Southern Company

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also submitted other analyses to demonstrate that it lacks generation market power. On December 17, 2004, the FERC initiated a proceeding to assess Southern Company’s generation dominance within its retail service territory. The ability to charge market-based rates in other markets is not at issue. As directed by this order, Southern Company submitted additional information on February 15, 2005 related to generation dominance in its retail service territory. Any new market-based rate transactions in the Southern Company retail service territory entered into after February 27, 2005 will be subject to refund to the level of the default cost-based rates, pending the outcome of the proceeding. Southern Company, along with other utilities, has also filed an appeal of the FERC’s April and July 2004 orders with the U.S. Court of Appeals for the District of Columbia Circuit. The FERC has asked the court to dismiss the appeal on the grounds that it is premature.

     In the event that the FERC’s default mitigation measures are ultimately applied, the Company may be required to charge cost-based rates for certain wholesale sales in the Southern Company retail service territory, which may be lower than negotiated market-based rates. The final outcome of this matter will depend on the form in which the final methodology for assessing generation market power and mitigation rules may be ultimately adopted and cannot be determined at this time.

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 was the subject of an appeal to Florida’s First District Court of Appeal. In May 2004, the court affirmed the result of the jury’s verdict without submitting a written opinion, thereby preempting the Company’s right to appeal the case to the Florida Supreme Court. Therefore, in June 2004 the Company paid the judgment amount and accrued interest. As a result of insurance coverage, there was no 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. 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 exceed the easements or other property rights held by defendants. The plaintiffs assert claims for, among other things, trespass and unjust enrichment, and seek compensatory and punitive damages and injunctive relief.

     In November 2003, the Second Circuit Court in Gadsden County, Florida, ruled in favor of the plaintiffs on their motion for partial summary judgment concerning liability in one such lawsuit brought by landowners regarding the installation and use of fiber optic cable over the Company’s rights of way located on the landowners’ property. Subsequently, the plaintiffs sought to amend their complaint and asked the court to enter a final declaratory judgment and to enter an order enjoining the Company from allowing expanded general telecommunications use of the fiber optic cables that are the subject of this litigation. On January 6, 2005, the trial judge entered an order granting in part the plaintiffs’ motion to amend their Complaint and denying the requested declaratory and injunctive relief at this time. The question of damages with respect to this action 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 it in pending and future right of way litigation. The defendants believe that the plaintiff’s claims are without merit. In the fall of 2004, the trial court stayed the case until resolution of the underlying

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landowner litigation discussed above. On January 12, 2005, the Georgia Court of Appeals dismissed the telecommunications company’s appeal of the trial court’s order for lack of jurisdiction. 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

In May 2002, the Florida PSC 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.

     On February 2, 2005, the Citizens of the State of Florida through the Office of Public Counsel, the Florida Industrial Power Users Group, and the Company filed a Stipulation and Settlement with the Florida PSC to resolve all matters regarding the effects of Hurricane Ivan on the Company’s reserve for property damage (Stipulation).

     Under the terms of the Stipulation, the Company will recover the retail portion of $51.7 million of Hurricane Ivan storm damage costs, plus interest and revenue taxes, through a monthly surcharge applied to retail customer bills for a 24-month period. For purposes of the Stipulation, such recovery amount excludes $44.8 million from the amount to be recovered, including $26.4 million in capital that will be included in retail rate base, and a $15 million discretionary accrual made by the Company in 2004 pursuant to the agreement between the parties reached in the Stipulation.

     In the event that the Florida Legislature enacts legislation that allows for the securitization of storm recovery financing under terms of a financing order that provides for the establishment of storm recovery property through a surcharge, the Stipulation provides that the Company may request an order from the Florida PSC under such legislation to securitize the retail portion of the agreed $51.7 million plus interest and revenue taxes, as well as additional amounts not to exceed $27.8 million plus interest and revenue taxes.

     Except under circumstances provided for within the Stipulation, the Company has agreed that it will not seek any additional increase in its base rates and charges to become effective on or before March 1, 2007.

     The Stipulation is subject to the approval of the Florida PSC, which is expected to rule on the Stipulation at its next meeting in March 2005. The ultimate outcome of this matter cannot now be determined.

Environmental Remediation

The Florida Legislature adopted legislation for an ECRC, which allows an electric utility 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 also allows 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 EPA. During 2004, 2003, and 2002, the Company recorded ECRC revenues of $14.7 million, $10.7 million, and $10.8 million, respectively.

     At December 31, 2004, the Company’s liability for the estimated costs of environmental remediation projects for known sites was $59.4 million. In September 2004, the Company increased its liability by approximately $47 million. This increase relates to new regulations and more stringent site closure criteria by the FDEP for impacts to soil and groundwater from herbicide applications at Company substations. Because FDEP approval is required prior to the issuance of site closure, a timeframe for the completion of the remediation projects cannot be determined. These projects have been approved by the Florida PSC for recovery through the ECRC. Therefore, the Company recorded $1.4 million in current assets and current liabilities and $58.0 million in deferred assets and deferred liabilities representing the future recoverability of these costs.

     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 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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4.   JOINT OWNERSHIP AGREEMENTS

The Company and Mississippi Power jointly own Plant Daniel Units 1 and 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.

     At December 31, 2004, 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
  $ 190,005 (1)   $ 239,308  
Accumulated Depreciation
  $ 84,394     $ 128,422  
Construction Work in Progress
  $ 205     $ 537  
Ownership
    25 %     50 %
 


(1)   Includes net plant acquisition adjustment of $4.3 million.

5. INCOME TAXES

Southern Company and its subsidiaries file a consolidated federal income tax return and a combined State of Georgia income tax return. Under a joint consolidated income tax allocation agreement, as required by the PUHCA, each subsidiary’s current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more expense than would be paid if they filed a separate income tax return. In accordance with Internal Revenue Service regulations, each company is jointly and severally liable for the tax liability.

     In 2004, in order to avoid the loss of certain federal income tax credits related to the production of synthetic fuel, Southern Company chose to defer certain deductions otherwise available to the subsidiaries. The cash flow benefit associated with the utilization of the tax credits was allocated to the subsidiary that otherwise would have claimed the available deductions on a separate company basis without the deferral. This allocation concurrently reduced the tax benefit of the credits allocated to those subsidiaries that generated the credits. As the deferred expenses are deducted, the benefit of the tax credits will be repaid to the subsidiaries that generated the tax credits. The Company has recorded $6.8 million payable to these subsidiaries in “Accumulated Deferred Income Taxes” on the balance sheets.

     At December 31, 2004, the tax-related regulatory assets to be recovered from customers were $17.6 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, 2004, the tax-related regulatory liabilities to be credited to customers were $23.4 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:

                         
    2004     2003     2002  
    (in thousands)  
Total provision for income taxes:
                       
Federal—
                       
Current
  $ (4,255 )   $ 33,871     $ 24,474  
Deferred
    39,373       1,702       7,936  
 
 
    35,118       35,573       32,410  
 
State—
                       
Current
    (2,305 )     4,703       3,051  
Deferred
    6,882       601       1,683  
 
 
    4,577       5,304       4,734  
 
Total
  $ 39,695     $ 40,877     $ 37,144  
 

     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:

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    2004     2003  
    (in thousands)  
Deferred tax liabilities:
               
Accelerated depreciation
  $ 218,137     $ 200,129  
Other
    53,092       27,669  
 
Total
    271,229       227,798  
 
Deferred tax assets:
               
Federal effect of state deferred taxes
    11,930       9,568  
Pension & postretirement benefits
    14,608       11,793  
Other
    12,855       24,347  
 
Total
    39,393       45,708  
 
Net deferred tax liabilities
    231,836       182,090  
Less prepaid (accrued) income taxes, net
    (1,927 )     (6,405 )
 
Accumulated deferred income taxes in the balance sheets
  $ 229,909     $ 175,685  
 

     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 and amortization in the statements of income. Credits amortized in this manner amounted to $2.0 million in 2004, $1.8 million in 2003, and $1.8 million in 2002. At December 31, 2004, 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:

                         
    2004     2003     2002  
Federal statutory rate
    35 %     35 %     35 %
State income tax, net of federal deduction
    3       3       3  
Non-deductible book depreciation
    1       1       1  
Difference in prior years’ deferred and current tax rate
    (1 )     (1 )     (2 )
Other, net
    (1 )     (1 )     (1 )
 
Effective income tax rate
    37 %     37 %     36 %
 

6. FINANCING

Mandatorily Redeemable Preferred Securities/ Long-Term Debt Payable to Affiliated Trusts

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 and are reflected on the balance sheets as Long-term Debt Payable to Affiliated 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 trusts’ payment obligations with respect to these securities. At December 31, 2004, these securities were outstanding. See Note 1 under “Variable Interest Entities” for additional information on the accounting treatment for these trusts and the related securities.

Pollution Control Bonds

Pollution control obligations represent loans to the Company from public authorities of funds derived from sales by such authorities of revenue bonds issued to finance pollution control facilities. The Company is required to make payments sufficient for the authorities to meet principal and interest requirements of such bonds. With respect to $12.1 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 loan agreements. No principal or interest on these first mortgage bonds is payable unless and until a default occurs on the loan agreements.

Long-Term Debt Due Within One Year

At December 31, 2004, 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 improvement 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 2009 applicable to long-term debt are as follows: $100.0 million

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Gulf Power Company 2004 Annual Report

in 2005; $37.1 million in 2006; and zero in 2007, 2008, and 2009.

Common Stock Dividend Restrictions

The Company’s first mortgage bond indenture contains various common stock dividend restrictions, which remain in effect as long as the bonds are outstanding. At December 31, 2004, 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. In addition, the Company has granted a second lien on its property at Plant Daniel in connection with the issuance of two series of pollution control bonds.

     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 satisfy obligations of Southern Company or any of its subsidiaries.

Bank Credit Arrangements

At the beginning of 2005, the Company had $56.3 million of lines of credit with banks subject to renewal each year, all of which remained unused. The $56.3 million in committed lines of credit provide liquidity support for the Company’s commercial paper program and for $4.0 million of daily variable rate pollution control bonds. In connection with these credit lines, the Company has agreed to pay commitment fees and/or to maintain compensating balances with the banks. The compensating balances, which represent substantially all of the cash of the Company except for daily working funds and like items, are not legally restricted from withdrawal.

     Certain credit arrangements contain covenants that limit the level of indebtedness to capitalization to 65 percent, as defined in the arrangements. For purposes of these definitions, debt excludes the long-term debt payable to affiliated trusts. At December 31, 2004, the Company was in compliance with these debt limit covenants.

     In addition, certain credit arrangements contain cross default provisions to other indebtedness that would trigger an event of default 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 borrows through a commercial paper program that has the liquidity support of committed bank credit arrangements and through an extendible commercial note program. At December 31, 2004, the Company had no commercial paper or extendible commercial notes outstanding. At December 31, 2003, the Company had $37.7 million in commercial paper outstanding. These amounts are included in the notes payable on the balance sheets. During 2004, the peak amount outstanding for commercial paper was $47.6 million and the average amount outstanding was $10.7 million. The average annual interest rate on commercial paper was 1.23 percent.

     In addition, the Company has bid-loan facilities with four major money center banks that total $50 million, with none committed at December 31, 2004.

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 Florida PSC. The Company enters into hedges of forward electricity sales. There was no material ineffectiveness recorded in earnings in 2004 and 2003.

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     At December 31, 2004, the fair value of derivative energy contracts was reflected in the financial statements as follows:

         
    Amounts  
    (in thousands)  
Regulatory liabilities, net
  $ 309  
Other comprehensive income
     
Net income
    8  
 
Total fair value
  $ 317  
 

     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 has energy-related hedges in place up to and including 2007.

     The Company also 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 for any year presented.

     During 2004, the Company did not enter into any interest rate derivatives. 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, maturing in 2013. 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 and 2003, approximately $0.3 million and $0.2 million, respectively, of pre-tax losses were reclassified from other comprehensive income to interest expense. For 2005, 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 $154 million in 2005, $112 million in 2006, and $103 million in 2007. The construction program is subject to periodic review and revision, and actual construction costs may vary from the above estimates because of numerous factors. These factors include changes in business conditions; acquisition of additional generation 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. At December 31, 2004, significant purchase commitments were outstanding in connection with the construction program.

     Included in the amounts above, the Company has budgeted $40 million and $4 million in 2005 and 2006, respectively, for capital expenditures related to environmental controls at Plant Crist as part of an agreement with the FDEP to reduce nitrogen oxide emissions. The Florida PSC authorized the Company to recover the costs related to these environmental projects through the ECRC. The construction program also includes $15 million in 2005, $9 million in 2006, and $23 million in 2007 for other environmental expenditures. Construction of new transmission and distribution facilities and other capital improvements, including those needed to meet environmental standards for the Company’s existing generation, transmission, and distribution facilities, are ongoing.

Long-Term Service Agreement

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. 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 payments to GE under this agreement for facilities owned are currently estimated at $81.2 million over the remaining life of the agreement. However, the LTSA contains various cancellation provisions at the option of the Company.

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Gulf Power Company 2004 Annual Report

     Payments made to GE prior to the performance of any planned inspections are recorded as 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 Exchange future prices at December 31, 2004. Total estimated minimum long-term obligations at December 31, 2004 were as follows:

                         
    Purchased     Natural        
Year   Power     Gas     Coal  
    (in thousands)          
2005
  $ 311     $ 95,604     $ 196,159  
2006
          78,425       151,970  
2007
          50,726       76,640  
2008
          18,886        
2009
          18,886        
2010 and thereafter
          240,269        
 
Total commitments
  $ 311     $ 502,796     $ 424,769  
 

     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 operating lease agreements with various terms and expiration dates. Total operating lease expenses were $2.0 million, $2.2 million, and $2.1 million for 2004, 2003, and 2002, respectively.

     At December 31, 2004, estimated minimum rental commitments for noncancelable operating leases were as follows:

                         
    Rail              
Year   Cars     Other     Total  
    (in thousands)  
2005
  $ 2,422     $ 59     $ 2,481  
2006
    2,422             2,422  
2007
    2,422             2,422  
2008
    2,068             2,068  
2009
    2,068             2,068  
2010 and thereafter
    6,238             6,238  
 
Total minimum payments
  $ 17,640     $ 59     $ 17,699  
 

     In 1989, the Company and Mississippi Power jointly entered into a twenty-two year operating lease agreement for the use of 495 aluminum railcars. In 1994, a second lease agreement for the use of 250 additional aluminum railcars was entered into for twenty-two years. Both of these leases are for the transportation of coal to Plant Daniel. 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. In 2004, the Company and Mississippi Power entered into a three year operating lease agreement for the use of 120 aluminum railcars. There is no purchase option associated with this lease.

     The Company, as a joint owner of Plant Daniel Units 1 and 2, is responsible for one-half of the lease costs. The lease costs are charged to fuel inventory and are allocated to fuel expense as the fuel is used. 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 each of 2004, 2003, and 2002.

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8. 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, 2004, 258 current and former employees of the Company participated in the stock option plan. The maximum number of shares of Southern Company common stock that may be issued under this plan may not exceed 55 million. The prices of options granted to date have been at the fair market value of the shares on the dates of grant. Options granted to date become exercisable pro rata over a maximum period of three years from the date of grant. Options outstanding will expire no later than 10 years after the date of grant, unless terminated earlier by the Southern Company Board of Directors in accordance with the stock option plan. Activity from 2002 to 2004 for the options granted to the Company’s employees under the stock option plan is summarized below:

                 
    Shares     Average  
    Subject     Option Price  
    To Option     Per Share  
Balance at December 31, 2001
    1,031,944     $ 17.57  
Options granted
    322,431       25.26  
Options canceled
    (1,999 )     21.14  
Options exercised
    (126,178 )     14.77  
 
Balance at December 31, 2002
    1,226,198       19.88  
Options granted
    274,245       27.98  
Options canceled
    (3,082 )     19.26  
Options exercised
    (192,189 )     17.01  
 
Balance at December 31, 2003
    1,305,172       22.00  
Options granted
    256,363       29.50  
Options canceled
    (438 )     28.47  
Options exercised
    (386,413 )     18.76  
 
Balance at December 31, 2004
    1,174,684     $ 24.70  
 
 
               
Options exercisable:
               
At December 31, 2002
    632,015          
At December 31, 2003
    839,618          
At December 31, 2004
    715,570          
 

     The following table summarizes information about options outstanding at December 31, 2004:

                         
    Dollar Price  
    Range of Options  
    13-20     20-26     26-32  
Outstanding:
                       
Shares
    261,102       405,017       508,565  
Average remaining life (in years)
    5.6       6.8       8.6  
Average exercise price
  $ 17.47     $ 24.32     $ 28.72  
Exercisable:
                       
Shares
    261,102       339,871       114,597  
Average exercise price
  $ 17.47     $ 24.14     $ 27.99  
 

9.   QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

Summarized quarterly financial data for 2004 and 2003 are as follows:

                         
                    Net Income
    Operating   Operating   After Dividends
Quarter Ended   Revenues   Income   on Preferred Stock
    (in thousands)
March 2004
  $ 214,919     $ 35,803     $ 16,839  
June 2004
    241,170       39,824       19,002  
September 2004
    269,386       59,628       31,900  
December 2004
    234,656       9,457       482  
 
                       
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  
 

     The Company’s business is influenced by seasonal weather conditions and the timing of rate changes, among other factors.

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SELECTED FINANCIAL AND OPERATING DATA 2000-2004

Gulf Power Company 2004 Annual Report

                                         
 
    2004     2003     2002     2001     2000  
 
Operating Revenues (in thousands)
  $ 960,131     $ 877,697     $ 820,467     $ 725,203     $ 714,319  
Net Income after Dividends on Preferred Stock (in thousands)
  $ 68,223     $ 69,010     $ 67,036     $ 58,307     $ 51,843  
Cash Dividends on Common Stock (in thousands)
  $ 70,000     $ 70,200     $ 65,500     $ 53,275     $ 59,000  
Return on Average Common Equity (percent)
    11.83       12.42       12.72       12.51       12.20  
Total Assets (in thousands)
  $ 2,110,663     $ 1,839,053     $ 1,816,889     $ 1,713,436     $ 1,448,977  
Gross Property Additions (in thousands)
  $ 161,205     $ 99,284     $ 106,624     $ 274,668     $ 95,807  
 
Capitalization (in thousands):
                                       
Common stock equity
  $ 592,172     $ 561,358     $ 549,505     $ 504,894     $ 427,378  
Preferred stock
    4,098       4,236       4,236       4,236       4,236  
Mandatorily redeemable preferred securities
          70,000       115,000       115,000       85,000  
Long-term debt payable to affiliated trusts
    72,166                          
Long-term debt
    550,989       515,827       452,040       467,784       365,993  
 
Total (excluding amounts due within one year)
  $ 1,219,425     $ 1,151,421     $ 1,120,781     $ 1,091,914     $ 882,607  
 
Capitalization Ratios (percent):
                                       
Common stock equity
    48.6       48.8       49.0       46.2       48.4  
Preferred stock
    0.3       0.4       0.4       0.4       0.5  
Mandatorily redeemable preferred securities
          6.1       10.3       10.5       9.6  
Long-term debt payable to affiliated trusts
    5.9                          
Long-term debt
    45.2       44.7       40.3       42.9       41.5  
 
Total (excluding amounts due within one year)
    100.0       100.0       100.0       100.0       100.0  
 
Security Ratings:
                                       
First Mortgage Bonds - 
                                       
Moody’s
    A1       A1       A1       A1       A1  
Standard and Poor’s
    A+       A+       A+       A+       A+  
Fitch
    A+       A+       A+       A+     AA-  
Preferred Stock - 
                                       
Moody’s
  Baa1     Baa1     Baa1     Baa1       a2  
Standard and Poor’s
  BBB+     BBB+     BBB+     BBB+     BBB+  
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
    343,151       341,935       333,757       327,128       321,731  
Commercial
    51,865       51,169       49,411       48,654       47,666  
Industrial
    285       285       281       270       280  
Other
    473       473       474       468       442  
 
Total
    395,774       393,862       383,923       376,520       370,119  
 
Employees (year-end):
    1,336       1,337       1,339       1,309       1,327  
 

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SELECTED FINANCIAL AND OPERATING DATA 2000-2004 (continued)

Gulf Power Company 2004 Annual Report

                                         
 
    2004     2003     2002     2001     2000  
 
Operating Revenues (in thousands):
                                       
Residential
  $ 401,382     $ 381,464     $ 365,693     $ 313,165     $ 302,210  
Commercial
    232,928       218,928       207,960       188,759       177,047  
Industrial
    99,420       95,702       89,385       81,719       74,095  
Other
    3,140       3,080       2,798       948       (4,712 )
 
Total retail
    736,870       699,174       665,836       584,591       548,640  
Sales for resale — non-affiliates
    73,537       76,767       77,171       82,252       66,890  
Sales for resale — affiliates
    110,264       63,268       40,391       27,256       66,995  
 
Total revenues from sales of electricity
    920,671       839,209       783,398       694,099       682,525  
Other revenues
    39,460       38,488       37,069       31,104       31,794  
 
Total
  $ 960,131     $ 877,697     $ 820,467     $ 725,203     $ 714,319  
 
Kilowatt-Hour Sales (in thousands):
                                       
Residential
    5,215,332       5,101,099       5,143,802       4,716,404       4,790,038  
Commercial
    3,695,471       3,614,255       3,552,931       3,417,427       3,379,449  
Industrial
    2,113,027       2,146,956       2,053,668       2,018,206       1,924,749  
Other
    22,579       22,479       21,496       21,208       18,730  
 
Total retail
    11,046,409       10,884,789       10,771,897       10,173,245       10,112,966  
Sales for resale — non-affiliates
    2,256,942       2,504,211       2,156,741       2,093,203       1,705,486  
Sales for resale — affiliates
    3,124,788       2,438,874       1,720,240       962,892       1,916,526  
 
Total
    16,428,139       15,827,874       14,648,878       13,229,340       13,734,978  
 
Average Revenue Per Kilowatt-Hour (cents):
                                       
Residential
    7.70       7.48       7.11       6.64       6.31  
Commercial
    6.30       6.06       5.85       5.52       5.24  
Industrial
    4.71       4.46       4.35       4.05       3.85  
Total retail
    6.67       6.42       6.18       5.75       5.43  
Sales for resale
    3.42       2.83       3.03       3.58       3.70  
Total sales
    5.60       5.30       5.35       5.25       4.97  
Residential Average Annual Kilowatt-Hour Use Per Customer
    15,096       15,064       15,510       14,497       14,992  
Residential Average Annual Revenue Per Customer
  $ 1,162     $ 1,126     $ 1,100     $ 963     $ 946  
Plant Nameplate Capacity Ratings (year-end) (megawatts)
    2,712       2,786       2,809       2,188       2,188  
Maximum Peak-Hour Demand (megawatts):
                                       
Winter
    2,061       2,494       2,182       2,106       2,154  
Summer
    2,421       2,269       2,454       2,223       2,285  
Annual Load Factor (percent)
    57.1       54.6       55.3       57.5       55.4  
Plant Availability Fossil-Steam (percent):
    92.4       90.7       90.6       90.1       85.2  
 
Source of Energy Supply (percent):
                                       
Coal
    77.9       78.7       69.8       81.2       87.8  
Gas
    14.4       11.9       15.5       1.0       1.6  
Purchased power - 
                                       
From non-affiliates
    4.5       3.2       4.6       6.5       7.6  
From affiliates
    3.2       6.2       10.1       11.3       3.0  
 
Total
    100.0       100.0       100.0       100.0       100.0  
 

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MISSISSIPPI POWER COMPANY

 
 
 
FINANCIAL SECTION
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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, 2004 and 2003, 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, 2004. 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.

     We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (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 consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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-241 to II-265) present fairly, in all material respects, the financial position of Mississippi Power Company at December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004, 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
February 28, 2005

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MANAGEMENT’S DISCUSSION AND ANALYSIS
Mississippi Power Company 2004 Annual Report

OVERVIEW

Business Activities

Mississippi Power Company (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.

     Many 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 stringent environmental standards. In 2004, the Company completed a major retail rate proceeding that should help provide future earnings stability. Appropriately balancing environmental expenditures with reasonable retail rates will continue to challenge the Company for the foreseeable future.

Key Performance Indicators

The Company strives to maximize shareholder value while providing low-cost, reliable energy to more than 190,000 customers in southeast Mississippi. In recognition that the Company’s long-term financial success is dependent upon how well it satisfies its customers’ needs, the Company’s retail base rate mechanism, the Performance Evaluation Plan (PEP), includes performance indicators that directly tie customer service indicators to the Company’s allowed return. PEP measures the Company’s performance on a 10 point scale as a weighted average of results in three areas: average customer price, as compared to prices of other regional utilities (weighted at 40%); service reliability, measured in outage minutes per customer (40%); and customer satisfaction, measured in surveys of residential customers (20%). The Company’s PEP performance score in 2004 was 8.9 out of 10, resulting in an 89 basis point increase to the Company’s retail allowed return on investment for 2005. See Note 3 to the financial statements under “Retail Regulatory Matters” for more information on PEP.

     In addition to the PEP performance indicators, the Company focuses on other performance measures, including broader measures of customer satisfaction, return on equity (ROE), and peak season equivalent forced outage rate (Peak Season EFOR). ROE is the performance standard used by both the investment community and many regulatory agencies. Peak Season EFOR is a key element in the Company’s price performance. It measures plant availability and efficient generation fleet operations during the months when generation needs are greatest.

                         
 
  Key     2004     2004  
  Performance     Target     Actual  
  Indicator     Performance     Performance  
 
Customer Satisfaction
    Top quartile in national and regional surveys     Top quartile  
 
Peak Season EFOR
      2.58 %       1.05 %  
 
ROE
      13.80 %       14.24 %  
 

     The Company’s performance in 2004 reflects the focus that management places on all of these indicators, as well as the commitment shown by the Company’s employees in achieving or exceeding management’s expectations.

Earnings

The Company’s net income after dividends on preferred stock was $76.8 million in 2004 compared to $73.5 million in 2003. The increase in 2004 resulted from increased retail base revenue and higher non-territorial energy sales. Retail base revenues grew over $3 million as a result of improving economic conditions in the service area. The increase in sales for resale to non-affiliates resulted from the additional Plant Daniel capacity available following the 2003 termination of a contract with a subsidiary of Dynegy, Inc. (Dynegy). The 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 the Dynegy contract, the income effect of which was offset by a $60 million expense related to the establishment of a regulatory liability in connection with an accounting order issued by the Mississippi PSC. See Note 3 to the financial statements under “Retail Regulatory Matters” for additional information.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2004 Annual Report

     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 retail and wholesale rate increases in late 2001 and early 2002, respectively, and lower interest expense.

RESULTS OF OPERATIONS

A condensed statement of income is as follows:

                                 
            Increase (Decrease)  
    Amount     From Prior Year  
    2004     2004     2003     2002  
    (in thousands)  
Operating revenues
  $ 910,326     $ 40,402     $ 45,759     $ 28,100  
 
Fuel
    320,997       91,746       (53,142 )     4,447  
Purchased power
    106,763       13,566       41,864       (43,911 )
Other operation and maintenance
    241,363       (58,755 )     68,105       41,015  
Depreciation and amortization
    39,390       (16,310 )     (1,938 )     3,561  
Taxes other than income taxes
    55,572       1,581       (1,527 )     10,552  
 
Total operating expenses
    764,085       31,828       53,362       15,664  
 
Operating income
    146,241       8,574       (7,603 )     12,436  
Total other income and (expense)
    (14,942 )     1,898       7,525       2,008  
Less — Income taxes
    50,666       5,351       (564 )     5,346  
 
Net income
    80,633       5,121       486       9,098  
 
Dividends on preferred stock
    3,832       1,819             (28 )
 
Net income after dividends on preferred stock
  $ 76,801     $ 3,302     $ 486     $ 9,126  
 

Revenues

Details of the Company’s operating revenues in 2004 and the prior two years are as follows:

                         
    Amount  
    2004     2003     2002  
    (in thousands)  
Retail — prior year
  $ 516,301     $ 536,827     $ 489,153  
Change in — Base rates
                38,143  
Sales growth
    2,530       1,175       566  
Weather
    1,025       (1,542 )     3,533  
Fuel cost recovery and other
    64,457       (20,159 )     5,432  
 
Retail — current year
    584,313       516,301       536,827  
 
Sales for resale —
                       
Non-affiliates
    265,863       249,986       224,275  
Affiliates
    44,371       26,723       46,314  
 
Total sales for resale
    310,234       276,709       270,589  
 
Contract termination
          62,111        
Other electric operating revenues
    15,779       14,803       16,749  
 
Total electric operating revenues
  $ 910,326     $ 869,924     $ 824,165  
 
Percent change
    4.6 %     5.6 %     3.5 %
 

     Total retail revenues for 2004 increased 13.2 percent when compared to 2003. While higher fuel costs accounted for 92 percent of this increase, sales growth, particularly in industrial customers, also contributed to the increase. Industrial sales in 2004 grew over the prior year for the first time since 2000 as most of the Company’s industrial customers recovered from the recent economic downturn. Total retail revenues for 2003 decreased approximately 3.8 percent when compared to 2002 as a result of decreased fuel revenues and, to a 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 “Retail Regulatory Matters” for additional information.

     Fuel revenues generally represent the direct recovery of fuel expenses including purchased power. Therefore, changes in recoverable fuel expenses are offset with corresponding changes in fuel revenues and

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2004 Annual Report

have no effect on net income. The fuel cost recovery and other revenues increased in 2004 when compared to 2003 as a result of an increase in fuel expenses due to consistently higher fuel prices and a slight increase in retail rates that became effective in 2004. During 2003, the fuel cost recovery and other revenues decreased $20 million compared to 2002 due to lower generation and fewer fuel purchases as a result of milder than normal weather in 2003.

     Sales for resale to non-affiliates are influenced by the non-affiliate utilities’ own customer demand, plant availability, and fuel costs. Included in sales for resale to non-affiliates are revenues from rural electric cooperative associations and municipalities located in southeastern Mississippi. As compared to the prior year, sales to these utilities increased 3.3 percent in 2004, remained relatively flat in 2003, and increased 8.0 percent in 2002, with the related revenues increasing 12.4 percent, 1.6 percent, and 19.8 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 2004 by $14.4 million, or 5.7 percent. This increase primarily resulted from a $32.7 million increase in related energy revenues, of which approximately $6 million was associated with increased kilowatt-hour sales and $26.7 million was associated with higher prices due to increased fuel cost in 2004. The increase was offset by an $18.3 million decrease in related capacity revenues as a result of the termination of the contract with Dynegy in 2003. 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, primarily as the result of a new power sales contract that began in June 2001, as well as colder winter months during 2002.

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 are made in accordance with the affiliated company interchange agreement, as approved by the Federal Energy Regulatory Commission (FERC). These sales do not have a significant impact on earnings since the energy is generally sold at marginal cost.

     Kilowatt-hour (KWH) sales for 2004 and percent change by year were as follows:

                                 
    KWH     Percent Change
    2004     2004     2003     2002  
    (in millions)                    
Residential
    2,297       1.9 %     (1.9 )%     6.3 %
Commercial
    2,970       1.9       0.4       2.1  
Industrial
    4,235       3.0       (1.2 )     (2.7 )
Other
    40       1.0              
 
                             
Total retail
    9,542       2.4       (0.9 )     0.1  
Sales for Resale
                               
Non-Affiliated
    6,028       2.6       9.2       7.4  
Affiliated
    1,054       48.6       (55.3 )     (46.3 )
 
                             
Total
    16,624       4.5       (2.8 )     (5.3 )
 

     Total retail kilowatt-hour sales increased in 2004 when compared to 2003. The increase is the result of higher sales to all retail classes, particularly the industrial class, due to the effects of economic recovery in the area. 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. Industrial sales decreased in 2003 due to lower kilowatt-hour sales and decreased fuel costs. Industrial sales fell 2.7 percent in 2002 due to an economic downturn in the Company’s service area.

     The Company anticipates modest growth over the next five years due to a recovery from the national and regional economic downturn and some growth in the gaming and tourism industry. Retail sales are expected to grow at an annual average rate of approximately 1.9 percent through 2009, with increases expected in the local, state, and federal government sectors, as well as increases in shipbuilding, oil and gas production and refining, and tourism-related industries.

Expenses

In 2004, total operating expenses increased 4.3 percent to $764 million when compared to 2003. The increase is the result of increased fuel expense, as a result of increased generation and higher fuel prices. Total operating expenses were $732 million in 2003, which

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2004 Annual Report

reflects an increase of 7.9 percent over 2002. The increase in 2003 is primarily due to $60 million in Plant Daniel capacity expense recorded in connection with an accounting order from the Mississippi PSC. See Note 3 to the financial statements under “Retail Regulatory Matters” 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 increased maintenance expense resulting from planned outages at Plant Watson and Plant Daniel as well as a full year of rental expense for Plant Daniel Units 3 and 4 and a slight increase in fuel expense.

     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, the average cost of fuel per net kilowatt-hour generated, and the average cost of purchased power were as follows:

                         
    2004     2003     2002  
 
Total generation (millions of kilowatt-hours)
    14,058       12,850       15,079  
 
                       
Sources of generation (percent) —
                       
Coal
    69       74       57  
Gas
    31       26       43  
Average cost of fuel per net kilowatt-hour generated (cents) —
    2.47       1.95       2.03  
Average cost of purchased power per kilowatt-hour (cents) —
    3.28       2.51       2.60  
 

     Fuel expense increased $92 million in 2004 as compared to 2003. Approximately $25 million of the increase was associated with increased generation and approximately $67 million of the increase was due to higher coal and gas prices. Fuel expense for 2003 decreased $53 million due to decreased generation and lower average cost of fuel. Fuel expense for 2002 increased $4 million due to a fuel hedging loss, which was approved for recovery through the fuel cost recovery clause authorized by the Mississippi PSC.

     A significant upward trend in the cost of coal and natural gas has emerged since 2003, and volatility in these markets is expected to continue. Increased coal prices have been influenced by a worldwide increase in demand as a result of rapid economic growth in China as well as by increases in mining costs. Higher natural gas prices in the United States are the result of slightly lower gas supplies despite increased drilling activity. Natural gas supply interruptions, such as those caused by the 2004 hurricanes, result in an immediate market response; however, the impact of this price volatility may be reduced by imports of natural gas and liquefied natural gas. Fuel expenses generally do not affect net income since they are offset by fuel revenues under the Company’s fuel cost recovery clause.

     Purchased power expense increased $13.6 million, or 14.6 percent, in 2004 when compared to 2003. The increase is the result of an increase in purchases from non-affiliates. These purchases were needed to meet increased load and offset higher priced self-generation resulting from increased fuel costs. In 2003, purchased power expense increased $41.9 million, or 81.6 percent. The increase was primarily due to an increase in purchased power expense from affiliate companies. Those purchases were more economical than self generation due to the increased cost of natural gas in 2003. In 2002, purchased power expense decreased $43.9 million 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. Energy purchases vary from year to year depending on demand and the availability and cost of the Company’s generating resources. These expenses do not have a significant impact on earnings since the energy purchases are generally offset by energy revenues through the Company’s fuel cost recovery clause.

     Other operation expense decreased $65.7 million, or 28.6 percent, in 2004 and increased $71.7 million, or 45.3 percent, in 2003 due to approximately $11 million incurred in 2003 to restructure the lease agreement for the combined cycle generating units at Plant Daniel and $60 million in expense recorded in 2003 in connection with the recognition of a regulatory liability following an accounting order from the Mississippi PSC related to Plant Daniel capacity expense. See FINANCIAL CONDITION AND LIQUIDITY—“Off-Balance Sheet Financing Arrangements” and Notes 3 and 7 to the financial statements under “Retail Regulatory Matters” and “Operating Leases – Plant Daniel Combined Cycle

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2004 Annual Report

Generating Units,” respectively, for additional information. In 2002, other operation expense increased $23.5 million, or 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.

     Maintenance expense increased $7.0 million, or 9.9 percent, in 2004 as a result of higher operating hours at Plant Daniel and increased distribution line maintenance during 2004. Maintenance expense decreased $3.6 million, or 4.9 percent, in 2003 primarily resulting from a decrease of approximately 50 percent in operating hours at Plant Daniel Units 3 and 4. See Note 7 to the financial statements under “Long-Term Service Agreements” for further information. In 2002, maintenance expense increased $17.5 million, or 31.2 percent, primarily due to scheduled maintenance performed at Plant Watson and Plant Daniel.

     Depreciation and amortization expense decreased $16.3 million in 2004 as compared to 2003 primarily due to $16.5 million of amortization related to a regulatory liability recorded in 2003 in connection with the Mississippi PSC’s accounting order on the Plant Daniel Capacity. See Note 3 under “Retail Regulatory Matters” for additional information. In 2003, depreciation and amortization expense decreased $1.9 million compared to 2002 primarily due the amortization related to the Company’s Environmental Compliance Overview Plan (ECO Plan) approved by the Mississippi PSC. In 2002, depreciation and amortization expense increased $3.6 million due to increased plant in service and due to amortization of the Company’s regulatory asset related to the ECO Plan. See Note 3 to the financial statements under “Environmental Compliance Overview Plan” for further information.

     In 2004, taxes other than income taxes increased 2.9 percent due to additional municipal franchise taxes, which are directly related to the increase in retail revenues. 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 an increase in property taxes related to Plant Daniel Units 3 and 4 and increased municipal franchise taxes. The decrease in total other income and expense is due to interest on long-term debt decreasing in all years presented 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 based on the recovery of historical costs. In addition, the income tax laws are based on historical costs. Therefore, inflation creates an economic loss because the Company is recovering its 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 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 Southeastern United States. Prices for electricity relating to jointly owned generating facilities, interconnecting transmission lines, and the exchange of electric power are set by the FERC. Prices for electricity provided by the Company to retail customers are set by the Mississippi PSC under cost-based regulatory principles. Retail rates and earnings are reviewed and adjusted periodically within certain limitations based on earned ROE. See ACCOUNTING POLICIES – “Application of Critical Accounting Policies and Estimates – Electric Utility Regulation” herein and Note 3 to the financial statements for additional information about these and other regulatory matters.

     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 that affect the challenges and risks of the Company’s business of selling electricity. These

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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 more stringent 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.

     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).

Environmental Matters

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 and Georgia Power. The complaint alleged violations of the New Source Review (NSR) provisions of the Clean Air Act and related state laws at five coal-fired generating facilities in Alabama and Georgia. 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 EPA concurrently issued to the retail operating companies notices of violations relating to ten generating facilities, which included 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 the Company, Gulf Power, 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.

     The Company believes that it has complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $32,500 per day, per violation at each generating unit, depending on the date of the alleged violation. 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.

     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 (RMRR) exclusion. A coalition of states and environmental organizations has filed petitions for review of these revisions with the U.S. Court of Appeals for the District of Columbia Circuit. The October 2003 RMRR rules have been stayed by the Court of Appeals pending its review of the rules. In any event, the final regulations must be adopted by the individual states in the Company’s service territory in order to apply to the Company’s facilities. The effect of these final regulations, related legal challenges, and potential state rulemakings cannot be determined at this time.

Carbon Dioxide Litigation

On July 21, 2004, attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel for New York City filed a complaint in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. A nearly identical complaint was filed by three environmental groups in the same court. The complaints allege that the companies’ emissions of carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs assert is a public nuisance. Under common law public and private nuisance theories, the plaintiffs seek a judicial order (1) holding each defendant jointly and severally liable for creating, contributing to, and/or

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maintaining global warming and (2) requiring each of the defendants to cap its emissions of carbon dioxide and then reduce those emissions by a specified percentage each year for at least a decade. Plaintiffs have not, however, requested that damages be awarded in connection with their claims. Southern Company believes these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. Southern Company and the other defendants have filed motions to dismiss both lawsuits. Southern Company intends to vigorously defend against these claims. While the outcome of these matters cannot be determined at this time, an adverse judgment in either of these actions could result in substantial capital expenditures.

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 involves significant capital and operating costs, a major portion of which is expected to be recovered through the Company’s ECO Plan. See Note 3 to the financial statements under “Environmental Compliance Overview Plan” for additional information. Environmental costs that are known and estimable at this time are included in capital expenditures discussed under FINANCIAL CONDITION AND LIQUIDITY – “Capital Requirements and Contractual Obligations” herein. There is no assurance, however, that all such costs will, in fact, be recovered.

     Compliance with the 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 and resulted in total construction expenditures of approximately $65 million through 2000.

     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 and included development of an eight-hour ozone standard, as opposed to the previous one-hour ozone standard. 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. On April 30, 2004, the EPA published its eight-hour ozone nonattainment designations and a portion of the rules implementing the new eight-hour ozone standard. Areas within the Company’s service area have not been designated as nonattainment under the eight-hour ozone standard.

     In January 2004, the EPA issued a proposed Clean Air Interstate Rule (CAIR) 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 in 2005. If finalized, the rule could modify or supplant other state requirements for attainment of the fine particulate matter standard and the eight-hour ozone standard, as well as other air quality regulations. 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.

     The Company has developed and maintains an environmental compliance strategy for the installation of additional control technologies and the purchase of emission allowances to assure continued compliance with current sulfur dioxide and nitrogen oxide emission regulations. Additional expenses associated with these regulations are anticipated to be incurred each year to maintain current and future compliance. Because the Company’s compliance strategy is impacted by factors such as changes to existing environmental laws and regulations, increases in the cost of emissions allowances, and any changes in the Company’s fuel mix, future environmental compliance costs 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 and to implement emission reduction requirements that make progress toward remedying current visibility impairment in certain natural areas. 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 implementation plans in 2008 that contain emission reduction strategies for implementing BART

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and for achieving sufficient progress toward the Clean Air Act’s visibility improvement goal. In response to litigation, the EPA proposed revised rules in May 2004, which it plans to finalize in April 2005. The impact of these regulations will depend on the promulgation of final rules and implementation of those rules by the states and, therefore, it is not possible to determine the effect of these rules on the Company at this time.

     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 March 2005, and compliance could be required as early as 2008. Because the regulations have not been finalized, the impact on the Company cannot be determined at this time.

     Major bills to amend the Clean Air Act to impose more stringent emissions limitations on power plants including the Bush Administration’s Clear Skies Act, have been re-proposed in 2005. The Clear Skies Act is expected to further limit power plant emissions of sulfur dioxide, nitrogen oxides, and mercury and to supplement the proposed CAIR and mercury regulatory programs. Other proposals to limit emissions of carbon dioxide have also been introduced. The cost impacts of such legislation would depend upon the specific requirements enacted and cannot be determined at this time.

     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. In July 2004, the EPA published final rules that 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 and the actual limits established by the regulatory agencies.

     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 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.

Global Climate Issues

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 constraints on the emissions of greenhouse gases for a group of industrialized countries. The Bush Administration has not supported U.S. ratification of the Kyoto Protocol or other mandatory carbon dioxide reduction legislation and, in 2002, announced a goal to reduce the greenhouse gas intensity of the U.S. – the ratio of greenhouse gas emissions to the value of U.S. economic output — by 18 percent by 2012. A year later, the Department of Energy (DOE) announced the Climate VISION program to support this goal. Energy-intensive industries, including electricity generation are the initial focus of this program. Southern Company is leading the development of a voluntary electric utility sector climate change initiative in partnership with the government. The utility sector has pledged to reduce its greenhouse gas emissions rate by 3 to 5 percent over the next decade and, on December 13, 2004, signed a memorandum of understanding with the DOE initiating this program under Climate VISION. Because efforts under this voluntary program are just beginning, the impact of this program on the Company cannot be determined at this time.

Environmental Remediation Reserves

The Company must comply with 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 may incur substantial costs to remediate properties. The Company conducts studies to determine the extent of any required remediation and has recognized in its financial statements the costs to remediate 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

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cleanup costs for additional sites that may require environmental remediation. The Company has received authority from the Mississippi PSC to recover approved environmental compliance costs through specific retail rate clauses. Within limits approved by the Mississippi PSC, these rates are adjusted annually. See Note 3 to the financial statements under “Environmental Remediation” for additional information.

FERC and Mississippi PSC Matters

Transmission

In December 1999, the FERC issued its final rule on Regional Transmission Organizations (RTOs). Since that time, there have been a number of additional proceedings at the FERC designed to encourage further voluntary formation of RTOs or to mandate their formation. However, at the current time, there are no active proceedings that would require Southern Company to participate in an RTO. Current FERC efforts that may potentially change the regulatory and/or operational structure of transmission include rules related to the standardization of generation interconnection, as well as an inquiry into, among other things, market power by vertically integrated utilities. See “Generation Interconnection Agreements” and “Market-Based Rate Authority” herein for additional information. The final outcome of these proceedings cannot now be determined. However, Southern Company’s financial condition, results of operations, and cash flows could be adversely affected by future changes in the federal regulatory or operational structure of transmission.

Generation Interconnection Agreements

In July 2003, the FERC issued its final rule on the standardization of generation interconnection agreements and procedures (Order 2003). Order 2003 shifts much of the financial burden of new transmission investment from the generator to the transmission provider. The FERC has indicated that Order 2003, which was effective January 20, 2004, is to be applied prospectively to interconnection agreements. The impact of Order 2003 and its subsequent rehearings on the Company cannot be determined at this time.

Market-Based Rate Authority

The Company has obtained FERC approval to sell power to nonaffiliates at market-based prices. 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, its retail operating companies and Southern Power and found Southern Company and others to be “pivotal suppliers” in their retail service territories 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. In April 2004, the FERC issued an order that abandoned the SMA test and adopted a new interim analysis for measuring generation market power. This new interim approach requires utilities to submit a pivotal supplier screen and a wholesale market share screen. If the applicant does not pass both screens, there will be a rebuttable presumption regarding generation market power. The FERC’s order also sets forth procedures for rebutting these presumptions and addresses mitigation measures for those entities that are found to have market power. In the absence of specific mitigation measures, the order includes several cost-based mitigation measures that would apply by default. The FERC also initiated a new rulemaking proceeding that, among other things, will adopt a final methodology for assessing generation market power.

     In July 2004, the FERC denied SCS’s request for rehearing, along with a number of others, and reaffirmed the interim tests that it adopted in April 2004. In August 2004, Southern Company submitted a filing to FERC that included results showing that Southern Company passed the pivotal supplier screen for all markets and the wholesale market share screen for all markets except its retail service territory. Southern Company also submitted other analyses to demonstrate that it lacks generation market power. On December 17, 2004, the FERC initiated a proceeding to assess Southern Company’s generation dominance within the Southern Company retail service territory. The ability to charge market-based rates in other markets is not at issue. As directed by this order, on February 15, 2005, Southern Company submitted additional information related to

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generation dominance in the Southern Company retail service territory. Any new market-based rate transactions in its retail service territory entered into after February 27, 2005 will be subject to refund to the level of the default cost-based rates, pending the outcome of the proceeding. Southern Company, along with other utilities, has also filed an appeal of the FERC’s April and July 2004 orders with the U.S. Court of Appeals for the District of Columbia Circuit. The FERC has asked the court to dismiss the appeal on the grounds that it is premature.

     In the event that the FERC’s default mitigation measures are ultimately applied, the Company may be required to charge cost-based rates for certain wholesale sales in the Southern Company retail service territory, which may be lower than negotiated market-based rates. The final outcome of this matter will depend on the form in which the final methodology for assessing generation market power and mitigation rules may be ultimately adopted and cannot be determined at this time.

Retail Rate Filing

In May 2004, the Mississippi PSC approved the Company’s request to reclassify 266 megawatts of Plant Daniel Units 3 and 4 capacity to jurisdictional cost of service effective January 1, 2004 and authorized the Company to include the related costs and revenue credits in jurisdictional rate base, cost of service, and revenue requirement calculations for purposes of retail rate recovery. The Company is amortizing the regulatory liability established pursuant to the Mississippi PSC’s interim December 2003 order, as approved in the May 2004 order, to earnings as follows: $16.5 million in 2004, $25.1 million in 2005, $13.0 million in 2006, and $5.7 million in 2007, resulting in reductions of costs in each of those years.

Other Matters

On October 22, 2004, President Bush signed the American Jobs Creation Act of 2004 (Jobs Act) into law. The Jobs Act includes a provision that allows a generation tax deduction for utilities. The Company is currently assessing the impact of the Jobs Act, including this deduction, as well as the related regulatory treatment, on its taxable income. However, the Company currently does not expect the Jobs Act to have a material impact on its financial statements.

     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 $.6 million, $1.7 million, and $2.5 million in 2004, 2003, and 2002, respectively. Future pension income is dependent on several factors including trust earnings and changes to the pension plan. The decline in pension income is expected to continue, resulting in pension expense in 2005. Postretirement benefit costs for the Company were $4.5 million, $4 million, and $3.7 million in 2004, 2003, and 2002, respectively, and are expected to continue to trend upward. A portion of pension 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.

     The Company is involved in various other 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. Southern Company 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.

Electric Utility Regulation

The Company is subject to retail regulation by the Mississippi PSC and wholesale regulation by the FERC.

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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, which requires the financial statements to reflect the effects of rate 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 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, 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 legislative, 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 herein 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:

•   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.

•   Changes in existing income tax regulations or changes in Internal Revenue Service interpretations of existing regulations.

•   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.

•   Identification and evaluation of other potential lawsuits or complaints in which the Company may be named as a defendant.

•   Resolution or progression of existing matters through the legislative process, the court systems, or the EPA.

Unbilled Revenues

Revenues related to the sale of electricity are recorded when electricity is delivered to customers. However, the determination of kilowatt-hour (KWH) sales to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month. At the end of each month, amounts of electricity delivered to customers, but not yet metered and billed, are estimated. Components of the unbilled revenue estimates include total KWH territorial supply, total KWH billed, estimated total electricity lost in delivery, and customer usage. These components can fluctuate as a result of a number of factors including weather, generation patterns, power delivery volume, and other operational constraints. These factors can be unpredictable and can vary from historical trends. As a result, the overall estimate of unbilled revenues could be significantly affected, which could have a material impact on the Company’s results of operations.

Plant Daniel Operating Lease

As discussed in Note 7 to the financial statements under “Operating Leases – Plant Daniel Combined Cycle Generating Units,” the Company leases a 1,064 megawatt natural gas combined cycle facility at Plant

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Daniel (Facility) from 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 in the 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:

•   Fair market value of the Facility at lease inception.

•   The Company’s incremental borrowing rate.

•   Timing of debt payments and the related amortization of the initial acquisition cost during the initial lease term.

•   Residual value of the Facility at the end of the lease term.

•   Estimated economic life of the Facility.

•   Juniper’s status as a voting interest entity.

     The determination of operating lease treatment was 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. 46R, “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 $37 million annually, rather than annual lease expense of approximately $29 million.

New Accounting Standards

On March 31, 2004, the Company prospectively adopted FASB Interpretation No. 46R, “Consolidation of Variable Interest Entities,” which requires the primary beneficiary of a variable interest entity to consolidate the related assets and liabilities. The adoption of FASB Interpretation No. 46R had no impact on the Company’s net income. However, as a result of the adoption, the Company deconsolidated a certain wholly-owned trust established to issue preferred securities since the Company does not meet the definition of primary beneficiary established by FASB Interpretation No. 46R. See Note 1 to the financial statements under “Variable Interest Entities” for additional information.

     In the third quarter 2004, the Company prospectively adopted FASB Staff Position (FSP) 106-2, Accounting and Disclosure Requirements related to the Medicare Prescription Drug Improvement, and Modernization Act of 2003 (Medicare Act). The Medicare Act provides a 28 percent prescription drug subsidy for Medicare eligible retirees. FSP 106-2 requires recognition of the impacts of the Medicare Act in the accumulated postretirement benefit obligation (APBO) and future cost of service for postretirement medical plans. The effect of the subsidy reduced the Company’s expenses for the six months ended December 31, 2004 by approximately $.5 million and is expected to have a similar impact on future expenses. The subsidy’s impact on the postretirement medical plan APBO was a reduction of approximately $8 million. However, the ultimate impact on future periods is subject to final interpretation of the federal regulations which were published on January 21, 2005. See Note 2 to the financial statements under “Postretirement Benefits” for additional information.

     FASB Statement No. 123R, “Share-Based Payment” was issued in December 2004. This statement requires that compensation cost relating to share-based payment transactions be recognized in financial statements. That cost will be measured based on the grant date fair value of the equity or liability instruments issued. For the Company, this statement is effective beginning on July 1, 2005. Although the compensation expense required under the revised statement differs slightly, the impacts on the financial statements are expected to be similar to the pro forma disclosures included in Note 1 to the financial statements under “Stock Options.”

     See FUTURE EARNINGS POTENTIAL – “Other Matters” herein for information regarding the adoption of new tax legislation. In December 2004, the FASB issued FSP 109-1, Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax Deduction on Qualified Production Activities provided by the American Jobs Creation Act of 2004, which requires that the generation deduction be accounted for as a special tax deduction rather than as a tax rate reduction. The Company is currently assessing the Jobs Act and this pronouncement, as well as the related regulatory treatment, but currently does not expect a material impact on the Company’s financial statements.

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FINANCIAL CONDITION AND LIQUIDITY

Overview

The Company’s financial condition continued to be strong at December 31, 2004. Net cash flow from operating activities totaled $119 million, $183 million, and $193 million for 2004, 2003, and 2002, respectively. The $64 million decrease for 2004 was primarily due to additional cash received in 2003 related to the termination of the Dynegy contract.

     Other significant balance sheet changes from 2003 to 2004 include $78.6 million in property, plant, and equipment additions, $80 million decrease in long-term securities due within one year, $40 million increase in long-term debt, $16.5 million reduction in deferred credit associated with Plant Daniel capacity regulatory liabilities. See “Financing Activities” herein and the statements of cash flows for additional information.

     The Company’s ratio of common equity to total capitalization, excluding long-term debt due within one year, decreased from 66.4 percent in 2003 to 63.7 percent at December 31, 2004.

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. In recent years, financings primarily have utilized unsecured debt and preferred securities. However, the type and timing of any future financings—if needed—will depend on market conditions and regulatory approval.

     The issuance of securities by the Company is subject to regulatory approval by the Securities and Exchange Commission (SEC) under the Public Utility Holding Company Act of 1935, as amended (PUHCA). Additionally, with respect to the public offering of securities, the Company must file registration statements with the SEC under the Securities Act of 1933, as amended (1933 Act). The amounts of securities authorized by the SEC, as well as the amounts registered under the 1933 Act, are continuously monitored and appropriate filings are made to ensure flexibility in the capital markets.

     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 PUHCA, most loans between affiliated companies must be approved in advance by the SEC.

     To meet short-term cash needs and contingencies, the Company has various internal and external sources of liquidity. At the beginning of 2005, the Company had approximately $6.9 million of cash and cash equivalents and $100.5 million of unused credit arrangements with banks. 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. The obligations of each company under these arrangements are several; there is no cross affiliate credit support. At December 31, 2004, the Company had no outstanding commercial paper or extendible commercial notes.

Financing Activities

During 2004, the Company continued a program to retire higher-cost securities and replace them with lower-cost capital. See the statements of cash flows for further details.

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     In March 2004, the Company issued $40 million of Series F Floating Rate Senior Notes due March 9, 2009. The proceeds from this sale, along with other monies of the Company, were used to repay at maturity $80 million aggregate principal amount of the Company’s Series D Floating Rate Senior Notes due March 12, 2004.

     In April 2004, the Company issued 1,200,000 Depositary Shares ($30 million aggregate stated capital), each representing one-fourth of a share of 5.25% Series Preferred Stock, cumulative, par value $100 per share. The proceeds from this sale were primarily used to redeem various issues of higher cost preferred stock and the remainder was used for general corporate purposes.

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 – Plant Daniel Combined Cycle Generating Plant.” 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. The Company does not consolidate the leased assets and related liabilities, and the lease with Juniper is considered an operating lease. Accordingly, the lease is not reflected in the balance sheets.

     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 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 arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. The Company is party to certain derivative agreements that could require collateral and/or accelerated payment in the event of a credit rating change to below investment grade. These agreements are primarily for natural gas price risk management activities. At December 31, 2004, the Company’s exposure related to these agreements was not material.

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 and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques that include, but are not limited to, market valuation and sensitivity analysis.

     The Company does not currently hedge interest rate risk. The weighted average interest rate on variable long-term debt at January 1, 2005 was 2.27 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 $1.2 million at January 1, 2005. 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. At January 1, 2005,

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Mississippi Power Company 2004 Annual Report

exposure from these activities was not material to the Company’s financial statements.

     In addition, at the instruction of the Mississippi PSC, the Company has implemented a fuel-hedging program. At December 31, 2004, exposure from these activities was not material to the Company’s financial statements.

     The change in fair value of energy contracts and year-end valuations are as follows:

                 
    Change in Fair Value  
    2004     2003  
    (in thousands)  
Contracts beginning of year
  $ 2,470     $ 12,864  
Contracts realized or settled
    (9,181 )     (17,210 )
Current period changes (a)
    7,600       6,816  
 
Contracts end of year
  $ 889     $ 2,470  
 

     (a) Current period changes also include the changes in fair value of new contracts entered into during the period.

                         
Source of Year-End Valuation Prices  
    Total     Maturity  
    Fair Value     Year 1     2-3 Years  
    (in thousands)  
Actively quoted
  $ 1,046     $ 564     $ 482  
External sources
    (157 )     (157 )      
Models and other methods
                 
 
Contracts end of year
  $ 889     $ 407     $ 482  
 

     These contracts are related primarily 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 energy cost management clause.

     Gains and losses on forward contracts for the sale of electricity that do not represent hedges are recognized in the statements of income as incurred. For the years ended December 31, 2004, 2003, and 2002, these amounts were not material.

     At December 31, 2004, the fair value of derivative energy contracts was reflected in the financial statements as follows:

         
    Amounts  
    (in thousands)  
Regulatory liabilities, net
  $ 1,361  
Other comprehensive income
    (481 )
Net income
    9  
 
Total fair value
  $ 889  
 

     Unrealized pre-tax gains and losses recognized in income were not material for any year presented. 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. See Notes 1 and 6 to the financial statements under “Financial Instruments” for additional information.

Capital Requirements and Contractual Obligations

The construction program of the Company is currently estimated to be $88 million for 2005, $95 million for 2006, and $90 million for 2007. Environmental expenditures included in these amounts are $6.3 million, $15.6 million, and $16.2 million for 2005, 2006, and 2007, 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 related to obligations associated with scheduled maturities of long-term debt and preferred securities, as well as the related interest, preferred stock dividends, leases, and other purchase commitments are as follows. See Notes 1, 6, and 7 to the financial statements for additional information.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2004 Annual Report

Contractual Obligations

                                         
  2006-     2008-     After        
    2005     2007     2009     2009     Total  
    (in thousands)  
Long-term debt and preferred
                                       
securities (a)
                                       
Principal
  $     $     $ 40,000     $ 238,777     $ 278,777  
Interest
    12,514       25,028       25,028       267,616       330,186  
Preferred stock dividends (b)
    1,733       3,466       3,466             8,665  
Operating leases
    31,353       62,386       61,255       62,926       217,920  
Purchase commitments (c)
                                       
Capital (d)
    87,754       185,591                   273,345  
Coal
    250,420       99,184                   349,604  
Natural Gas (e)
    109,676       126,434       11,876       48,207       296,193  
Long-term service agreements
    12,953       24,849       23,219       103,808       164,829  
Post retirement benefit trust (f)
    260       520                   780  
 
Total
  $ 506,663     $ 527,458     $ 164,844     $ 721,334     $ 1,920,299  
 

(a)   All amounts are reflected based on final maturity dates. The Company plans to 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, 2005, 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 $241 million, $300 million, and $232 million, respectively.

(d)   The Company forecasts capital expenditures over a three-year period. Amounts represent current estimates of total expenditures. At December 31, 2004, 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 Exchange future prices at December 31, 2004.

(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 and postretirement plans, including estimated benefit payments. Certain benefit payments will be made through the related trusts. Other benefit payments will be made from the Company’s corporate assets.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2004 Annual Report

Cautionary Statement Regarding Forward-Looking Statements

The Company’s 2004 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, retail sales growth, environmental regulations and expenditures, the Company’s projections for postretirement benefit trust contributions and estimated construction and other expenditures. 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 similar terminology. There are various factors that could cause actual results to differ materially from those suggested by in the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:

•   the impact of recent and future federal and state regulatory change, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, and also changes in environmental, tax, and other laws and regulations to which the Company is subject, as well as changes in application of existing laws and regulations;

•   current and future litigation, regulatory investigations, proceedings or inquiries;

•   the effects, extent and timing of the entry of additional competition in the markets in which the Company operates;

•   variations in demand for electricity and gas, including those relating to weather, the general economy and population, and business growth (and declines);

•   available sources and costs of fuels;

•   ability to control costs;

•   investment performance of the Company’s employee benefit plans;

•   advances in technology;

•   state and federal rate regulations and the impact of pending and future rate cases and negotiations;

•   internal restructuring or other restructuring options that may be pursued;

•   potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to the Company;

•   the ability of counterparties of the Company to make payments as and when due;

•   the ability to obtain new short- and long-term contracts with neighboring utilities;

•   the direct or indirect effect on the Company’s business resulting from terrorist incidents and the threat of terrorist incidents;

•   interest rate fluctuations and financial market conditions and the results of financing efforts, including the Company’s credit ratings;

•   the ability of the Company to obtain additional generating capacity at competitive prices;

•   catastrophic events such as fires, earthquakes, explosions, floods, hurricanes, or other similar occurrences;

•   the direct or indirect effects on the Company’s business resulting from incidents similar to the August 2003 power outage in the Northeast;

•   the effect of accounting pronouncements issued periodically by standard setting bodies; and

•   other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed by the Company from time to time with the SEC.

The Company expressly disclaims any obligation to update any forward-looking statements.

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STATEMENTS OF INCOME
For the Years Ended December 31, 2004, 2003, and 2002
Mississippi Power Company 2004 Annual Report

                         
 
    2004     2003     2002  
    (in thousands)  
Operating Revenues:
                       
Retail sales
  $ 584,313     $ 516,301     $ 536,827  
Sales for resale —
                       
Non-affiliates
    265,863       249,986       224,275  
Affiliates
    44,371       26,723       46,314  
Contract termination
          62,111        
Other revenues
    15,779       14,803       16,749  
 
Total operating revenues
    910,326       869,924       824,165  
 
Operating Expenses:
                       
Fuel
    320,997       229,251       282,393  
Purchased power —
                       
Non-affiliates
    33,528       18,523       18,550  
Affiliates
    73,235       74,674       32,783  
Other operations —
                       
Plant Daniel capacity
          60,300        
Other
    164,362       169,775       158,354  
Maintenance
    77,001       70,043       73,659  
Depreciation and amortization
    39,390       55,700       57,638  
Taxes other than income taxes
    55,572       53,991       55,518  
 
Total operating expenses
    764,085       732,257       678,895  
 
Operating Income
    146,241       137,667       145,270  
Other Income and (Expense):
                       
Interest income
    777       617       655  
Interest expense
    (11,776 )     (14,369 )     (18,650 )
Interest expense to affiliate trust
    (1,948 )            
Distributions on mandatorily redeemable preferred securities
    (630 )     (2,520 )     (3,016 )
Other income (expense), net
    (1,365 )     (568 )     (3,354 )
 
Total other income and (expense)
    (14,942 )     (16,840 )     (24,365 )
 
Earnings Before Income Taxes
    131,299       120,827       120,905  
Income taxes
    50,666       45,315       45,879  
 
Net Income
    80,633       75,512       75,026  
Dividends on Preferred Stock
    3,832       2,013       2,013  
 
Net Income After Dividends on Preferred Stock
  $ 76,801     $ 73,499     $ 73,013  
 

The accompanying notes are an integral part of these financial statements.

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STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2004, 2003, and 2002
Mississippi Power Company 2004 Annual Report

                         
 
    2004     2003     2002  
    (in thousands)  
Operating Activities:
                       
Net income
  $ 80,633     $ 75,512     $ 75,026  
Adjustments to reconcile net income to net cash provided from operating activities —
                       
Depreciation and amortization
    60,260       60,226       61,930  
Deferred income taxes and investment tax credits, net
    44,424       (7,632 )     (3,404 )
Plant Daniel capacity
    (16,508 )     60,300        
Pension, postretirement, and other employee benefits
    (1,084 )     (1,014 )     730  
Tax benefit of stock options
    1,532       2,323       1,826  
Other, net
    (1,700 )     1,402       2,017  
Changes in certain current assets and liabilities —
                       
Receivables, net
    (26,373 )     21,043       6,120  
Fossil fuel stock
    5,528       2,070       4,186  
Materials and supplies
    (3,768 )     (1,607 )     1,160  
Other current assets
    1,401       1,169       (13,346 )
Accounts payable
    (5,555 )     (20,602 )     18,487  
Accrued taxes
    151       (8,976 )     3,160  
Accrued compensation
    82       (2,568 )     5,570  
Over recovered regulatory clause revenues
    (25,761 )     694       22,384  
Other current liabilities
    6,052       3,264       6,816  
 
Net cash provided from operating activities
    119,314       185,604       192,662  
 
Investing Activities:
                       
Gross property additions
    (70,063 )     (69,345 )     (67,460 )
Cost of removal net of salvage
    (3,189 )     (5,811 )     (9,987 )
Other
    (2,826 )     (4,203 )     (3,471 )
 
Net cash used for investing activities
    (76,078 )     (79,359 )     (80,918 )
 
Financing Activities:
                       
Decrease in notes payable, net
                (15,973 )
Proceeds —
                       
Pollution control bonds
                42,625  
Senior notes
    40,000       90,000       80,000  
Mandatorily redeemable preferred securities
                35,000  
Preferred stock
    30,000              
Capital contributions from parent company
    1,791       4,912       16,198  
Redemptions —
                       
First mortgage bonds
          (33,350 )     (650 )
Pollution control bonds
          (850 )     (42,645 )
Senior notes
    (80,000 )     (86,628 )     (80,550 )
Mandatorily redeemable preferred securities
                (35,000 )
Preferred stock
    (28,388 )            
Payment of preferred stock dividends
    (1,829 )     (2,013 )     (2,013 )
Payment of common stock dividends
    (66,200 )     (66,000 )     (63,500 )
Other
    (785 )     (5,891 )     (1,491 )
 
Net cash used for financing activities
    (105,411 )     (99,820 )     (67,999 )
 
Net Change in Cash and Cash Equivalents
    (62,175 )     6,425       43,745  
Cash and Cash Equivalents at Beginning of Period
    69,120       62,695       18,950  
 
Cash and Cash Equivalents at End of Period
  $ 6,945     $ 69,120     $ 62,695  
 
Supplemental Cash Flow Information:
                       
Cash paid during the period for —
                       
Interest
  $ 12,084     $ 17,334     $ 17,743  
Income taxes (net of refunds)
    6,654       60,618       50,240  
 

The accompanying notes are an integral part of these financial statements.

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BALANCE SHEETS
At December 31, 2004 and 2003
Mississippi Power Company 2004 Annual Report

                 
 
Assets   2004     2003  
 
  (in thousands)  
Current Assets:
               
Cash and cash equivalents
  $ 6,945     $ 69,120  
Receivables —
               
Customer accounts receivable
    32,978       30,514  
Unbilled revenues
    20,803       19,278  
Under recovered regulatory clause revenues
    32,499       14,607  
Other accounts and notes receivable
    8,881       8,088  
Affiliated companies
    15,769       12,160  
Accumulated provision for uncollectible accounts
    (774 )     (897 )
Fossil fuel stock, at average cost
    19,704       25,233  
Vacation pay
    6,125       5,766  
Materials and supplies, at average cost
    27,438       23,670  
Assets from risk management activities
    4,471       2,672  
Prepaid income taxes
    5,814       27,415  
Prepaid expenses
    3,423       4,518  
Other
    3,193       766  
 
Total current assets
    187,269       242,910  
 
Property, Plant, and Equipment:
               
In service
    1,882,542       1,841,667  
Less accumulated provision for depreciation
    697,862       679,939  
 
 
    1,184,680       1,161,728  
Construction work in progress
    27,961       25,844  
 
Total property, plant, and equipment
    1,212,641       1,187,572  
 
Other Property and Investments
    7,272       4,404  
 
Deferred Charges and Other Assets:
               
Deferred charges related to income taxes
    10,668       11,358  
Prepaid pension costs
    19,158       18,167  
Unamortized debt issuance expense
    6,955       6,993  
Unamortized loss on reacquired debt
    9,437       10,201  
Prepaid rent
    12,874       14,758  
Other
    12,839       14,811  
 
Total deferred charges and other assets
    71,931       76,288  
 
Total Assets
  $ 1,479,113     $ 1,511,174  
 

The accompanying notes are an integral part of these financial statements.

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BALANCE SHEETS
At December 31, 2004 and 2003
Mississippi Power Company 2004 Annual Report

                 
 
Liabilities and Stockholder’s Equity   2004     2003  
    (in thousands)  
 
               
Current Liabilities:
               
Securities due within one year
  $     $ 80,000  
Accounts payable —
               
Affiliated
    19,568       21,259  
Other
    52,688       44,494  
Customer deposits
    9,053       11,863  
Accrued taxes —
               
Income taxes
    396       1,696  
Other
    44,285       42,834  
Accrued interest
    1,731       1,669  
Accrued vacation pay
    6,125       5,766  
Accrued compensation
    23,913       23,832  
Regulatory clauses over recovery
    5,356       31,118  
Plant Daniel capacity
    25,125        
Other
    18,196       14,394  
 
Total current liabilities
    206,436       278,925  
 
Long-term Debt (See accompanying statements)
    242,498       202,488  
 
Long-term Debt Payable to Affiliated Trust (See accompanying statements)
    36,082        
 
Mandatorily Redeemable Preferred Securities (See accompanying statements)
          35,000  
 
Deferred Credits and Other Liabilities:
               
Accumulated deferred income taxes
    167,345       142,088  
Deferred credits related to income taxes
    20,261       22,327  
Accumulated deferred investment tax credits
    18,654       19,841  
Employee benefit obligations
    57,275       54,830  
Plant Daniel lease guarantee obligation, at fair value
    10,990       14,758  
Plant Daniel capacity
    18,667       60,300  
Other cost of removal obligations
    76,228       73,378  
Miscellaneous regulatory liabilities
    9,522       7,595  
Other
    36,538       35,346  
 
Total deferred credits and other liabilities
    415,480       430,463  
 
Total Liabilities
    900,496       946,876  
 
Preferred Stock (See accompanying statements)
    32,780       31,809  
 
Common Stockholder’s Equity (See accompanying statements)
    545,837       532,489  
 
Total Liabilities and Stockholder’s Equity
  $ 1,479,113     $ 1,511,174  
 
Commitments and Contingent Matters (See notes)
               
 

The accompanying notes are an integral part of these financial statements.

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STATEMENTS OF CAPITALIZATION
At December 31, 2004 and 2003
Mississippi Power Company 2004 Annual Report

                                 
 
    2004     2003     2004     2003  
    (in thousands)     (percent of total)  
Long-Term Debt:
                               
First mortgage bonds — 6.875% due 2025
  $ 30,000     $ 30,000                  
 
Long-term notes payable —
                               
5.625% due May 1, 2033
    90,000       90,000                  
Adjustable rates (2.76% at 1/1/05) due 2009
    40,000       80,000                  
 
Total long-term notes payable
    130,000       170,000                  
 
Other long-term debt —
                               
Pollution control revenue bonds — non-collateralized:
                               
Variable rates (1.85% to 2.25% at 1/1/05) 2020-2028
    82,695       82,695                  
 
Unamortized debt premium (discount), net
    (197 )     (207 )                
 
Total long-term debt (annual interest requirement — $9.9 million)
    242,498       282,488                  
Less amount due within one year
          80,000                  
 
Long-term debt excluding amount due within one year
    242,498       202,488       28.3 %     25.2 %
 
Long-term Debt Payable to Affiliated Trust:
                               
7.20% due 2041 (annual interest requirement — $2.6 million)
    36,082             4.2       0.0  
 
Mandatorily Redeemable Preferred Securities:
                               
$25 liquidation value — 7.20% due 2041
          35,000       0.0       4.4  
 
Cumulative Preferred Stock:
                               
$100 par value 4.40% to 7.00% (annual dividend requirement — $1.7 million)
    32,780       31,809       3.8       4.0  
 
Common Stockholder’s Equity:
                               
Common stock, without par value —
                               
Authorized - 1,130,000 shares
                               
Outstanding - 1,121,000 shares in 2004 and 2003
    37,691       37,691                  
Paid-in capital
    295,837       292,841                  
Retained earnings
    215,893       203,419                  
Accumulated other comprehensive income (loss)
    (3,584 )     (1,462 )                
 
Total common stockholder’s equity
    545,837       532,489       63.7       66.4  
 
Total Capitalization
  $ 857,197     $ 801,786       100.0 %     100.0 %
 

The accompanying notes are an integral part of these financial statements.

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STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
For the Years Ended December 31, 2004, 2003, and 2002
Mississippi Power Company 2004 Annual Report

                                         
 
                            Other        
    Common     Paid-In     Retained     Comprehensive        
    Stock     Capital     Earnings     Income (loss)     Total  
    (in thousands)  
Balance at December 31, 2001
  $ 37,691     $ 267,582     $ 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       285,606       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       292,841       203,419       (1,462 )     532,489  
Net income after dividends on preferred stock
                76,801             76,801  
Capital contributions from parent company
          3,323                   3,323  
Other comprehensive income (loss)
                      (2,122 )     (2,122 )
Cash dividends on common stock
                (66,200 )           (66,200 )
Other
          (327 )     1,873             1,546  
 
Balance at December 31, 2004
  $ 37,691     $ 295,837     $ 215,893     $ (3,584 )   $ 545,837  
 

The accompanying notes are an integral part of these financial statements.

STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2004, 2003, and 2002
Mississippi Power Company 2004 Annual Report

                         
 
    2004     2003     2002  
 
 
                       
Net income after dividends on preferred stock
  $ 76,801     $ 73,499     $ 73,013  
 
Other comprehensive income (loss):
                       
Change in additional minimum pension liability, net of tax of $(1,131), $(123) and $(783), respectively
    (1,825 )     (198 )     (1,264 )
Change in fair value of marketable securities, net of tax of $49
    80              
Changes in fair value of qualifying hedges, net of tax of $(184)
    (297 )            
Less: Reclassification adjustment for amounts included in net income, net of tax of $(49)
    (80 )            
 
Total other comprehensive income (loss)
    (2,122 )     (198 )     (1,264 )
 
Comprehensive Income
  $ 74,679     $ 73,301     $ 71,749  
 

The accompanying notes are an integral part of these financial statements.

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Mississippi Power Company 2004 Annual Report

1.   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General

Mississippi Power Company (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 (SouthernLINC Wireless), 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, the Company, and Savannah Electric — provide electric service in four Southeastern states. The Company operates as a vertically integrated utility providing service to retail customers in Southwest 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. SouthernLINC Wireless 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 various other energy related businesses. Southern Nuclear operates and provides services to Southern Company’s nuclear power plants.

     The equity method is used for subsidiaries which are variable interest entities and for which the Company is not the primary beneficiary. Certain prior years’ data presented in the financial statements have been reclassified to conform to the current year presentation.

     Southern Company is registered as a holding company under the Public Utility Holding Company Act of 1935, as amended (PUHCA). Both Southern Company and its subsidiaries, including the Company, are subject to the regulatory provisions of PUHCA. The Company is also subject to regulation by the FERC and the Mississippi Public Service Commission (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.

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 transactions. Costs for these services amounted to $45.3 million, $46.1 million, and $43.8 million during 2004, 2003, and 2002, 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 $7.2 million, $6.6 million, and $6.4 million in 2004, 2003, and 2002, 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 $17.8 million, $17.7 million, and $16.6 million in 2004,

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Mississippi Power Company 2004 Annual Report

2003, and 2002, respectively. See Notes 4 and 5 for additional information on certain deferred tax liabilities payable to affiliates.

     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.

Revenues

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 the actual recoverable costs and amounts billed in current regulated rates.

     The Company has a diversified base of customers. For the year ended December 31, 2004 and December 31, 2002, no single customer or industry accounted for 10 percent or more of revenue. However, 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. For all periods presented, uncollectible accounts continued to average less than 1 percent of revenues.

Fuel Costs

Fuel costs are expensed as the fuel is used. Fuel expense includes the cost of purchased emission allowances as they are used.

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.

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Mississippi Power Company 2004 Annual Report

     Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to:

                         
    2004     2003     Note  
    (in thousands)  
Deferred income tax charges
  $ 11,358     $ 12,125       (a )
Property tax
    11,199       12,210       (b )
Vacation pay
    6,125       5,766       (c )
Loss on reacquired debt
    9,437       10,201       (d )
Loss on redeemed preferred stock
    1,086             (e )
Fuel-hedging asset
    2,666             (f )
Asset retirement obligations
    1,398       689       (a )
Property damage reserve
    (5,034 )     (6,796 )     (g )
Deferred income tax credits
    (21,789 )     (22,719 )     (a )
Other cost of removal obligations
    (76,228 )     (73,378 )     (a )
Plant Daniel capacity
    (43,792 )     (60,300 )     (h )
Fuel-hedging liabilities
    (4,027 )     (4,164 )     (f )
Other liabilities
    (142 )     (330 )     (g )
Total
  $ (107,743 )   $ (126,696 )        

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 fifty years. Asset retirement and removal liabilities will be settled and trued up following completion of the related activities.
 
(b)   Recovered through the ad valorem tax adjustment clause over a 12-month period beginning in April of the following year.
 
(c)   Recorded as earned by employees and recovered as paid, generally within one year.
 
(d)   Recovered over the remaining life of the original issue or, if refinanced, over the life of the new issue, which may range up to fifty years.
 
(e)   Amortized over a period beginning in 2004 that is not to exceed seven years.
 
(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, costs are recovered through the Energy Cost Management Clause (ECM).
 
(g)   Recorded and recovered or amortized as approved by the Mississippi PSC.
 
(h)   Amortized over a four-year period ending in 2007.

     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 currently 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 each of 2004, 2003, and 2002. When property subject to depreciation is retired or otherwise disposed of in the normal course of business, its cost — together with the cost of removal, less salvage — is charged to the accumulated depreciation provision. Minor items of property included in the original cost of the plant are retired when the related property unit is retired. Depreciation expense includes an amount for the expected cost of removal of facilities.

     In December 2003, the Mississippi PSC issued an interim accounting order directing the Company to expense and record a regulatory liability of $60.3 million while it considered the Company’s request to include 266 megawatts of Plant Daniel Units 3 and 4 generating capacity in jurisdictional cost of service. In May 2004, the Mississippi PSC approved the Company’s request effective January 1, 2004 and ordered the Company to amortize the regulatory liability previously established to earnings as follows: $16.5 million in 2004, $25.1 million in 2005, $13.0 million in 2006, and $5.7 million in 2007.

Asset Retirement Obligations and Other Costs of Removal

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 present value of the ultimate cost 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. Although 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 received accounting guidance from the Mississippi PSC allowing such treatment. Accordingly, the accumulated removal costs for other obligations previously accrued will continue to be reflected on the balance sheets as a

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Mississippi Power Company 2004 Annual Report

regulatory liability. 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, 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 statements of income 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:

                 
    2004     2003  
    (in millions)  
Balance, beginning of year
  $ 2.5     $  
Liabilities incurred
          2.4  
Liabilities settled
           
Accretion
    0.2       0.1  
Cash flow revisions
    2.8        
 
Balance, end of year
  $ 5.5     $ 2.5  
 

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 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 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.

Environmental Cost Recovery

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 may also incur substantial costs to clean up properties. The Company has authority from the Mississippi PSC to recover approved environmental compliance costs through retail rates.

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 or used.

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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 currently 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 of Southern Company’s common stock 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.

     The pro forma impact of fair-value accounting for options granted on earnings is as follows:

                 
    As     Pro  
Net Income   Reported     Forma  
    (in thousands)  
2004
  $ 76,801     $ 76,033  
2003
  $ 73,499     $ 72,680  
2002
  $ 73,013     $ 72,186  

     The estimated fair values of stock options granted in 2004, 2003, and 2002 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:

                         
    2004     2003     2002  
 
Interest rate
    3.1 %     2.7 %     2.8 %
Average expected life of stock options (in years)
    5.0       4.3       4.3  
Expected volatility of common stock
    19.6 %     23.6 %     26.3 %
Expected annual dividends on common stock
  $ 1.40     $ 1.37     $ 1.34  
Weighted average fair value of stock options granted
  $ 3.29     $ 3.59     $ 3.37  

Financial Instruments

The Company uses derivative financial instruments to limit exposure to 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 Mississippi PSC has approved the Company’s request to implement an Energy Cost Management clause (ECM) which, 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 has been approved by the Federal Energy Regulatory Commission (FERC).

     The Company is exposed to losses related to financial instruments in the event of counterparties’ nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company’s exposure to counterparty credit risk.

     Other financial instruments for which the carrying amount did not equal the fair value at December 31 were as follows:

                 
    Carrying     Fair  
    Amount     Value  
    (in thousands)  
Long-term debt:
               
At December 31, 2004
  $ 278,580     $ 282,884  
At December 31, 2003
  $ 282,488     $ 286,250  
Preferred securities:
               
At December 31, 2004
  $     $  
At December 31, 2003
  $ 35,000     $ 37,170  
 

     The fair values were based on either closing market price or closing price of comparable instruments. See “Variable Interest Entities” herein and Note 6 under “Mandatorily Redeemable Preferred Securities/Long-Term Debt Payable to Affiliated Trust” for further

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Mississippi Power Company 2004 Annual Report

information.

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 the Mississippi PSC and the FERC, the Company accrues for the cost of such damage through an annual expense accrual credited to a regulatory liability account. The cost of repairing actual damage resulting from such events that individually exceed $50,000 is charged to the reserve. The annual accruals may range from $1.5 million to $4.6 million with a maximum reserve totaling $23 million. The Company accrued $4.6 million in 2004, $2.5 million in 2003, and $1.8 million in 2002. As of December 31, 2004, the accumulated provision amounted to $5 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, changes in the fair value of qualifying cash flow hedges and marketable securities and changes in additional minimum pension liability, less income taxes, and reclassifications for amounts included in net income.

Variable Interest Entities

On March 31, 2004, the Company prospectively adopted FASB Interpretation No. 46R, “Consolidation of Variable Interest Entities,” which requires the primary beneficiary of a variable interest entity to consolidate the related assets and liabilities. The adoption of Interpretation No. 46R had no impact on the net income of the Company. However, as a result of the adoption, the Company deconsolidated a wholly-owned trust established to issue preferred securities since the Company is not the primary beneficiary of the trust. Therefore, the investments in this trust are reflected as Other Investments and the related loan from the trust are reflected as Long-term Debt Payable to Affiliated Trust on the balance sheets. This treatment resulted in a $1 million increase in both total assets and total liabilities as of December 31, 2004.

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 of 1974, as amended (ERISA), requirements. No contributions to the plan are expected for the year ending December 31, 2005. The Company also provides certain non-qualified benefit plans for a selected group of management and highly compensated employees. The Company provides certain medical care and life insurance benefits for retired employees. Benefits under these non-qualified plans are funded on a cash basis. In addition, trusts are funded to the extent required by the Mississippi PSC and the FERC. For the year ending December 31, 2005, postretirement trust contributions are expected to total approximately $260,000.

     The measurement date for plan assets and obligations is September 30 of each year.

Pension Plans

The accumulated benefit obligation for the pension plans was $211 million and $188 million for 2004 and 2003, 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  
    2004     2003  
    (in thousands)  
Balance at beginning of year
  $ 207,689     $ 186,443  
Service cost
    6,153       5,607  
Interest cost
    12,249       11,964  
Benefits paid
    (10,564 )     (9,317 )
Actuarial loss and employee transfers
    16,342       12,992  
Amendments
    789        
 
Balance at end of year
  $ 232,658     $ 207,689  
 

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Mississippi Power Company 2004 Annual Report

                 
    Plan Assets  
    2004     2003  
    (in thousands)  
Balance at beginning of year
  $ 210,285     $ 188,839  
Actual return on plan assets
    20,419       30,024  
Benefits paid
    (8,985 )     (8,512 )
Employee transfers
    824       (66 )
 
Balance at end of year
  $ 222,543     $ 210,285  
 

     Pension plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code of 1986, as amended (Internal 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     2004     2003  
 
Domestic equity
    37 %     36 %     37 %
International equity
    20       20       20  
Fixed income
    26       26       24  
Real estate
    10       10       11  
Private equity
    7       8       8  
 
Total
    100 %     100 %     100 %
 

     The reconciliations of the funded status with the accrued pension costs recognized in the balance sheets were as follows:

                 
    2004     2003  
    (in thousands)  
Funded status
  $ (10,115 )   $ 2,596  
Unrecognized transition obligation
    (1,090 )     (1,635 )
Unrecognized prior service cost
    14,423       15,004  
Unrecognized net gain (loss)
    8,315       (5,507 )
 
Prepaid pension asset, net
  $ 11,533     $ 10,458  
 

     The prepaid asset, net is reflected in the balance sheets in the following line items:

                 
    2004     2003  
    (in thousands)  
Prepaid pension asset
  $ 19,158     $ 18,167  
Employee benefit obligations
    (15,394 )     (11,839 )
Other property and investment-other
    2,445       1,762  
Accumulated other comprehensive income
    5,324       2,368  
 
Prepaid pension, net
  $ 11,533     $ 10,458  
 

     Components of the pension plans’ net periodic cost were as follows:

                         
    2004     2003     2002  
    (in thousands)  
Service cost
  $ 6,153     $ 5,607     $ 5,259  
Interest cost
    12,249       11,965       12,674  
Expected return on plan assets
    (18,325 )     (18,329 )     (18,380 )
Recognized net gain (loss)
    865       (1,847 )     (2,654 )
Net amortization
    (361 )     862       650  
 
Net pension income (expense)
  $ 581     $ (1,742 )   $ (2,451 )
 

     Future benefit payments reflect expected future service and are estimated based on assumptions used to measure the projected benefit obligation for the pension plans. At December 31, 2004, estimated benefit payments were as follows:

         
    2004  
    (in thousands)  
2005
  $ 10,216  
2006
    10,372  
2007
    10,483  
2008
    10,645  
2009
    11,108  
2010 to 2014
  $ 65,913  
 

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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  
    2004     2003  
    (in thousands)  
Balance at beginning of year
  $ 72,186     $ 61,168  
Service cost
    1,330       1,149  
Interest cost
    4,015       3,897  
Benefits paid
    (3,364 )     (2,813 )
Actuarial (gain) loss
    1,268       8,785  
Plan amendments
           
 
Balance at end of year
  $ 75,435     $ 72,186  
 
                 
    Plan Assets  
    2004     2003  
    (in thousands)  
Balance at beginning of year
  $ 18,185     $ 16,078  
Actual return on plan assets
    1,868       1,979  
Employer contributions
    3,494       2,941  
Benefits paid
    (3,364 )     (2,813 )
 
Balance at end of year
  $ 20,183     $ 18,185  
 

     Postretirement benefits plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal 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     2004     2003  
 
Domestic equity
    27 %     27 %     27 %
International equity
    15       15       15  
Fixed income
    45       45       45  
Real estate
    8       8       8  
Private equity
    5       5       5  
 
Total
    100 %     100 %     100 %
 

     The accrued postretirement costs recognized in the balance sheets were as follows:

                 
    Accrued Costs  
    2004     2003  
    (in thousands)  
Funded status
  $ (55,253 )   $ (54,001 )
Unrecognized transition obligation
    2,889       3,235  
Unrecognized prior service cost
    1,504       1,610  
Unrecognized net gain
    19,211       18,503  
Fourth quarter contributions
    779       926  
 
Accrued liability recognized in the Balance Sheets
  $ (30,870 )   $ (29,727 )

     Components of the postretirement plans’ net periodic cost were as follows:

                         
    Net Periodic Costs  
    2004     2003     2002  
    (in thousands)  
Service cost
  $ 1,330     $ 1,149     $ 959  
Interest cost
    4,015       3,898       3,781  
Expected return on plan assets
    (1,716 )     (1,598 )     (1,514 )
Transition obligation
    346       346       346  
Prior service cost
    106       106       106  
Recognized net loss
    408       116        
 
Net postretirement cost
  $ 4,489     $ 4,017     $ 3,678  
 

     In the third quarter 2004, the Company prospectively adopted FASB Staff Position (FSP) 106-2, Accounting and Disclosure Requirements related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (Medicare Act). The Medicare Act provides a 28 percent prescription drug subsidy for Medicare eligible retirees. FSP 106-2 requires recognition of the impacts of the Medicare Act in the accumulated postretirement benefit obligation (APBO) and future cost of service for postretirement medical plan. The effect of the subsidy reduced the Company’s expenses for the six months ended December 31, 2004 by approximately $.5 million and is expected to have a similar impact on future expenses. The subsidy’s impact on the postretirement medical plan APBO was a reduction of approximately $8 million. However, the ultimate impact on future periods is subject to federal regulations governing the subsidy created in the Medicare Act which are being finalized.

     Future benefit payments, including prescription drug benefits, reflect expected future service and are estimated based on assumptions used to measure the

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accumulated benefit obligation for the postretirement plans. Estimated benefit payments are reduced by drug subsidy receipts expected as a result of the Medicare Act as follows:

                         
    Benefit     Subsidy        
    Payments     Receipts     Total  
    (in thousands)  
2005
  $ 3,264     $     $ 3,264  
2006
    3,588       (422 )     3,166  
2007
    3,937       (465 )     3,472  
2008
    4,170       (503 )     3,667  
2009
    4,561       (547 )     4,014  
2010 to 2014
  $ 27,802     $ (3,371 )   $ 24,431  
 

     The weighted average rates assumed in the actuarial calculations for both the pension and postretirement benefits plans were as follows:

                         
    2004     2003     2002  
 
Discount
    5.75 %     6.00 %     6.50 %
Annual salary increase
    3.50       3.75       4.00  
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 11.0 percent for 2004, decreasing gradually to 5.0 percent through the year 2012, 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, 2004 as follows:

                 
    1 Percent  
    Increase     Decrease  
    (in thousands)  
Benefit obligation
  $ 6,456     $ 5,109  
Service and interest costs
    340       299  
 

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 2004, 2003, and 2002 were $2.8 million, $2.7 million, and $2.6 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 and Georgia Power alleging violations of the New Source Review (NSR) provisions of the Clean Air Act and related state laws at five coal-fired generating facilities. The EPA concurrently issued to each of the retail operating companies notices of violation relating to 10 generating facilities, which included 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.

     The U.S. District Court for the Northern District of Georgia subsequently granted Alabama Power’s motion to dismiss and denied the EPA’s motion to add the Company and Gulf Power for lack of jurisdiction in Georgia. In March 2001, the

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court granted the EPA’s motion to add Savannah Electric as a defendant. 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 civil complaints allege violations with respect to eight coal-fired generating facilities in Alabama and Georgia, and they request penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The EPA has not refiled against Gulf Power or the Company.

     The actions against Alabama Power, Georgia Power, and Savannah Electric were effectively stayed in the spring of 2001 during the appeal of a similar NSR enforcement action against the Tennessee Valley Authority (TVA) before the U.S. Court of Appeals for the Eleventh Circuit. In June 2003, the Court of Appeals issued its ruling in the TVA case, dismissing the appeal for reasons unrelated to the issues in the cases pending against Alabama Power, Georgia Power, and Savannah Electric. In May 2004, the U.S. Supreme Court denied the EPA’s petition for review of the case. In June 2004, the U.S. District Court for the Northern District of Alabama lifted the stay in the action against Alabama Power, placing the case back onto the court’s active docket. At this time, no party to the case against Georgia Power and Savannah Electric has sought to reopen that case, which remains administratively closed in the U.S. District Court for the Northern District of Georgia.

     Since the inception of the NSR proceedings against Alabama Power, Georgia 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. District courts addressing these cases have, to date, issued opinions that reached conflicting conclusions.

     The Company believes that it complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $32,500 per day, per violation at each generating unit, depending on the date of the alleged violation. 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.

     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 (RMRR) exclusion. A coalition of states and environmental organizations has filed petitions for review of these revisions with the U.S. Court of Appeals for the District of Columbia Circuit. The October 2003 RMRR rules have been stayed by the Court of Appeals pending its review of the rules. In any event, the final regulations must be adopted by the individual states in the Company’s service territory to apply to the Company’s facilities. The effect of these final regulations, related legal challenges, and potential state rulemakings cannot be determined at this time.

Generation Interconnection Agreements

In July 2003, the FERC issued its final rule on the standardization of generation interconnection agreements and procedures (Order 2003). Order 2003 shifts much of the financial burden of new transmission investment from the generator to the transmission provider. The FERC has indicated that Order 2003, which was effective January 20, 2004, is to be applied prospectively to interconnection agreements. The impact of Order 2003 and its subsequent rehearings on the Company and the final results of these matters cannot be determined at this time.

Market-Based Rate Authority

The Company has obtained FERC approval to sell power to nonaffiliates at market-based prices. 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

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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, the retail operating companies, and Southern Power, and found Southern Company and others to be “pivotal suppliers” in their retail service territories 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. In April 2004, the FERC issued an order that abandoned the SMA test and adopted a new interim analysis for measuring generation market power. This new interim approach requires utilities to submit a pivotal supplier screen and a wholesale market share screen. If the applicant does not pass both screens, there will be a rebuttable presumption regarding generation market power. The FERC’s order also sets forth procedures for rebutting these presumptions and addresses mitigation measures for those entities that are found to have market power. In the absence of specific mitigation measures, the order includes several cost-based mitigation measures that would apply by default. The FERC also initiated a new rulemaking proceeding that, among other things, will adopt a final methodology for assessing generation market power.

     In July 2004, the FERC denied Southern Company’s request for rehearing, along with a number of others, and reaffirmed the interim tests that it adopted in April 2004. In August 2004, Southern Company submitted a filing to the FERC which included results showing that Southern Company passed the pivotal supplier screen for all markets and the wholesale market share screen for all markets except its retail service territory. Southern Company also submitted other analyses to demonstrate that it lacks generation market power. On December 17, 2004, the FERC initiated a proceeding to assess Southern Company’s generation dominance within the Southern Company retail service territory. The ability to charge market-based rates in other markets is not at issue. As directed by this order, Southern Company submitted additional information on February 15, 2005 related to generation dominance in the Southern Company retail service territory. Any new market-based rate transactions in the Southern Company retail service territory entered into after February 27, 2005 will be subject to refund to the level of the default cost-based rates, pending the outcome of the proceeding. Southern Company, along with other utilities, has also filed an appeal of the FERC’s April and July 2004 orders with the U.S. Court of Appeals for the District of Columbia Circuit. The FERC has asked the court to dismiss the appeal on the grounds that it is premature.

     In the event that the FERC’s default mitigation measures are ultimately applied, the Company may be required to charge cost-based rates for certain wholesale sales in the Southern Company retail service territory, which may be lower than negotiated market-based rates. The final outcome of this matter will depend on the form in which the final methodology for assessing generation market power and mitigation rules may be ultimately adopted and cannot be determined at this time.

Right of Way Litigation

Southern Company and certain of its subsidiaries, including the Company, Georgia Power, Gulf Power, and Southern Telecom, have been named as defendants in numerous lawsuits brought by landowners since 2001. 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 exceed the easements or other property rights held by defendants. The Company has entered into an agreement with approximately one-third of the plaintiffs in the actions pending against the Company to clarify the Company’s easement rights in the State of Mississippi. This agreement has been approved by the Circuit Court of Harrison County, Mississippi (First Judicial District) and dismissals of the related cases are in progress. The remaining plaintiffs assert claims for, among other things, trespass and unjust enrichment, and seek compensatory and punitive damages and injunctive relief. Management of the Company believes that the Company 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 Alabama Power, Georgia Power, Gulf Power, the Company, Savannah Electric, and Southern Telecom, 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

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contractually obligated to indemnify, defend, and hold harmless the telecommunications company from any liability that may be assessed against it in pending and future right of way litigation. The Company believes that the plaintiff’s claims are without merit. In the fall of 2004, the trial court stayed the case until resolution of the underlying landowner litigation discussed above. On January 12, 2005, the Georgia Court of Appeals dismissed the telecommunications company’s appeal of the trial court’s order for lack of jurisdiction. 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’s retail base rates are set under Performance Evaluation Plan (PEP), a rate plan approved by the Mississippi PSC. 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: price, customer satisfaction, and service reliability.

     In May 2004, the Mississippi PSC approved the Company’s request to modify certain portions of its PEP and to reclassify, to jurisdictional cost of service the 266 megawatts of Plant Daniel Units 3 and 4 capacity, effective January 1, 2004. The Mississippi PSC authorized the Company to include the related costs and revenue credits in jurisdictional rate base, cost of service, and revenue requirement calculations for purposes of retail rate recovery. The Company is amortizing the regulatory liability established pursuant to the Mississippi PSC’s interim December 2003 accounting order, as approved in the May 2004 order, to earnings as follows: $16.5 million in 2004, $25.1 million in 2005, $13.0 million in 2006, and $5.7 million in 2007, resulting in increases to earnings in each of those years.

     In addition, the Mississippi PSC also approved the Company’s requested changes to PEP, including the use of a forward-looking test year, with appropriate oversight; annual, rather than semi-annual, filings; and certain changes to the performance indicator mechanisms. Rate changes will be limited to four percent of retail revenues annually under the revised PEP. The Mississippi PSC will review all aspects of PEP in 2007. PEP will remain in effect until the Mississippi PSC modifies, suspends, or terminates the plan. In December 2004, the Company filed its PEP for the projected 2005 test period. The results from the 2005 filing did not necessitate any change in rates.

Environmental Compliance Overview Plan

The Company’s Environmental Compliance Overview (ECO) Plan establishes procedures to facilitate the Mississippi PSC’s overview of the Company’s environmental strategy and provides for recovery of costs (including cost 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 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. In accordance with the Mississippi PSC order, the Company recovers such costs under the ECO Plan as they are incurred. The Company’s 2004 ECO Plan filing was approved, as filed, by the Mississippi PSC on March 15, 2004, and resulted in a slight decrease in rates effective April 2004.

Environmental Remediation

In 2003, the Texas Commission on Environmental Quality (TCEQ) designated the Company as a potentially responsible party at a site in Texas. The site was owned by an electric transformer company that handled the Company’s transformers as well as those of many other entities. 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 investigate and remediate the site. Amounts expensed during 2003 and 2004 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. The remediation expenses incurred by the

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Company are expected to be recovered through the Company’s ECO Plan.

4.   JOINT OWNERSHIP AGREEMENTS

The Company and Alabama Power own, as tenants in common, Units 1 and 2 with a total capacity of 500 megawatts 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 with a total capacity of 1,000 megawatts at Plant Daniel, which is located in Mississippi and operated by the Company.

     At December 31, 2004, the Company’s percentage ownership and investment in these jointly owned facilities were as follows:

                         
            Company’s        
Generating   Percent     Gross     Accumulated  
Plant   Ownership     Investment     Depreciation  
            (in thousands)  
Greene County
                       
Units 1 and 2
    40 %   $ 73,397     $ 38,396  
Daniel
                       
Units 1 and 2
    50 %   $ 251,702     $ 123,934  
 

     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 allocation agreement, as required by the PUHCA, each subsidiary’s current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more expense than would be paid if they filed a separate income tax return. In accordance with Internal Revenue Service regulations, each company is jointly and severally liable for the tax liability.

     In 2004, in order to avoid the loss of certain federal income tax credits related to the production of synthetic fuel, Southern Company chose to defer certain deductions otherwise available to the subsidiaries. The cash flow benefit associated with the utilization of the tax credits was allocated to the subsidiary that otherwise would have claimed the available deductions on a separate company basis without the deferral. This allocation concurrently reduced the tax benefit of the credits allocated to those subsidiaries that generated the credits. As the deferred expenses are deducted, the benefit of the tax credits will be repaid to the subsidiaries that generated the tax credits. The Company has recorded $3.6 million payable to these subsidiaries in “Accumulated Deferred Income Taxes” on the balance sheets.

     At December 31, 2004, the tax-related regulatory assets and liabilities were $11.4 million and $21.8 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 current enacted tax law and to unamortized investment tax credits.

     Details of the federal and state income tax provisions are shown below:

                         
    2004     2003     2002  
    (in thousands)  
Total provision for income taxes:
                       
Federal —
                       
Current
  $ 3,700     $ 46,116     $ 42,603  
Deferred
    40,350       (6,166 )     (3,122 )
 
 
    44,050       39,950       39,481  
 
State —
                       
Current
    2,542       7,761       6,680  
Deferred
    4,074       (2,396 )     (282 )
 
 
    6,616       5,365       6,398  
 
Total
  $ 50,666     $ 45,315     $ 45,879  
 

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     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:

                 
    2004     2003  
    (in thousands)  
Deferred tax liabilities:
               
Accelerated depreciation
  $ 183,692     $ 168,373  
Basis differences
    7,014       7,487  
Other
    63,414       46,689  
 
Total
    254,120       222,549  
 
Deferred tax assets:
               
Other property basis differences
    14,095       15,067  
Pension and other benefits
    12,198       10,722  
Property insurance
    3,928       2,599  
Unbilled fuel
    5,953       5,593  
Other
    53,886       68,257  
 
Total
    90,060       102,238  
 
Total deferred tax liabilities, net
    164,060       120,311  
Portion included in prepaid (accrued) income taxes, net
    3,285       21,777  
 
Accumulated deferred income taxes in the balance sheets
  $ 167,345     $ 142,088  
 

     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 $1.2 million in each year presented. At December 31, 2004, 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:

                         
    2004     2003     2002  
 
Federal statutory rate
    35.0 %     35.0 %     35.0 %
State income tax, net of federal deduction
    3.3       2.9       3.4  
Non-deductible book depreciation
    0.4       0.4       0.5  
Other
    (0.1 )     (0.8 )     (1.0 )
 
Effective income tax rate
    38.6 %     37.5 %     37.9 %
 

6.   FINANCING

Mandatorily Redeemable Preferred Securities/ Long-Term Debt Payable to Affiliated Trust

The Company has formed a 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 and are reflected on the balance sheets as Long-term Debt Payable to Affiliated 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, 2004, preferred securities of $35 million were outstanding. See Note 1 under “Variable Interest Entities” for additional information on the accounting treatment for the trust and the related securities.

Pollution Control Bonds

Pollution control obligations represent loans to the Company from public authorities of funds derived from sales by such authorities of revenue bonds issued to finance pollution control facilities. The Company is required to make payments sufficient for authorities to meet principal and interest requirements of such bonds. The amount of tax-exempt pollution control revenue bonds outstanding at December 31, 2004 was $82.7 million.

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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:

                 
    2004     2003  
    (in thousands)  
Bond improvement fund requirement
  $ 300     $ 300  
Less: Portion to be satisfied by certifying property additions
    300       300  
 
Cash sinking fund requirement
           
Current portion of other long-term debt
          80,000  
Pollution control bond cash sinking fund requirements
           
 
Total
  $     $ 80,000  
 

     The first mortgage bond improvement fund requirement is one percent of each outstanding series authenticated under the mortgage 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, reacquiring bonds, or by pledging additional property equal to 1 and 2/3 times such requirement.

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 satisfy obligations of Southern Company or any of its subsidiaries.

Bank Credit Arrangements

At the beginning of 2005, the Company had total committed credit agreements with banks for approximately $100.5 million, all of which were unused. These credit arrangements expire in 2005. The Company expects to renew its credit facilities, as needed, prior to expiration. 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.

     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 $100.5 million in unused credit arrangements provides required liquidity support to the Company’s borrowings through a commercial paper program. At December 31, 2004, the Company had no outstanding commercial paper or extendible commercial notes. During 2004, the peak amount outstanding for commercial paper was $59.9 million and the average amount outstanding was $21.5 million. The average annual interest rate on commercial paper was 1.30 percent in 2004. The credit arrangements also provide support to the Company’s variable daily rate tax-exempt pollution control bonds.

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 Mississippi PSC. The Company enters into hedges of forward electricity sales. There was no material ineffectiveness recorded in earnings in 2004 and 2003.

     At December 31, 2004, the fair value of derivative energy contracts was reflected in the financial statements as follows:

         
    Amounts  
    (in thousands)  
Regulatory liabilities, net
  $ 1,361  
Other comprehensive income
    (481 )
Net income
    9  
 
Total fair value
  $ 889  
 

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NOTES TO FINANCIAL STATEMENTS (continued)
Mississippi Power Company 2004 Annual Report

     The fair value gains or losses for cash flow hedges are recorded as regulatory assets and liabilities if they are recoverable through the regulatory clauses, otherwise they are recorded in other comprehensive income, and are recognized in earnings at the same time the hedged items affect earnings. For the year 2005, approximately $0.5 million of pre-tax losses are expected to be reclassified from other comprehensive income to fuel expense. The Company has energy-related hedges in place up to and including 2007.

Common Stock Dividend Restrictions

The Company’s first mortgage bond indenture and the corporate charter contain various common stock dividend restrictions. At December 31, 2004, 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 $88 million in 2005, $95 million in 2006, and $90 million in 2007. The construction program is subject to periodic review and revision, and actual construction costs may vary from the above estimates because of numerous factors. These factors include changes in business conditions; acquisition of additional generation 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. At December 31, 2004, 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 leased 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.

     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 $9 million, $6 million, and $11 million for 2004, 2003, and 2002, respectively, which is included in maintenance expense in the statements of income. Remaining payments to GE under this agreement are currently estimated to total $160 million over the next 13 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 $4.9 million over the remaining term of the agreement, which is approximately two 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.

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NOTES TO FINANCIAL STATEMENTS (continued)
Mississippi Power Company 2004 Annual Report

Fuel 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. Coal commitments include forward contract purchases for carbon dioxide emission allowances. 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 Exchange future prices at December 31, 2004. Total estimated minimum long-term obligations at December 31, 2004 were as follows:

                 
Year   Natural Gas     Coal  
    (in thousands)  
2005
  $ 109,676     $ 250,420  
2006
    78,730       71,768  
2007
    47,704       27,416  
2008
    5,938        
2009
    5,938        
2010 and there after
    48,207        
 
Total commitments
  $ 296,193     $ 349,604  
 

     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. In 2004, the Company entered into a three-year operating lease agreement for the use of 120 aluminum railcars. All of these leases are for the transport of coal to Plant Daniel.

     Gulf Power, as joint owner of Plant Daniel Units 1 and 2, is responsible for one half of the lease costs. The Company’s share (50%) of the leases, charged to fuel stock and recovered through the ECM, was $1.9 million annually in 2004, 2003, and 2002. The Company’s annual lease payments for 2005 through 2009 will average approximately $2.3 million and after 2009, lease payments total in aggregate approximately $6.2 million.

Plant Daniel Combined Cycle Generating Units

In May 2001, the Company began the initial 10-year term of the lease agreement 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 Mississippi PSC. 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 Matters” for a description of PEP, the Company’s 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. The Company is not required to consolidate the leased assets and related liabilities, and the lease with

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NOTES TO FINANCIAL STATEMENTS (continued)
Mississippi Power Company 2004 Annual Report

Juniper is considered an operating lease. 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. A liability of approximately $13 million for the fair market value of this residual value guarantee is included in the balance sheets. In 2003, approximately $11 million in lease termination costs and were included in other operation expense. Lease expenses were $27 million, $26 million, and $26 million in 2004, 2003, and 2002, respectively.

     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, 2004, are as follows:

         
Year   Lease Payments  
    (in thousands)  
2005
  $ 28,931  
2006
    28,824  
2007
    28,718  
2008
    28,616  
2009
    28,504  
2010 and thereafter
    56,688  
 
Total commitments
  $ 200,281  
 

8.   STOCK OPTION PLAN

Southern Company provides non-qualified stock options to a large segment of the Company’s employees ranging from line management to executives. As of December 31, 2004, 266 current and former employees of the Company participated in the stock option plan. The maximum number of shares of Southern Company common stock that may be issued under this plan may not exceed 55 million. The prices of options granted to date have been at the fair market value of the shares on the dates of grant. Options granted to date become exercisable pro rata over a maximum period of three years from the date of grant. Options outstanding will expire no later than 10 years after the date of grant, unless terminated earlier by the Southern Company Board of Directors in accordance with the stock option plan. Activity from 2002 to 2004 for the options granted to the Company’s employees under the stock option plan is summarized below:

                 
    Shares     Average  
    Subject     Option Price  
    To Option     Per Share  
 
Balance at December 31, 2001
    1,322,666     $ 17.54  
Options granted
    375,553       25.26  
Options canceled
    (4,248 )     23.52  
Options exercised
    (209,962 )     14.83  
 
Balance at December 31, 2002
    1,484,009       19.86  
Options granted
    336,450       27.98  
Options canceled
    (2,882 )     24.64  
Options exercised
    (269,753 )     16.35  
 
Balance at December 31, 2003
    1,547,824       22.23  
Options granted
    309,043       29.50  
Options canceled
    (1,395 )     19.87  
Options exercised
    (260,061 )     17.00  
 
Balance at December 31, 2004
    1,595,411     $ 24.49  
                 
Options exercisable:
 
At December 31, 2002
    625,585          
At December 31, 2003
    794,374          
At December 31, 2004
    1,019,627          

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NOTES TO FINANCIAL STATEMENTS (continued)
Mississippi Power Company 2004 Annual Report

     The following table summarizes information about options outstanding at December 31, 2004:

                         
    Dollar Price  
    Range of Options  
    13-20     20-26     26-32  
 
Outstanding:
                       
Shares (in thousands)
    360,368       595,638       639,405  
Average remaining life (in years)
    5.6       6.8       8.6  
Average exercise price
  $ 17.70     $ 24.07     $ 28.71  
Exercisable:
                       
Shares (in thousands)
    360,368       497,176       162,083  
Average exercise price
  $ 17.70     $ 23.84     $ 28.18  
 

9.   QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

Summarized quarterly financial data for 2004 and 2003 are as follows:

                         
                    Net Income  
                    After Dividends  
    Operating     Operating     On Preferred  
Quarter Ended   Revenues     Income     Stock  
    (in thousands)  
March 2004
  $ 209,728     $ 31,600     $ 17,319  
June 2004
    232,785       43,290       21,891  
September 2004
    258,564       61,744       35,581  
December 2004
    209,249       9,607       2,010  
 
                       
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 )
 

     The Company’s business is influenced by seasonal weather conditions. During the second quarter of 2003, the Company recorded $62 million of contract termination revenues, as a result of the termination of a contract with a subsidiary of Dynegy. During the fourth quarter of 2003, the Company recorded a $60 million expense related to the establishment of a regulatory liability in connection with an accounting order issued by the Mississippi PSC. See Note 3 under “Retail Regulatory Matters” for additional information.

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SELECTED FINANCIAL AND OPERATING DATA 2000-2004
Mississippi Power Company 2004 Annual Report

                                         
 
    2004     2003     2002     2001     2000  
 
Operating Revenues (in thousands)
  $ 910,326     $ 869,924     $ 824,165     $ 796,065     $ 687,602  
Net Income after Dividends on Preferred Stock (in thousands)
  $ 76,801     $ 73,499     $ 73,013     $ 63,887     $ 54,972  
Cash Dividends on Common Stock (in thousands)
  $ 66,200     $ 66,000     $ 63,500     $ 50,200     $ 54,700  
Return on Average Common Equity (percent)
    14.24       13.99       14.46       14.25       13.80  
Total Assets (in thousands)
  $ 1,479,113     $ 1,511,174     $ 1,482,040     $ 1,411,050     $ 1,341,470  
Gross Property Additions (in thousands)
  $ 70,063     $ 69,345     $ 67,460     $ 61,193     $ 81,211  
 
Capitalization (in thousands) :
                                       
Common stock equity
  $ 545,837     $ 532,489     $ 517,953     $ 491,680     $ 404,898  
Preferred stock
    32,780       31,809       31,809       31,809       31,809  
Mandatorily redeemable preferred securities
          35,000       35,000       35,000       35,000  
Long-term debt payable to affiliated trust
    36,082                          
Long-term debt
    242,498       202,488       243,715       233,753       370,511  
 
Total (excluding amounts due within one year)
  $ 857,197     $ 801,786     $ 828,477     $ 792,242     $ 842,218  
Capitalization Ratios (percent) :
                                       
Common stock equity
    63.7       66.4       62.5       62.1       48.1  
Preferred stock
    3.8       4.0       3.8       4.0       3.8  
Mandatorily redeemable preferred securities
          4.4       4.2       4.4       4.2  
Long-term debt payable to affiliated trust
    4.2                          
Long-term debt
    28.3       25.2       29.5       29.5       43.9  
 
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+       A+  
Fitch
    AA       AA-       AA-       AA-       AA-  
Preferred Stock -
                                       
Moody’s
    A3       A3       A3       A3       a1  
Standard and Poor’s
    BBB+       BBB+       BBB+       BBB+       BBB+  
Fitch
    A+       A       A       A       A  
Unsecured Long-Term Debt -
                                       
Moody’s
    A1       A1       A1       A1        
Standard and Poor’s
    A       A       A       A        
Fitch
    AA-       A+       A+       A+        
 
Customers (year-end) :
                                       
Residential
    160,189       159,582       158,873       158,852       158,253  
Commercial
    33,646       33,135       32,713       32,538       32,372  
Industrial
    522       520       489       498       517  
Other
    183       171       171       173       206  
 
Total
    194,540       193,408       192,246       192,061       191,348  
 
Employees (year-end) :
    1,283       1,290       1,301       1,316       1,319  
 

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SELECTED FINANCIAL AND OPERATING DATA 2000-2004 (continued)
Mississippi Power Company 2004 Annual Report

                                         
 
    2004     2003     2002     2001     2000  
 
Operating Revenues (in thousands) :
                                       
Residential
  $ 199,242     $ 180,978     $ 186,522     $ 164,716     $ 170,729  
Commercial
    199,127       175,416       181,224       163,253       163,552  
Industrial
    180,516       154,825       164,042       156,525       159,705  
Other
    5,428       5,082       5,039       4,659       4,565  
 
Total retail
    584,313       516,301       536,827       489,153       498,551  
Sales for resale — non-affiliates
    265,863       249,986       224,275       204,623       145,931  
Sales for resale — affiliates
    44,371       26,723       46,314       85,652       27,915  
 
Total revenues from sales of electricity
    894,547       793,010       807,416       779,428       672,397  
Other revenues
    15,779       76,914       16,749       16,637       15,205  
 
Total
  $ 910,326     $ 869,924     $ 824,165     $ 796,065     $ 687,602  
 
Kilowatt-Hour Sales (in thousands) :
                                       
Residential
    2,297,110       2,255,445       2,300,017       2,162,623       2,286,143  
Commercial
    2,969,829       2,914,133       2,902,291       2,840,840       2,883,197  
Industrial
    4,235,290       4,111,199       4,161,902       4,275,781       4,376,171  
Other
    40,229       39,890       39,635       41,009       41,153  
 
Total retail
    9,542,458       9,320,667       9,403,845       9,320,253       9,586,664  
Sales for resale — non-affiliates
    6,027,666       5,874,724       5,380,145       5,011,212       3,674,621  
Sales for resale — affiliates
    1,053,471       709,065       1,586,968       2,952,455       452,611  
 
Total
    16,623,595       15,904,456       16,370,958       17,283,920       13,713,896  
 
Average Revenue Per Kilowatt-Hour (cents) :
                                       
Residential
    8.67       8.02       8.11       7.62       7.47  
Commercial
    6.70       6.02       6.24       5.75       5.67  
Industrial
    4.26       3.77       3.94       3.66       3.65  
Total retail
    6.12       5.54       5.71       5.25       5.20  
Sales for resale
    4.38       4.20       3.88       3.64       4.21  
Total sales
    5.38       4.99       4.93       4.51       4.90  
Residential Average Annual Kilowatt-Hour Use Per Customer
    14,357       14,161       14,453       13,634       14,445  
Residential Average Annual Revenue Per Customer
  $ 1,245     $ 1,136     $ 1,172     $ 1,038     $ 1,079  
Plant Nameplate Capacity Ratings (year-end) (megawatts)
    3,156       3,156       3,156       3,156       2,086  
Maximum Peak-Hour Demand (megawatts) :
                                       
Winter
    2,173       2,458       2,311       2,249       2,305  
Summer
    2,427       2,330       2,492       2,466       2,593  
Annual Load Factor (percent)
    62.4       60.5       61.8       60.7       59.3  
Plant Availability Fossil-Steam (percent):
    91.4       92.6       91.7       92.8       92.6  
 
Source of Energy Supply (percent) :
                                       
Coal
    55.7       57.7       50.8       52.0       67.8  
Oil and gas
    25.5       19.9       37.7       35.9       13.5  
Purchased power -
                                       
From non-affiliates
    6.4       3.5       3.1       3.1       7.7  
From affiliates
    12.4       18.9       8.4       9.0       11.0  
 
Total
    100.0       100.0       100.0       100.0       100.0  
 

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SAVANNAH ELECTRIC AND POWER COMPANY

 
 
 
FINANCIAL SECTION
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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, 2004 and 2003, 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, 2004. 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.

     We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (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 consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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-287 to II-311) present fairly, in all material respects, the financial position of Savannah Electric and Power Company at December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.

     As discussed in Note 9 to the financial statements, the 2003 and 2002 financial statements have been restated.

     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
February 28, 2005

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION
Savannah Electric and Power Company 2004 Annual Report

OVERVIEW

Business Activities

Savannah Electric and Power Company (the Company) operates as a vertically integrated utility providing electricity to retail customers within its traditional service area of southeastern Georgia.

     Many 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 more stringent environmental standards. In 2004, the Company filed a retail rate case and completed a retail fuel cost recovery rate case. These regulatory actions were initiated to help enable the recovery of substantial capital investments in generating plant, to facilitate the continued reliability of the transmission and distribution network, and to allow for the recovery of increasing fuel costs. The Georgia Public Service Commission (PSC) is expected to rule on the Company’s base rate increase request in May 2005.

Restatement

See Note 9 to the financial statements for information regarding the Company’s restatement of its financial statements for the years ended December 31, 2003 and 2002 and for the quarters ended March 31, June 30, and September 30, 2004 and 2003, as well as quarterly financial information for the quarter ended December 31, 2003. The restatement also affects periods prior to 2002. These restatements were a result of errors in the Company’s estimates of unbilled revenues in these periods. All amounts herein reflect the effects of these restatements. For further information on the estimates of unbilled revenues, also see ACCOUNTING POLICIES – “Application of Critical Accounting Policies and Estimates – Unbilled Revenues” herein.

Key Performance Indicators

In striving to maximize shareholder value while providing low-cost energy to more than 143,000 customers, the Company focuses on several key indicators. These indicators include customer satisfaction, peak season equivalent forced outage rate (Peak Season EFOR), and return on equity (ROE). The Company’s financial success is directly tied to the satisfaction of its customers. Key elements of ensuring customer satisfaction include outstanding service, high reliability and competitive prices. Management uses nationally recognized independent customer satisfaction surveys and reliability indicators to evaluate the Company’s results. Peak Season EFOR is an indicator of plant availability and efficient generation fleet operations during the months when generation needs are greatest. The rate is calculated by dividing the number of hours of forced outages by total generation hours. ROE is a performance standard used by both the investment community and many regulatory agencies. The Company’s 2004 results compared to its targets for each of these indicators are reflected in the following chart.

                         
 
  Key     2004     2004  
  Performance     Target     Actual  
  Indicator     Performance     Performance  
 
Customer Satisfaction
    Top quartile in national and regional surveys     Top quartile  
 
Peak Season EFOR
    3.64% or less       2.29 %  
 
ROE
      12.4 %       11.7 %  
 

     Management focuses on these indicators and employees are committed to achieving or exceeding management’s expectations. The financial performance achieved in 2004 was adversely affected by the purchase of the Plant McIntosh Combined Cycle Units 10 and 11 construction project and a related cost disallowance by the Georgia PSC. See Note 3 under “Plant McIntosh Construction Project” for additional information.

Earnings

The Company’s net income after preferred stock dividends for 2004 totaled $24.2 million, representing an increase of $0.8 million, or 3.3 percent, from the prior year. Higher operating revenues were somewhat offset by higher operating expenses and higher interest expenses. Earnings were $23.5 million in 2003, reflecting an increase of $2.1 million, or 10.0 percent, from the prior year. Higher operating revenues, lower depreciation and amortization expenses, and lower interest expenses were somewhat offset by higher operating expenses and income taxes. In 2002, earnings were $21.3 million, representing a decrease of $0.2

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million, or 0.8 percent, from the prior year.

RESULTS OF OPERATIONS

A condensed income statement is as follows:

                                 
            Increase (Decrease)  
    Amount     from Prior Year  
    2004     2004     2003     2002  
    (in thousands)  
Operating revenues
  $ 356,960     $ 41,843     $ 18,111     $ 14,080  
 
Fuel
    55,721       413       353       4,159  
Purchased power
    125,674       36,169       13,901       2,518  
Other operation and maintenance
    85,965       2,344       2,603       10,525  
Depreciation and amortization
    21,252       753       (2,205 )     (3,247 )
Taxes other than income taxes
    15,245       580       208       473  
 
Total operating expenses
    303,857       40,259       14,860       14,428  
 
Operating income
    53,103       1,584       3,251       (348)  
Total other income and (expense)
    (12,993 )     (451 )     2,959       247  
Income taxes
    14,378       (1,140 )     4,070       75  
 
Net income
    25,732       2,273       2,140       (176)  
Dividends on preferred stock
    1,500       1,500              
 
Net income after dividends on preferred stock
  $ 24,232     $ 773     $ 2,140     $ (176 )
 

Revenues

     Details of operating revenues are as follows:

                         
    Amount  
    2004     2003     2002  
    (in thousands)  
Retail — prior year
  $ 298,807     $ 283,225     $ 268,246  
Change in —
                       
Base rates
          2,799       5,101  
Sales growth
    9,497       2,084       7,109  
Weather
    10       (263 )     2,397  
Fuel cost recovery and other
    33,452       10,962       372  
 
Retail — current year
    341,766       298,807       283,225  
 
Sales for resale —
                       
Non-affiliates
    5,035       5,653       6,354  
Affiliates
    6,130       6,499       4,075  
 
Total sales for resale
    11,165       12,152       10,429  
 
Other operating revenues
    4,029       4,158       3,352  
 
Total operating revenues
  $ 356,960     $ 315,117     $ 297,006  
 
Percent change
    13.3 %     6.1 %     5.0 %
 

     Total operating revenues for 2004 were $357.0 million, reflecting a 13.3 percent increase when compared to 2003. Retail revenues increased 14.4 percent, or $43.0 million, in 2004, increased 5.5 percent, or $15.6 million, in 2003, and increased 5.6 percent, or $15.0 million, in 2002. Retail base rates increased in 2003 and 2002 reflecting the Georgia PSC decision effective June 2002.

     On November 30, 2004, the Company filed a traditional one-year rate case with the Georgia PSC requesting a $23.2 million, or 6.7 percent, increase in retail revenues, effective January 1, 2005. See Note 3 to the financial statements under “Retail Regulatory Matters” for additional information on the Company’s 2002 rate order and 2004 retail rate case filing.

     Electric rates include provisions to adjust billings for fluctuations in fuel costs, the energy component of

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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. The Georgia PSC approved a Fuel Cost Recovery (FCR) rate increase that became effective in November 2004. See Note 3 to the financial statements under “Retail Regulatory Matters” for additional information on the Company’s rate orders.

     Revenues from sales to non-affiliated utilities are primarily energy related. These sales decreased 10.9 percent in 2004, decreased 11.0 percent in 2003, and decreased 28.5 percent in 2002 primarily due to fluctuations in off-system sale transactions that were generally offset by corresponding purchase transactions. 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 affiliated sales are made in accordance with the affiliate company interchange agreement, as approved by the Federal Energy Regulatory Commission (FERC). 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 2004 and the percent change by year were as follows:

                                 
    KWH     Percent Change  
    2004     2004     2003   2002  
    (in millions)                          
Residential
    1,899       8.3 %     (0.1 )%     6.5 %
Commercial
    1,540       5.4       0.4       5.4  
Industrial
    841       (2.4 )     8.8       0.9  
Other
    142       4.1       (0.5 )     3.5  
 
                             
Total retail
    4,422       5.0       1.8       4.9  
Sales for resale —
                               
Non-affiliates
    131       (19.2 )     7.7       35.7  
Affiliates
    143       (22.9 )     47.1       43.4  
 
                             
Total
    4,696       3.0 %     3.3 %     6.6 %
 

     In 2004, residential and commercial energy sales increased from the prior year primarily due to continued customer growth. Industrial sales were lower because of lower usage by several industrial customers due to cogeneration and cutbacks in production.

     In 2003, residential 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 customer classes benefited from continued customer growth. In 2002, residential and commercial energy sales increased from the prior year reflecting the positive impact of weather and continued customer growth. Industrial sales increased, reflecting customer growth, and were somewhat offset by a general economic slowdown.

     Energy sales to retail customers are projected to increase at a compound average growth rate of 2.2 percent during the period 2005 through 2009.

Expenses

Fuel and Purchased Power 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 generation units.

     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:

                         
    2004     2003     2002  
Total generation
(millions of KWHs)
    2,135       2,325       2,249  
Sources of generation (percent) —
                       
Coal
    96       94       91  
Oil
    1       2       1  
Gas
    3       4       8  
Average cost of fuel per net KWH generated (cents)
    2.61       2.38       2.44  
Total purchased power (millions of KWHs)
    2,829       2,581       2,379  
Average cost of purchased power per net KWH (cents)
    4.44       3.47       3.18  
 

     Fuel expense increased 0.7 percent due to a 9.7 percent increase in the average cost of fuel per net KWH generated that more than offset an 8.2 percent decrease in

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generation in 2004. The average cost of fuel per net KWH generated increased for coal and oil and decreased for gas in 2004. In 2003, fuel expense increased 0.6 percent due to a slight increase in generation offset somewhat by a lower cost of coal. In 2002, fuel expense increased 8.2 percent due to increased gas usage and a higher cost of coal.

     Purchased power expense increased $36.2 million, or 40.4 percent, in 2004 due to increased energy demands and higher energy costs. In 2003, purchased power expense increased $13.9 million, or 18.4 percent, due to increased energy demands and a purchased power agreement (PPA) 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 PPA discussed above. 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.

     A significant upward trend in the cost of coal and natural gas has emerged since 2003, and volatility in these markets is expected to continue. Increased coal prices have been influenced by a worldwide increase in demand as a result of rapid economic growth in China as well as by increases in mining costs. Higher natural gas prices in the United States are the result of slightly lower gas supplies despite increased drilling activity. Natural gas supply interruptions, such as those caused by the 2004 hurricanes, result in an immediate market response, however, the impact of this price volatility may be reduced by imports of natural gas and liquefied natural gas. Fuel expenses generally do not affect net income, since they are offset by fuel revenues under the Company’s fuel cost recovery provisions.

Other Operating Expenses

Other operation and maintenance expenses increased $2.3 million, or 2.8 percent, in 2004 as a result of a $2.8 million increase in administrative and general expenses primarily relating to accounting and auditing services and employee benefits expense, and a $0.6 million increase in distribution expenses partially offset by a decrease of $1.4 million in maintenance expense due mainly to a scheduled turbine maintenance outage at Plant Kraft in 2003.

     In 2003, other operation and maintenance expenses increased $2.6 million, or 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 $10.5 million, or 14.9 percent. Increased other operation expense reflected 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 $5.4 million 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.

     In 2004, depreciation and amortization increased $0.8 million, or 3.7 percent, due to an increase in depreciable property. Depreciation and amortization decreased $2.2 million, or 9.7 percent, in 2003 and $3.2 million, or 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 Georgia PSC rate order. See Note 3 to the financial statements under “Retail Regulatory Matters” for additional information.

Non-Operating Expenses

Interest expense and preferred dividends increased $4.0 million, or 41.3 percent, in 2004 primarily related to an increase in senior notes and preferred stock outstanding.

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These increases were partially offset by a decrease in distributions on mandatorily redeemable preferred securities due to the retirement of $40 million of mandatorily redeemable preferred securities. Interest expense decreased $2.0 million, or 17.4 percent, in 2003 primarily as a result of a lower principal amount of debt outstanding during the year. In 2002, interest expense decreased $0.9 million, or 7.3 percent. Lower interest rates in 2003 and 2002 contributed to lower expenses in those years. See FINANCIAL CONDITION AND LIQUIDITY – “Financing Activities” herein for additional information.

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 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 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 Georgia PSC 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 FERC. Retail rates and earnings are reviewed and adjusted periodically within certain limitations based on ROE. See ACCOUNTING POLICIES – “Application of Critical Accounting Policies and Estimates – Electric Utility Regulation” herein and Note 3 to the financial statements for additional information about these and other regulatory matters.

     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 that affect the opportunities, challenges, and risks of the Company’s primary 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 more stringent 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.

     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).

Environmental Matters

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 and Georgia Power. 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 and related state laws with respect to 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 were effectively stayed in the spring of 2001 pending the appeal of a similar NSR action against the Tennessee Valley Authority before the U.S. Court of Appeals for the Eleventh Circuit. In June 2004, following the final

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resolution of the appeal, the U.S. District Court for the Northern District of Alabama lifted the stay in the action against Alabama Power, placing the case back onto the court’s active docket. At this time, no party to the case against Georgia Power and the Company has sought to reopen that case, which remains administratively closed in the U.S. District Court for the Northern District of Georgia. See Note 3 to the financial statements under “New Source Review Actions” for additional information.

     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 maximum civil penalties of $25,000 to $32,500 per day, per violation at each generating unit, depending on the date of the alleged violation. 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.

     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 (RMRR) exclusion. A coalition of states and environmental organizations has filed petitions for review of these revisions with the U.S. Court of Appeals for the District of Columbia Circuit. The October 2003 RMRR rules have been stayed by the court of appeals pending its review of the rules. In any event, the final regulations must also be adopted by the State of Georgia in order to apply to the Company’s facilities. The effect of these final regulations, related legal challenges, and potential state rulemakings cannot be determined at this time.

Carbon Dioxide Litigation

On July 21, 2004, attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel for New York City filed a complaint in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. A nearly identical complaint was filed by three environmental groups in the same court. The complaints allege that the companies’ emissions of carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs assert is a public nuisance. Under common law public and private nuisance theories, the plaintiffs seek a judicial order (1) holding each defendant jointly and severally liable for creating, contributing to, and/or maintaining global warming and (2) requiring each of the defendants to cap its emissions of carbon dioxide and then reduce those emissions by a specified percentage each year for at least a decade. Plaintiffs have not, however, requested that damages be awarded in connection with their claims. Southern Company believes these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. Southern Company and the other defendants have filed motions to dismiss both lawsuits. Southern Company intends to vigorously defend against these claims. While the outcome of these matters cannot be determined at this time, an adverse judgment in either of these actions could result in substantial capital expenditures.

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 involves 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 discussed under FINANCIAL CONDITION AND LIQUIDITY — “Capital Requirements and Contractual Obligations” herein. There is no assurance, however, that all such costs will, in fact, be recovered.

     Compliance with the 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 and resulted in total construction expenditures of approximately $2 million through 2000.

     To help attain the one-hour ozone standard, the EPA

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issued regional nitrogen oxide reduction rules in 1998. Those rules 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 could be applied in Georgia. In April 2004, the EPA published final regional nitrogen oxide reduction rules applicable to Georgia, specifying a May 1, 2007 compliance date. However, in October 2004, the EPA announced that it would stay implementation of the rule as it relates to Georgia, while it initiates rulemakings to address issues raised in a petition for reconsideration filed by a coalition of Georgia industries. The impact of the nitrogen oxide reduction rules on the Company will depend on the outcome of the petition for reconsideration and/or any subsequent development and approval of Georgia’s state implementation plan and cannot be determined at this time.

     In January 2004, the EPA issued a proposed Clean Air Interstate Rule (CAIR) 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 in 2005. If finalized, the rule could modify or supplant other state requirements for attainment of the fine particulate matter standard and the eight-hour ozone standard, as well as other air quality regulations. 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.

     The Company has developed and maintains an environmental compliance strategy for the installation of additional control technologies and the purchase of emission allowances to assure continued compliance with current sulfur dioxide and nitrogen oxide emission regulations. Additional expenses associated with these regulations are anticipated to be incurred each year to maintain current and future compliance. Because the Company’s compliance strategy is impacted by factors such as changes to existing environmental laws and regulations, increases in the costs of emissions allowances, and any changes in the Company’s fuel mix, future environmental compliance costs 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 and to implement emission reduction requirements that make progress toward remedying current visibility impairment in certain natural areas. The Company has two plants that could be subject to these rules. The EPA’s Regional Haze program calls for states to submit implementation plans in 2008 that contain emission reduction strategies for implementing BART and for achieving sufficient progress toward the Clean Air Act’s visibility improvement goal. In response to litigation, the EPA proposed revised rules in May 2004, which it plans to finalize in April 2005. The impact of these regulations will depend on the promulgation of final rules and implementation of those rules by the states and, therefore, it is not possible to determine the effect of these rules on the Company at this time.

     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 March 2005, and compliance could be required as early as 2008. Because the regulations have not been finalized, the impact on the Company cannot be determined at this time.

     Major bills to amend the Clean Air Act to impose more stringent emissions limitations on power plants, including the Bush Administration’s Clear Skies Act, have been re-proposed in 2005. The Clear Skies Act is expected to further limit power plant emissions of sulfur dioxide, nitrogen oxides, and mercury and to supplement the proposed CAIR and mercury regulatory programs. Other proposals to limit emissions of carbon dioxide have also been introduced. The cost impacts of such legislation would depend upon the specific requirements enacted and cannot be determined at this time.

     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. In July 2004, the EPA published final rules that will require biological studies and, perhaps, retrofits to some intake structures at existing power plants. The impact of these new rules will

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depend on the results of studies and analyses performed as part of the rules’ implementation and actual limits established by the regulatory agencies.

     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, 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.

Global Climate Issues

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 constraints on the emissions of greenhouse gases for a group of industrialized countries. The Bush Administration has not supported U.S. ratification of the Kyoto Protocol or other mandatory carbon dioxide reduction legislation and, in 2002, announced a goal to reduce the greenhouse gas intensity of the U.S. — the ratio of greenhouse gas emissions to the value of U.S. economic output — by 18 percent by 2012. A year later, the Department of Energy (DOE) announced the Climate VISION program to support this goal. Energy-intensive industries, including electricity generation are the initial focus of this program. Southern Company is leading the development of a voluntary electric utility sector climate change initiative in partnership with the government. The utility sector has pledged to reduce its greenhouse gas emissions rate by 3 to 5 percent over the next decade and, on December 13, 2004, signed a memorandum of understanding with the DOE initiating this program under Climate VISION. Because efforts under this voluntary program are just beginning, the impact of this program on the Company cannot be determined at this time.

Environmental Remediation Reserves

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.

FERC and Georgia PSC Matters

Transmission

In December 1999, the FERC issued its final rule on Regional Transmission Organizations (RTOs). Since that time, there have been a number of additional proceedings at the FERC designed to encourage further voluntary formation of RTOs or to mandate their formation. However, at the current time, there are no active proceedings that would require the Company to participate in an RTO. Current FERC efforts that may potentially change the regulatory and/or operational structure of transmission include rules related to the standardization of generation interconnection, as well as an inquiry into, among other things, market power by vertically integrated utilities. See “Generation Interconnection Agreements” and “Market-Based Rate Authority” below for additional information. The final outcome of these proceedings cannot now be determined. However, the Company’s financial condition, results of operations and cash flows could be adversely affected by future changes in the federal regulatory or operational structure of transmission.

Generation Interconnection Agreements

In July 2003, the FERC issued its final rule on the standardization of generation interconnection agreements and procedures (Order 2003). Order 2003 shifts much of the financial burden of new transmission investment from the generator to the transmission provider. The FERC has indicated that Order 2003, which was effective

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January 20, 2004, is to be applied prospectively to interconnection agreements. The impact of Order 2003 and its subsequent rehearings on the Company and the final results of these matters cannot be determined at this time.

Market-Based Rate Authority

The Company has authorization from the FERC to sell power to non-affiliates at market-based prices. 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, the retail operating companies, and Southern Power, and found Southern Company and others to be “pivotal suppliers” in their retail service territories 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. In April 2004, the FERC issued an order that abandoned the SMA test and adopted a new interim analysis for measuring generation market power. This new interim approach requires utilities to submit a pivotal supplier screen and a wholesale market share screen. If the applicant does not pass both screens, there will be a rebuttable presumption regarding generation market power. The FERC’s order also sets forth procedures for rebutting these presumptions and addresses mitigation measures for those entities that are found to have market power. In the absence of specific mitigation measures, the order includes several cost-based mitigation measures that would apply by default. The FERC also initiated a new rulemaking proceeding that, among other things, will adopt a final methodology for assessing generation market power.

     In July 2004, the FERC denied Southern Company’s request for rehearing, along with a number of others, and reaffirmed the interim tests that it adopted in April 2004. In August 2004, Southern Company submitted a filing to the FERC that included results showing that Southern Company passed the pivotal supplier screen for all markets and the wholesale market share screen for all markets except the Southern Company retail service territory. Southern Company also submitted other analyses to demonstrate that it lacks generation market power. On December 17, 2004, the FERC initiated a proceeding to assess Southern Company’s generation dominance within its retail service territory. The ability to charge market-based rates in other markets is not at issue. As directed by this order, on February 15, 2005, Southern Company submitted additional information related to generation dominance in the Southern Company retail service territory. Any new market-based rate transactions in the Southern Company retail service territory entered into after February 27, 2005 will be subject to refund to the level of the default cost-based rates, pending the outcome of the proceeding. Southern Company, along with other utilities, has also filed an appeal of the FERC’s April and July 2004 orders with the U.S. Court of Appeals for the District of Columbia Circuit. The FERC has asked the court to dismiss the appeal on the grounds that it is premature.

     In the event that the FERC’s default mitigation measures are ultimately applied, the Company may be required to charge cost-based rates for certain wholesale sales in the Southern Company retail service territory, which may be lower than negotiated market-based rates. The final outcome of this matter will depend on the form in which the final methodology for assessing generation market power and mitigation rules may be ultimately adopted and cannot be determined at this time.

Retail Rate Case Filing

On November 30, 2004, the Company filed a traditional one-year rate case with the Georgia PSC requesting a $23.2 million, or 6.7 percent, increase in retail revenues, effective January 1, 2005. The requested increase is based on a future test year ending December 31, 2005 and a proposed retail return on common equity of 12.5 percent. As an alternative, the Company has also included in its request a three-year rate plan that is based on the same test year and proposed retail return on common equity. The Company expects the Georgia PSC to issue a final order in this matter during May 2005. The final outcome of this matter cannot now be determined.

     The increase in retail revenues is being requested to cover the Company’s investment in the new Plant McIntosh Combined Cycle Units 10 and 11; increasing operating and maintenance expenses; and continued investment in generation, transmission, and distribution facilities to support growth and ensure reliability. The increase also includes recognition on an annual basis of

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the $3.8 million of Plant Wansley purchased power expenses which were excluded by the Georgia PSC in the Company’s last rate case and subsequently were subject to deferral through a Georgia PSC accounting order issued in December 2002.

     Under the terms of that order, two-thirds of any earnings of the Company in a calendar year above a 12 percent return on common equity are 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 provided 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 2004, the Company had amortized all of the deferred purchased power costs. For additional information, see Note 3 to the financial statements under “Retail Regulatory Matters.”

Plant McIntosh Construction Project

In December 2002 after a competitive bidding process, the Georgia PSC certified PPAs between Southern Power and Georgia Power and the Company for capacity from Plant McIntosh Combined Cycle Units 10 and 11, construction of which is scheduled to be completed in June 2005. In April 2003, Southern Power applied for FERC approval of these PPAs. In July 2003, the FERC accepted the PPAs to become effective June 1, 2005, subject to refund, and ordered that hearings be held. Intervenors opposed the FERC’s acceptance of the PPAs, alleging that they did not meet applicable standards for market-based rates between affiliates. To ensure the timely completion of the Plant McIntosh construction project and the availability of the units in the summer of 2005 for their retail customers, the Company and Georgia Power in May 2004 requested the Georgia PSC to direct them to acquire the Plant McIntosh construction project. The Georgia PSC issued such an order and the transfer occurred on May 24, 2004 at a total cost of approximately $415 million, including $14 million of transmission interconnection facilities. Subsequently, Southern Power filed a request to withdraw the PPAs and to terminate the ongoing FERC proceedings. In August 2004, the FERC issued a notice accepting the request to withdraw the PPAs and permitting such request to become effective by operation of law. However, the FERC made no determination on what additional steps may need to be taken with respect to testimony provided in the proceedings. The ultimate outcome of any additional FERC action cannot now be determined.

     As directed by the Georgia PSC order, Georgia Power and the Company in June 2004 filed an application to amend the resource certificate granted by the Georgia PSC in 2002. In connection with the Georgia Power 2004 retail rate case, the Georgia PSC approved the transfer of the Plant McIntosh construction project, at a total fair market value of approximately $385 million. This value reflects an approximate $16 million disallowance. The Company owns 16.129 percent of the project; thus, this disallowance amounted to approximately $3 million and reduced the Company’s 2004 net income by approximately $1.5 million. The Georgia PSC also certified a total completion cost of $547 million for the project. The amount of the disallowance will be adjusted accordingly based on the actual completion cost of the project. The Georgia PSC will determine the rate treatment of Plant McIntosh in connection with its decision on the Company’s 2004 retail rate case filing in May 2005. See Note 3 under “Plant McIntosh Construction Project.”

Retail Fuel Cost Recovery

On October 25, 2004, the Georgia PSC approved the Company’s request for a fuel cost recovery rate increase with no significant modifications. The approved fuel rate increase also includes the recovery of approximately $3.5 million in costs associated with a coal transloader to be amortized over a 21-month period. The transloader allows foreign coal to be off-loaded from ships at the Company’s Plant Kraft dock and then transferred by rail to Plant McIntosh. The new rates became effective in November 2004. See Note 3 to the financial statements under “Retail Regulatory Matters – Fuel Cost Recovery” for further information.

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Income Tax Matters

American Jobs Creation Act of 2004

On October 22, 2004, President Bush signed the American Jobs Creation Act of 2004 (Jobs Act) into law. The Jobs Act includes a provision that allows a generation tax deduction for utilities. The Company is currently assessing the impact of the Jobs Act, including this deduction, as well as the related regulatory treatment, on its taxable income. However, the Company currently does not expect the Jobs Act to have a material impact on its financial statements.

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 $5.3 million, $4.3 million, and $4.4 million pre-tax in 2004, 2003, and 2002, respectively. Future pension costs are dependent on several factors including trust earnings and changes to the pension plans and are expected to continue to increase. Postretirement benefit costs for the Company were approximately $2.8 million in 2004, $2.7 million in 2003, and $2.6 million in 2002 and are expected to continue to trend upward. A portion of pension and postretirement benefit costs is capitalized based on construction-related labor charges. For more information regarding pension and postretirement benefits, see Note 2 to the financial statements.

     Effective September 30, 2004, the Company retired Units 4 and 5 at Plant Riverside. The remaining units at the plant will be retired on May 31, 2005. These retirements will have no material impact on the Company’s financial statements.

     The Company is involved in various other 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. Southern Company 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.

Electric Utility Regulation

The Company is subject to retail regulation by the Georgia 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, which requires the financial statements to reflect the effects of rate 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 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, 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 legislative, judicial, or regulatory actions could materially impact the amounts of such regulatory assets and liabilities and could adversely impact the Company’s financial statements.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Savannah Electric and Power Company 2004 Annual Report

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 herein 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:

•   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.

•   Changes in existing income tax regulations or changes in Internal Revenue Service interpretations of existing regulations.

•   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.

•   Identification and evaluation of other potential lawsuits or complaints in which the Company may be named as a defendant.

•   Resolution or progression of existing matters through the legislative process, the court systems, or the EPA.

Unbilled Revenues

Revenues related to the sale of electricity are recorded when electricity is delivered to customers. However, the determination of kilowatt-hour sales to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month. At the end of each month, amounts of electricity delivered to customers, but not yet metered and billed, are estimated. Components of the unbilled revenue estimates include total kilowatt-hour territorial supply, total kilowatt-hour billed, estimated total electricity lost in delivery, and customer usage. These components can fluctuate as a result of a number of factors including weather, generation patterns, and power delivery volume and other operational constraints. These factors can be unpredictable and can vary from historical trends. As a result, the overall estimate of unbilled revenues could be significantly affected. See Note 9 to the financial statements for information on the restatement of the Company’s financial statements which resulted from errors in the calculations of unbilled revenues.

New Accounting Standards

On March 31, 2004, the Company prospectively adopted FASB Interpretation No. 46R, “Consolidation of Variable Interest Entities,” which requires the primary beneficiary of a variable interest entity to consolidate the related assets and liabilities. In January 2004, the Company redeemed all $40 million of its outstanding mandatorily redeemable preferred securities; thus the adoption of Interpretation No. 46R did not have any impact on the Company’s financial statements.

     In the third quarter 2004, the Company prospectively adopted FASB Staff Position (FSP) 106-2, Accounting and Disclosure Requirements related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (Medicare Act). The Medicare Act provides a 28 percent prescription drug subsidy for Medicare eligible retirees. FSP 106-2 requires recognition of the impacts of the Medicare Act in the accumulated postretirement benefit obligation (APBO) and future cost of service for postretirement medical plans. The effect of the subsidy reduced the Company’s expenses for the six months ended December 31, 2004 by approximately $0.2 million and is expected to have a similar impact on future years. The subsidy’s impact on the postretirement medical plan APBO was a reduction of approximately $3.5 million. However, the ultimate impact on future periods is subject to final interpretation of the federal regulations which were published on January 21, 2005. See Note 2 to the financial statements under “Postretirement Benefits” for additional information.

     FASB Statement No. 123R, Share-Based Payment was issued in December 2004. This statement requires that compensation cost relating to share-based payment transactions be recognized in financial statements. That cost will be measured based on the grant date fair

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Savannah Electric and Power Company 2004 Annual Report

value of the equity or liability instruments issued. For the Company, this statement is effective beginning on July 1, 2005. Although the compensation expense required under the revised statement differs slightly, the impacts on the Company’s financial statements are expected to be similar to the pro forma disclosures included in Note 1 to the financial statements under “Stock Options”.

     See FUTURE EARNINGS POTENTIAL – “Income Tax Matters — American Jobs Creation Act of 2004” herein for information regarding the adoption of new tax legislation. In December 2004, the FASB issued FSP 109-1, Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax Deduction on Qualified Production Activities provided by the American Jobs Creation Act of 2004, which requires that the generation deduction be accounted for as a special tax deduction rather than as a tax rate reduction. The Company is currently assessing the Jobs Act and this pronouncement, as well as the related regulatory treatment, but currently does not expect a material impact on the Company’s financial statements.

FINANCIAL CONDITION AND LIQUIDITY

Overview

As of December 31, 2004, the Company’s capital structure consisted of 45.2 percent common stockholder’s equity, 8.6 percent preferred stock, and 46.2 percent long-term debt, excluding amounts due within one year.

     The principal change in the Company’s financial condition in 2004 was the addition of $126.1 million to utility plant, the majority of which was related to the purchase of the Plant McIntosh Combined Cycle Units 10 and 11 construction project. The funds needed for gross property additions are currently provided from operating activities, the issuance of securities, capital contributions from Southern Company, and short-term debt. Net cash flow from operating activities decreased in 2004 primarily as a result of higher fuel costs. Those costs are recoverable in future periods and are reflected in the balance sheets as under recovered regulatory clause revenues. 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 sources similar to those used in the past including both internal and external funds. Historically, external funding came from the issuance of debt, preferred securities, and capital contributions from Southern Company. 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. The issuance of securities by the Company is subject to regulatory approval by the Securities and Exchange Commission (SEC) under the Public Utility Holding Company Act of 1935, as amended (PUHCA), and the Georgia PSC. Additionally, with respect to the public offering of securities, the Company must file registration statements with the SEC under the Securities Act of 1933 (the 1933 Act). The amounts of securities authorized by the appropriate regulatory authorities, as well as the amounts registered under the 1933 Act, are continuously monitored and appropriate filings are made to ensure flexibility in the capital markets.

     At the beginning of 2005, the Company had $80 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. Of this amount, $70 million will expire at various times in 2005 and $10 million will expire in 2007. The Company expects to renew, as needed, its credit arrangements prior to expiration. The Company also has adequate cash flow from operating activities and access to the capital markets to meet liquidity needs. 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

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Savannah Electric and Power Company 2004 Annual Report

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, 2004, the Company had outstanding $12.6 million in commercial paper and $8.0 million in 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, 2004, the amount of variable rate obligations outstanding requiring liquidity support was $7.2 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 PUHCA, most loans between affiliated companies must be approved in advance by the SEC.

Financing Activities

Maturities and redemptions of long-term debt and mandatorily redeemable preferred securities were $70.0 million in 2004, $39.4 million in 2003, and $53.6 million in 2002.

     In January 2004, the Company redeemed its $40 million Savannah Electric Capital Trust I 6.85% Trust Preferred Securities. The Company issued, in June 2004, $45 million of 6.00% Series Preferred Stock. In December 2004, the Company issued $35 million of Series G 5.75% Senior Notes maturing in 2044. The Company received $31 million in May 2004 and $15 million in December 2004 in capital contributions from Southern Company. The Company used the proceeds from the preferred stock and senior notes sales and capital contributions to repay a portion of its outstanding short-term indebtedness and to finance the purchase of the Plant McIntosh Combined Cycle construction project.

     Subsequent to December 31, 2004, the Company entered into a cash flow hedge with a notional amount of $30 million, a fixed rate of 4.69 percent, and a final maturity of 2016 for an anticipated security issuance in 2006.

Credit Rating Risk

The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. The Company is party to certain derivative agreements that could require collateral and/or accelerated payment in the event of a credit rating change to below investment grade. These agreements are primarily for natural gas price risk management activities. At December 31, 2004, the Company’s exposure related to these agreements was not material.

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 risk management practices. Company policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including but not limited to market valuation, value at risk, stress testing, 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 January 1, 2005 was 2.31 percent. If the Company sustained a 100 basis point change in interest rates for all unhedged variable rate long-term debt, at January 1, 2005, the change would not materially affect annualized interest expense. The Company continues to evaluate its options related to these securities, and may or may not enter into additional hedging transactions in 2005. 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

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Company has implemented a natural gas/oil hedging program ordered by the Georgia PSC. 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 $2.4 million for 2002, $1.1 million for 2003, and $2.7 million for 2004 and will be $5.1 million for 2005. The program has operated within the defined hedging position limits set for each year.

     The changes in fair value of energy related derivative contracts and year-end valuations were as follows at December 31:

                 
    Changes in Fair Value  
    2004     2003  
    (in thousands)  
Contracts beginning of year
  $ 463     $ 626  
Contracts realized or settled
    (1,811 )     (1,798 )
New contracts at inception
           
Changes in valuation techniques
           
Current period changes (a)
    2,822       1,635  
 
Contracts end of year
  $ 1,474     $ 463  
 

(a) Current period changes also include the changes in fair value of new contracts entered into during the period.

                         
    Source of 2004 Year-End Valuation Prices  
    Total     Maturity  
    Fair Value     Year 1     2-3 Years  
    (in thousands)  
         
Actively quoted
  $ 1,293     $ 1,051     $ 242  
External sources
    181       181        
Models and other methods
                 
         
Contracts end of year
  $ 1,474     $ 1,232     $ 242  
         

     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. These amounts were not material in any year presented. At December 31, 2004, the fair value of derivative energy contracts was reflected in the financial statements as follows:

         
    Amounts  
         
    (in thousands)  
Regulatory liabilities, net
  $ 1,471  
Other comprehensive income
     
Net income
    3  
 
Total fair value
  $ 1,474  
 

     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. See Notes 1 and 6 to the financial statements under “Financial Instruments” for additional information.

Capital Requirements and Contractual Obligations

The Company’s construction program is currently estimated to be $52.4 million in 2005, $39.2 million in 2006, and $33.7 million in 2007. Environmental expenditures included in these amounts are $1.4 million, $1.2 million, and $0.2 million for 2005, 2006, and 2007, 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. The Company has new generating capacity scheduled to be placed in service in June 2005. 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 Georgia PSC.

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     Other funding requirements related to obligations associated with scheduled maturities of long-term debt, as well as the related interest, preferred stock dividends, leases, and other purchase commitments are as follows: See Notes 1, 6, and 7 to the financial statements for additional information.

Contractual Obligations

                                         
            2006-     2008-     After        
    2005     2007     2009     2009     Total  
    (in thousands)  
Long-term debt(a)
                   
Principal
  $ 1,010     $ 21,884     $ 46,758     $ 169,127     $ 238,779  
Interest
    13,196       24,897       20,425       147,502       206,020  
Preferred stock dividends(b)
    2,700       5,400       5,400             13,500  
Operating leases
    846       1,618       1,401       3,608       7,473  
Purchase commitments(c)
Capital(d)
    52,412       72,985                   125,397  
Coal
    50,301       6,771                   57,072  
Natural gas(e)
    26,296       42,140       63,785       285,322       417,543  
Purchased power
    13,262       26,554       26,602             66,418  
Long-term service agreements
    872       3,115       3,712       27,315       35,014  
Postretirement benefit trusts(f)
    1,190       2,500                   3,690  
 
Total
  $ 162,085     $ 207,864     $ 168,083     $ 632,874     $ 1,170,906  
 

(a)   All amounts are reflected based on final maturity dates. The Company plans to 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, 2005, 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 $86.0 million, $83.6 million, and $81.0 million, respectively.

(d)   The Company forecasts capital expenditures over a three-year period. Amounts represent current estimates of total expenditures. At December 31, 2004, significant purchase commitments were outstanding in connection with the construction program.

(e)   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 Exchange future prices at December 31, 2004.

(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 and postretirement plans, including estimated benefit payments. Certain benefit payments will be made through the related trusts. Other benefit payments will be made from the Company’s corporate assets.

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Cautionary Statement Regarding Forward-Looking Information

The Company’s 2004 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning retail sales growth, environmental regulations and expenditures, completion of construction projects, estimated construction and other expenditures, and the Company’s projections for 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 similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:

•   the impact of recent and future federal and state regulatory change, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry and also changes in environmental, tax, and other laws and regulations to which the Company is subject, as well as changes in application of existing laws and regulations;
 
•   current and future litigation, regulatory investigations, proceedings or inquiries, including the pending EPA civil action against the Company;
 
•   the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates;
 
•   variations in demand for electricity and gas, including those relating to weather, the general economy and population and business growth (and declines);
 
•   available sources and costs of fuels;
 
•   ability to control costs;
 
•   investment performance of the Company’s employee benefit plans;
 
•   advances in technology;
 
•   state and federal rate regulations and the impact of pending and future rate cases and negotiations;
 
•   internal restructuring or other restructuring options that may be pursued;
 
•   potential business strategies, including acquisitions or dispositions of assets, which cannot be assured to be completed or beneficial to the Company;
 
•   the ability of counterparties of the Company to make payments as and when due;
 
•   the ability to obtain new short- and long-term contracts with neighboring utilities;
 
•   the direct or indirect effects on the Company’s business resulting from terrorist incidents and the threat of terrorist incidents;
 
•   interest rate fluctuations and financial market conditions and the results of financing efforts, including the Company’s credit ratings;
 
•   the ability of the Company to obtain additional generating capacity at competitive prices;
 
•   catastrophic events such as fires, earthquakes, explosions, floods, hurricanes, or other similar occurrences;
 
•   the direct or indirect effects on the Company’s business resulting from incidents similar to the August 2003 power outage in the Northeast;
 
•   the effect of accounting pronouncements issued periodically by standard-setting bodies; and
 
•   other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed from time to time by the Company with the SEC.

The Company expressly disclaims any obligation to update any forward-looking statements.

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STATEMENTS OF INCOME
For the Years Ended December 31, 2004, 2003, and 2002
Savannah Electric and Power Company 2004 Annual Report

                         
   
    2004     2003
As Restated
(Note 9)
    2002
As Restated
(Note 9)
 
 
    (in thousands)
Operating Revenues:
                       
Retail sales
  $ 341,766     $ 298,807     $ 283,225  
Sales for resale —
                       
Non-affiliates
    5,035       5,653       6,354  
Affiliates
    6,130       6,499       4,075  
Other revenues
    4,029       4,158       3,352  
 
Total operating revenues
    356,960       315,117       297,006  
 
Operating Expenses:
                       
Fuel
    55,721       55,308       54,955  
Purchased power —
                       
Non-affiliates
    11,413       5,713       6,368  
Affiliates
    114,261       83,792       69,236  
Other operations
    61,134       56,823       55,756  
Maintenance
    24,831       26,798       25,262  
Depreciation and amortization
    21,252       20,499       22,704  
Taxes other than income taxes
    15,245       14,665       14,457  
 
Total operating expenses
    303,857       263,598       248,738  
 
Operating Income
    53,103       51,519       48,268  
Other Income and (Expense):
                       
Interest income
    208       290       147  
Interest expense, net of amounts capitalized
    (12,047 )     (9,590 )     (11,608 )
Distributions on mandatorily redeemable preferred securities
    (109 )     (2,740 )     (2,740 )
Other income (expense), net
    (1,045 )     (502 )     (1,300 )
 
Total other income and (expense)
    (12,993 )     (12,542 )     (15,501 )
 
Earnings Before Income Taxes
    40,110       38,977       32,767  
Income taxes
    14,378       15,518       11,448  
 
Net Income
    25,732       23,459       21,319  
Dividends on Preferred Stock
    1,500              
 
Net Income After Dividends on Preferred Stock
  $ 24,232     $ 23,459     $ 21,319  
 
The accompanying notes are an integral part of these financial statements.

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STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2004, 2003, and 2002
Savannah Electric and Power Company 2004 Annual Report

                         
   
          2003     2002  
          As Restated     As Restated  
    2004     (Note 9)     (Note 9)  
 
    (in thousands)
Operating Activities:
                       
Net income
  $ 25,732     $ 23,459     $ 21,319  
Adjustments to reconcile net income to net cash provided from operating activities —
                       
Depreciation and amortization
    23,710       22,587       24,653  
Deferred income taxes and investment tax credits, net
    13,441       793       (6,227 )
Allowance for equity funds used during construction
    (2,379 )     (193 )      
Pension, postretirement, and other employee benefits
    6,114       6,215       6,133  
Tax benefit of stock options
    861       884       1,451  
Other, net
    (7,226 )     4,208       (10,559 )
Changes in certain current assets and liabilities —
                       
Receivables, net
    (26,371 )     127       10,511  
Fossil fuel stock
    (1,938 )     (323 )     1,522  
Materials and supplies
    (842 )     516       3,383  
Other current assets
    (5,324 )     4,615       (7,591 )
Accounts payable
    5,035       3,713       7,352  
Accrued taxes
    3,352       (1,131 )     509  
Accrued compensation
    (40 )     (819 )     444  
Other current liabilities
    (911 )     (4,492 )     5,733  
 
Net cash provided from operating activities
    33,214       60,159       58,633  
 
Investing Activities:
                       
Gross property additions
    (51,301 )     (40,242 )     (32,481 )
Purchase of property from affiliates
    (74,832 )            
Other
    931       895       (1,331 )
 
Net cash used for investing activities
    (125,202 )     (39,347 )     (33,812 )
 
Financing Activities:
                       
Increase (decrease) in notes payable, net
    20,567       (2,897 )     (29,263 )
Proceeds —
                       
Pollution control bonds
          13,870        
Senior notes
    35,000       60,000       55,000  
Other long-term debt
    10,376             25,616  
Preferred stock
    45,000              
Capital contributions from parent company
    47,255       6,757       2,499  
Redemptions —
                       
First mortgage bonds
                (23,558 )
Pollution control bonds
          (13,870 )      
Senior notes
          (20,000 )     (30,000 )
Other long-term debt
    (30,000 )     (5,541 )      
Mandatorily redeemable preferred securities
    (40,000 )            
Payment of preferred stock dividends
    (825 )            
Payment of common stock dividends
    (23,200 )     (23,000 )     (22,700 )
Other
    (1,266 )     (2,166 )     (828 )
 
Net cash provided from (used for) financing activities
    62,907       13,153       (23,234 )
 
Net Change in Cash and Cash Equivalents
    (29,081 )     33,965       1,587  
Cash and Cash Equivalents at Beginning of Period
    37,943       3,978       2,391  
 
Cash and Cash Equivalents at End of Period
  $ 8,862     $ 37,943     $ 3,978  
 
Supplemental Cash Flow Information:
                       
Cash paid during the period for —
                       
Interest (net of $1,471, $220, and $165 capitalized, respectively)
  $ 10,080     $ 11,334     $ 13,353  
Income taxes (net of refunds)
    4,581       8,439       23,478  
 
The accompanying notes are an integral part of these financial statements.

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BALANCE SHEETS
At December 31, 2004 and 2003
Savannah Electric and Power Company 2004 Annual Report

                 
   
          2003  
          As Restated  
Assets   2004     (Note 9)  
 
    (in thousands)
Current Assets:
               
Cash and cash equivalents
  $ 8,862     $ 37,943  
Receivables —
               
Customer accounts receivable
    22,875       19,674  
Unbilled revenues
    6,681       6,064  
Under recovered regulatory clause revenues
    23,800        
Other accounts and notes receivable
    1,608       1,313  
Affiliated companies
    3,392       4,872  
Accumulated provision for uncollectible accounts
    (878 )     (817 )
Fossil fuel stock, at average cost
    10,590       8,652  
Materials and supplies, at average cost
    9,913       9,070  
Prepaid income taxes
    21,615       25,981  
Prepaid expenses
    1,415       1,377  
Other
    2,174       623  
 
Total current assets
    112,047       114,752  
 
Property, Plant, and Equipment:
               
In service
    945,359       912,504  
Less accumulated provision for depreciation
    408,415       402,394  
 
 
    536,944       510,110  
Construction work in progress
    91,275       14,121  
 
Total property, plant, and equipment
    628,219       524,231  
 
Other property and investments
    3,925       3,769  
 
Deferred Charges and Other Assets:
               
Deferred charges related to income taxes
    10,588       9,611  
Cash surrender value of life insurance for deferred compensation plans
    25,335       23,866  
Unamortized debt issuance expense
    5,303       5,652  
Unamortized loss on reacquired debt
    7,935       7,488  
Other regulatory assets
    16,107       13,245  
Other
    3,132       3,645  
 
Total deferred charges and other assets
    68,400       63,507  
 
Total Assets
  $ 812,591     $ 706,259  
 
The accompanying notes are an integral part of these financial statements.

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BALANCE SHEETS
At December 31, 2004 and 2003
Savannah Electric and Power Company 2004 Annual Report

                 
 
          2003  
          As Restated  
Liabilities and Stockholder's Equity   2004     (Note 9)  
 
    (in thousands)
Current Liabilities:
               
Securities due within one year
  $ 1,010     $ 40,910  
Notes payable
    20,567        
Accounts payable —
               
Affiliated
    17,379       13,797  
Other
    16,166       13,147  
Customer deposits
    6,973       6,922  
Accrued taxes —
               
Income taxes
    148       713  
Other
    5,390       1,473  
Accrued interest
    3,050       2,802  
Accrued vacation pay
    2,661       2,530  
Accrued compensation
    5,612       5,652  
Other
    5,248       5,107  
 
Total current liabilities
    84,204       93,053  
 
Long-term Debt (See accompanying statements)
    237,769       222,493  
 
Deferred Credits and Other Liabilities:
               
Accumulated deferred income taxes
    90,079       83,852  
Deferred credits related to income taxes
    8,738       9,804  
Accumulated deferred investment tax credits
    7,961       8,625  
Employee benefit obligations
    46,580       39,833  
Other cost of removal obligations
    41,890       36,843  
Miscellaneous regulatory liabilities
    12,631       12,932  
Other
    6,645       15,735  
 
Total deferred credits and other liabilities
    214,524       207,624  
 
Total Liabilities
    536,497       523,170  
 
Preferred Stock (See accompanying statements)
    43,938        
 
Common Stockholder’s Equity (See accompanying statements)
    232,156       183,089  
 
Total Liabilities and Stockholder’s Equity
  $ 812,591     $ 706,259  
 
Commitments and Contingent Matters (See notes)
               
 
The accompanying notes are an integral part of these financial statements.

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STATEMENTS OF CAPITALIZATION
At December 31, 2004 and 2003
Savannah Electric and Power Company 2004 Annual Report

                                 
   
          2003           2003  
        As Restated         As Restated  
    2004     (Note 9)     2004     (Note 9)  
 
Long-Term Debt:   (in thousands)
  (percent of total)
First mortgage bonds — 6.9% due May 1, 2006
  $ 20,000     $ 20,000                  
 
Long-term notes payable —
                               
6.55% due May 15, 2008
    45,000       45,000                  
4.90% to 5.75% due 2013 through 2044
    150,000       115,000                  
Adjustable rates due September 6, 2005
          20,000                  
 
Total long-term notes payable
    195,000       180,000                  
 
Other long-term debt —
                               
Non-collateralized pollution control revenue bonds —
                               
Variable rates (2.20% to 2.65% at 1/1/05) due 2016-2038
    17,955       17,955                  
 
Capitalized lease obligations
    5,824       5,448                  
 
Total long-term debt (annual interest requirement — $13.2 million)
    238,779       223,403                  
Less amount due within one year
    1,010       910                  
 
Long-term debt excluding amount due within one year
    237,769       222,493       46.2 %     54.9 %
 
Mandatorily Redeemable Preferred Securities:
                               
$25 liquidation value — 6.85% due 2028
          40,000                  
Less amount due within one year
          40,000                  
 
Mandatorily redeemable preferred securities excluding amount due within one year
                0.0       0.0  
 
Non-Cumulative Preferred Stock:
                               
$25 par value — 6.00% (annual dividend requirement — $2.7 million)
    43,938             8.6       0.0  
 
Common Stockholder’s Equity:
                               
Common stock, par value $5 per share —
    54,223       54,223                  
Authorized - 16,000,000 shares
                               
Outstanding - 10,844,635 shares in 2004 and 2003
                               
Paid-in capital
    72,533       24,417                  
Retained earnings
    107,685       106,653                  
Accumulated other comprehensive income (loss)
    (2,285 )     (2,204 )                
 
Total common stockholder’s equity
    232,156       183,089       45.2       45.1  
 
Total Capitalization
  $ 513,863     $ 405,582       100.0 %     100.0 %
 
The accompanying notes are an integral part of these financial statements.

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STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
For the Years Ended December 31, 2004, 2003, and 2002
Savannah Electric and Power Company 2004 Annual Report

                                         
   
                            Other        
    Common     Paid-In     Retained     Comprehensive        
    Stock     Capital     Earnings     Income (loss)     Total  
 
    (in thousands)
 
                                       
Balance at December 31, 2001 (As Restated — See Note 9)
  $ 54,223     $ 12,826     $ 107,575     $     $ 174,624  
Net income (As Restated — See Note 9)
                21,319             21,319  
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 (As Restated — See Note 9)
    54,223       16,776       106,194       (1,244 )     175,949  
Net income (As Restated — See Note 9)
                23,459             23,459  
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 (As Restated — See Note 9)
    54,223       24,417       106,653       (2,204 )     183,089  
Net income after dividends on preferred stock
                24,232             24,232  
Capital contributions from parent company
          48,116                   48,116  
Other comprehensive income (loss)
                      (81 )     (81 )
Cash dividends on common stock
                (23,200 )           (23,200 )
 
Balance at December 31, 2004
  $ 54,223     $ 72,533     $ 107,685     $ (2,285 )   $ 232,156  
 
The accompanying notes are an integral part of these financial statements.
 
 
 

STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2004, 2003, and 2002
Savannah Electric and Power Company 2004 Annual Report

                         
   
          2003     2002  
          As Restated     As Restated  
    2004     (Note 9)     (Note 9)  
 
    (in thousands)
Net income after dividends on preferred stock
  $ 24,232     $ 23,459     $ 21,319  
 
Other comprehensive income (loss):
                       
Change in additional minimum pension liability, net of tax of $(253), $(336) and $(785), respectively
    (401 )     (533 )     (1,244 )
Changes in fair value of qualifying hedges, net of tax of $161 and $(284), respectively
    255       (450 )      
Less: Reclassification adjustment for amounts included in net income, net of tax of $41 and $15, respectively
    65       23        
 
Total other comprehensive income (loss)
    (81 )     (960 )     (1,244 )
 
Comprehensive Income
  $ 24,151     $ 22,499     $ 20,075  
 

The accompanying notes are an integral part of these financial statements.

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NOTES TO FINANCIAL STATEMENTS
Savannah Electric and Power Company 2004 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 (SouthernLINC Wireless), 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 the subsidiary companies. SouthernLINC Wireless 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 various other energy-related businesses. 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, as amended (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 (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 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 $17.4 million, $16.3 million, and $15.6 million during 2004, 2003, and 2002, 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 (PPA) 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 2004 amounted to $31.5 million. At December 31, 2004, approximately $1.2 million in prepaid capacity expense related to this PPA was recorded in other deferred charges and other assets in the balance sheets.

     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 $3.3 million in 2004, $3.6 million in 2003, and $1.8 million in 2002. See Note 4 for additional information.

     The Company and Georgia Power acquired, in 2004,

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NOTES (continued)
Savannah Electric and Power Company 2004 Annual Report

the Plant McIntosh Combined Cycle Units 10 and 11 construction project. The units, scheduled to begin operation in June 2005, will be jointly owned by the Company and Georgia Power. See Note 3 under “Plant McIntosh Construction Project” and Notes 4 and 5 for additional information.

     Also, see Note 5 for information on certain deferred tax liabilities due to affiliates.

     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

Revenues are recognized as services are rendered. Unbilled revenues are accrued at the end of each fiscal period. 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 the actual recoverable costs and amounts billed 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.

Fuel Costs

Fuel costs are expensed as the fuel is used. Fuel expense generally includes the cost of purchased emission allowances as they are used.

Regulatory Assets and Liabilities

The Company is subject to the provisions of Financial Accounting Standards Board (FASB) Statement No. 71, Accounting for the Effects of Certain Types of Regulation. Regulatory assets represent probable future revenues to the Company associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process.

     Regulatory assets and (liabilities) reflected in the balance sheets at December 31 and the amortization periods are discussed below as follows:

                         
    2004     2003     Note  
           
    (in thousands)          
Asset retirement obligations
  $ 3,868     $ 3,265       (a)
Deferred income tax charges
    10,588       9,611       (a)
Loss on reacquired debt
    7,935       7,488       (b)
Deferred McIntosh maintenance costs
    8,599       9,818       (c)
Coal transloader
    3,077             (d)
Wansley accounting order
          162       (e)
Fuel-hedging
    563             (f)
Other cost of removal obligations
    (41,890 )     (36,843 )     (a)
Fuel-hedging
    (2,034 )     (462 )     (f)
Deferred income tax credits
    (8,738 )     (9,804 )     (a)
Storm damage reserves
    (8,341 )     (7,103 )     (e)
Accelerated cost recovery
    (1,256 )     (4,269 )     (g)
Property damages reserves
    (1,000 )     (1,098 )     (h)
Injuries and damages reserves
    (123 )     (91 )     (h)
         
Total
  $ (28,752 )   $ (29,326 )        
         

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)   Amortized over 21 months ending in July 2006 as approved by the Georgia PSC.
 
(e)   Recorded and recovered or amortized as approved by the Georgia PSC. See “Storm Damage Reserve” herein and Note 3 under “Retail Regulatory Matters.”
 
(f)   Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed three years. Upon final settlement, costs are recovered through the fuel cost recovery clauses.
 
(g)   Amortized over three-year period ending in May 2005.
 
(h)   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

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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 currently reflected in rates.

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 life of the related property.

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 percent to 5 percent of construction expenditures depending upon the county in which the new facility is located. The Company’s policy is to recognize these credits when the tax return is filed. Manufacturer’s tax credits recorded on the Company’s books were $0.2 million in 2004, $0.1 million in 2003, and $0.3 million in 2002.

Depreciation and Amortization

Depreciation of the original cost of plant in service is provided primarily by using composite straight-line rates, which approximated 2.8 percent in 2004, 2.9 percent in 2003, and 2.9 percent in 2002. 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, the Company recorded accelerated depreciation of $1.0 million, in accordance with a 1998 Georgia PSC accounting order. In the 2002 rate order, the Georgia PSC 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 2004, 2003, and 2002, the Company amortized $3.0 million, $3.0 million, and $1.8 million, respectively. See Note 3 under “Retail Regulatory Matters – 2002 Retail Rate Case Orders” for additional information.

Asset Retirement Obligations and Other Costs of Removal

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 costs 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. Although 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 received guidance from the Georgia PSC allowing such treatment. Accordingly, the accumulated removal costs for other obligations previously accrued will continue to be reflected on the balance sheets as a regulatory liability. 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 statements of income 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.

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     Details of the asset retirement obligations included in the balance sheets are as follows:

                 
    2004     2003  
 
 
  (in thousands)
Balance beginning of year
  $ 4,220     $  
Liabilities incurred
          4,020  
Liabilities settled
    (598 )     (11 )
Accretion
    248       211  
 
Balance end of year
  $ 3,870     $ 4,220  
 

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 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. The average rates used by the Company to calculate AFUDC were 6.11 percent in 2004, 4.22 percent in 2003, and 2.82 percent in 2002. AFUDC as a percent of net income was 13.5 percent in 2004, 1.4 percent in 2003, and 0.5 percent in 2002.

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 rate order, the Company is deferring the costs of certain significant inspection 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. See Note 3 under “Plant McIntosh Construction Project” for information on a regulatory disallowance by the Georgia PSC in December 2004.

Storm Damage Reserve

The Company maintains a storm damage reserve for property damage to cover the cost of uninsured damages from major storms to transmission and distribution lines and other property. Under the 2002 rate order, the Company’s annual storm damage accrual level was set at $1.5 million.

Environmental Cost Recovery

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 may also incur substantial costs to clean up properties. The Company currently recovers environmental costs through its base rates.

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 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.

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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 of Southern Company stock 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.

     The pro forma impact of fair-value accounting for options granted is as follows:

                 
    As     Pro  
Net Income After Preferred Stock Dividends (in thousands)   Reported     Forma  
 
2004
  $ 24,232     $ 23,940  
2003 As Restated (Note 9)
  $ 23,459     $ 23,143  
2002 As Restated (Note 9)
  $ 21,319     $ 20,994  

     The estimated fair values of stock options granted in 2004, 2003, and 2002 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:

                         
    2004     2003     2002  
 
Interest rate
    3.1 %     2.7 %     2.8 %
Average expected life of stock options (in years)
    5.0       4.3       4.3  
Expected volatility of common stock
    19.6 %     23.6 %     26.3 %
Expected annual dividends on common stock
  $ 1.40     $ 1.37     $ 1.34  
Weighted average fair value of stock options granted
  $ 3.29     $ 3.59     $ 3.37  
 

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 Georgia PSC. 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 $2.4 million for 2002, $1.1 million for 2003, and $2.7 million for 2004 and will be $5.1 million for 2005. 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, 2004
  $ 233     $ 235  
At December 31, 2003
  $ 218     $ 220  

     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

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with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges and marketable securities, and changes in additional minimum pension liability, net of income taxes.

2. RETIREMENT BENEFITS

The Company has a defined benefit, trusteed pension plan covering substantially all employees. The plan is funded in accordance with the Employee Retirement Income Security Act of 1974, as amended (ERISA), requirements. No contributions to the plan are expected for the year ending December 31, 2005. 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 Georgia PSC and the FERC. For the year ended December 31, 2005, postretirement trust contributions are expected to total approximately $1.2 million.

     The measurement date for plan assets and obligations is September 30 for each year.

Pension Plans

The accumulated benefit obligation for the pension plans was $95.5 million in 2004 and $87.2 million in 2003. Changes during the year in the projected benefit obligations, accumulated benefit obligations, and fair value of plan assets were as follows:

                 
    Projected  
    Benefit Obligations  
    2004     2003  
 
    (in thousands)
Balance at beginning of year
  $ 94,789     $ 85,262  
Service cost
    2,478       2,175  
Interest cost
    5,551       5,409  
Benefits paid
    (4,575 )     (4,425 )
Actuarial loss and employee transfers
    5,162       6,137  
Amendments
    159       231  
 
Balance at end of year
  $ 103,564     $ 94,789  
 
                 
    Plan Assets  
    2004     2003  
 
    (in thousands)
Balance at beginning of year
  $ 47,490     $ 44,092  
Actual return on plan assets
    3,939       6,829  
Benefits paid
    (4,060 )     (3,909 )
Employee transfers
    1,187       478  
 
Balance at end of year
  $ 48,556     $ 47,490  
 

     Pension plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code of 1986, as amended (Internal 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.

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     Plan assets were invested as follows:

                         
    Plan Assets  
    Target     2004     2003  
 
Domestic equity
    37 %     36 %     37 %
International equity
    20       20       20  
Fixed income
    26       26       24  
Real estate
    10       10       11  
Private equity
    7       8       8  
 
Total
    100 %     100 %     100 %
 

     The reconciliation of the funded status with the accrued pension costs recognized in the balance sheets were as follows:

                 
    2004     2003  
 
    (in thousands)
Funded status
  $ (55,008 )   $ (47,299 )
Unrecognized prior service cost
    6,664       7,258  
Unrecognized net loss
    26,929       23,379  
 
Accrued liability recognized in the balance sheets
  $ (21,415 )   $ (16,662 )
 

     The accrued pension liability is reflected in the balance sheets in the following line items:

                 
    2004     2003  
 
    (in thousands)
Employee benefit obligations
  $ (26,601 )   $ (21,212 )
Other property and investments other
    1,634       1,652  
Accumulated other comprehensive income
    3,552       2,898  
 
Accrued liability recognized in the balance sheets
  $ (21,415 )   $ (16,662 )
 

     The amount of accumulated other comprehensive income recognized in the balance sheets relates to the minimum pension liability for non-qualified pension benefit obligations. There is no additional minimum pension liability related to the Company’s tax-qualified pension benefit obligations because they are part of Southern Company’s plan, which is fully funded at December 31, 2004.

     Components of the pension plans’ net periodic cost were as follows:

                         
    2004     2003     2002  
 
    (in thousands)
Service cost
  $ 2,479     $ 2,175     $ 2,204  
Interest cost
    5,551       5,409       5,811  
Expected return on plan assets
    (4,047 )     (4,186 )     (4,311 )
Recognized net loss
    532       152       54  
Net amortization
    753       740       672  
 
Net pension cost
  $ 5,268     $ 4,290     $ 4,430  
 

     Future benefit payments reflect expected future service and are estimated based on assumptions used to measure the projected benefit obligation for the pension plans. At December 31, 2004, estimated benefit payments were as follows:

         
    (in thousands)  
2005
  $ 4,876  
2006
    4,979  
2007
    5,161  
2008
    5,304  
2009
    5,561  
2010 to 2014
  $ 32,800  
 

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  
    2004     2003  
 
    (in thousands)
Balance at beginning of year
  $ 37,249     $ 32,702  
Service cost
    546       493  
Interest cost
    2,094       2,082  
Benefits paid
    (1,459 )     (1,319 )
Actuarial loss (gain) and amendments
    535       3,291  
 
Balance at end of year
  $ 38,965     $ 37,249  
 
                 
    Plan Assets  
    2004     2003  
 
    (in thousands)
Balance at beginning of year
  $ 11,275     $ 7,994  
Actual return on plan assets
    1,329       1,481  
Employer contributions
    2,209       3,119  
Benefits paid
    (1,459 )     (1,319 )
 
Balance at end of year
  $ 13,354     $ 11,275  
 

     Postretirement benefits plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal 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

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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        2004     2003  
 
Domestic equity
    52 %     51 %     51 %
International equity
    10       14       14  
Fixed income
    33       30       30  
Real estate
    3       3       3  
Private equity
    2       2       2  
 
Total
    100 %     100 %     100 %
 

     The accrued postretirement costs recognized in the balance sheets were as follows:

                 
    2004     2003  
 
    (in thousands)
Funded status
  $ (25,611 )   $ (25,974 )
Unrecognized transition obligation
    3,950       4,444  
Unamortized prior service cost
    1,651       4,167  
Unrecognized net loss
    10,986       8,886  
Fourth quarter contributions
    1,261       1,063  
 
Accrued liability recognized in the balance sheets
  $ (7,763 )   $ (7,414 )
 

     Components of the postretirement plans’ net periodic cost were as follows:

                         
    2004     2003     2002  
 
    (in thousands)
Service cost
  $ 546     $ 493     $ 431  
Interest cost
    2,094       2,082       2,065  
Expected return on plan assets
    (845 )     (732 )     (627 )
Recognized net loss
    205       91        
Net amortization
    756       756       756  
 
Net postretirement cost
  $ 2,756     $ 2,690     $ 2,625  
 

     In the third quarter 2004, the Company prospectively adopted FASB Staff Position (FSP) 106-2, Accounting and Disclosure Requirements related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (Medicare Act). The Medicare Act provides a 28 percent prescription drug subsidy for Medicare eligible retirees. FSP 106-2 requires recognition of the impacts of the Medicare Act in the accumulated postretirement benefit obligation (APBO) and future cost of service for postretirement medical plans. The effect of the subsidy reduced the Company’s expenses for the six months ended December 31, 2004 by approximately $0.2 million and is expected to have a similar impact on future expenses. The subsidy’s impact on the postretirement medical plan APBO was a reduction of approximately $3.5 million.

     Future benefit payments, including prescription drug benefits, reflect expected future service and are estimated based on assumptions used to measure the accumulated benefit obligation for the postretirement plans. Estimated benefit payments are reduced by drug subsidy receipts expected as a result of the Medicare Act as follows:

                         
    Benefit     Subsidy        
    Payments     Receipts     Total  
 
    (in thousands)
2005
  $ 1,568     $     $ 1,568  
2006
    1,738       (175 )     1,563  
2007
    1,890       (192 )     1,698  
2008
    2,090       (214 )     1,876  
2009
    2,314       (240 )     2,074  
2010 to 2014
  $ 14,473     $ (1,520 )   $ 12,953  
 

     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:

                         
    2004     2003     2002  
 
Discount
    5.75 %     6.00 %     6.50 %
Annual salary increase
    3.50       3.75       4.00  
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 11.00 percent for 2004, decreasing gradually to 5.00 percent through the year 2012, and remaining at that level thereafter.

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     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, 2004 as follows:

                 
    1 Percent     1 Percent  
    Increase     Decrease  
 
    (in thousands)
Benefit obligation
  $ 3,235     $ 2,408  
Service and interest costs
    151       136  
 

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 2004, 2003, and 2002 were $1.1 million, $1.1 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 and Georgia Power, alleging violations of the New Source Review (NSR) provisions of the Clean Air Act and related state laws at five coal-fired generating facilities. The EPA concurrently issued a notice of violation to the Company’s Plant Kraft. In early 2000, the EPA filed a motion to amend its complaint to add the Company as a defendant.

     The U.S. District Court for the Northern District of Georgia subsequently granted Alabama Power’s motion to dismiss and denied the EPA’s motion to add Gulf Power and Mississippi Power for lack of jurisdiction in Georgia. In March 2001, the court granted the EPA’s motion to add the Company as a defendant. 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 civil complaints allege violations with respect to eight coal-fired generating facilities in Alabama and Georgia, and they request penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The EPA has not refiled against Gulf Power or Mississippi Power.

     The actions against Alabama Power, Georgia Power, and the Company were effectively stayed in the spring of 2001 during the appeal of a similar NSR enforcement action against the Tennessee Valley Authority (TVA) before the U.S. Court of Appeals for the Eleventh Circuit. In June 2003, the Court of Appeals issued its ruling in the TVA case, dismissing the appeal for reasons unrelated to the issues in the cases pending against Alabama Power, Georgia Power, and the Company. In May 2004, the U.S. Supreme Court denied the EPA’s petition for review of the case. In June 2004, the U.S. District Court for the Northern District of Alabama lifted the stay in the action against Alabama Power, placing the case back onto the court’s active docket. At this time, no party to the case against Georgia Power and the Company has sought to reopen that case, which remains administratively closed in the U.S. District Court for the Northern District of Georgia.

     Since the inception of the NSR proceedings against Alabama Power, Georgia 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

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activities the utilities considered to be routine or otherwise not subject to NSR. District courts addressing these cases have, to date, issued opinions that reached conflicting conclusions.

     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 maximum civil penalties of $25,000 to $32,500 per day, per violation at each generating unit, depending on the date of the alleged violation. 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.

     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 (RMRR) exclusion. A coalition of states and environmental organizations has filed petitions for review of these revisions with the U.S. Court of Appeals for the District of Columbia Circuit. The October 2003 RMRR rules have been stayed by the Court of Appeals pending its review of the rules. 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, related legal challenges and potential state rulemakings cannot be determined at this time.

Generation Interconnection Agreements

In July 2003, the FERC issued its final rule on the standardization of generation interconnection agreements and procedures (Order 2003). Order 2003 shifts much of the financial burden of new transmission investment from the generator to the transmission provider. The FERC has indicated that Order 2003, which was effective January 20, 2004, is to be applied prospectively to interconnection agreements. The impact of Order 2003 and its subsequent rehearings on the Company and the final results of these matters cannot be determined at this time.

Market-Based Rate Authority

The Company has authorization from the FERC to sell power to non-affiliates at market-based prices. 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, the retail operating companies, and Southern Power, and found Southern Company and others to be “pivotal suppliers” in their retail service territories 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. In April 2004, the FERC issued an order that abandoned the SMA test and adopted a new interim analysis for measuring generation market power. This new interim approach requires utilities to submit a pivotal supplier screen and a wholesale market share screen. If the applicant does not pass both screens, there will be a rebuttable presumption regarding generation market power. The FERC’s order also sets forth procedures for rebutting these presumptions and addresses mitigation measures for those entities that are found to have market power. In the absence of specific mitigation measures, the order includes several cost-based mitigation measures that would apply by default. The FERC also initiated a new rulemaking proceeding that, among other things, will adopt a final methodology for assessing generation market power.

     In July 2004, the FERC denied Southern Company’s request for rehearing, along with a number of others, and reaffirmed the interim tests that it adopted in April 2004. In August 2004, Southern Company submitted a filing to the FERC that included results showing that Southern Company passed the pivotal supplier screen for all markets and the wholesale market share screen for all markets except the Southern Company retail service territory. Southern Company also submitted other analyses to demonstrate that it lacks generation market power. On December 17, 2004, the FERC initiated a proceeding to assess Southern Company’s generation dominance within its retail service territory. The ability to charge market-based rates in other markets is not at issue. As directed by this order, Southern Company submitted additional information on February 15, 2005 related to generation

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dominance in the Southern Company retail service territory. Any new market based rate transactions in the Southern Company retail service territory entered into after February 27, 2005 will be subject to refund to the level of the default cost-based rates, pending the outcome of the proceeding. Southern Company, along with other utilities, has also filed an appeal of the FERC’s April and July 2004 orders with the U.S. Court of Appeals for the District of Columbia Circuit. The FERC has asked the court to dismiss the appeal on the grounds that it is premature.

     In the event that the FERC’s default mitigation measures are ultimately applied, the Company may be required to charge cost-based rates for certain wholesale sales in the Southern Company retail service territory, which may be lower than negotiated market-based rates. The final outcome of this matter will depend on the form in which the final methodology for assessing generation market power and mitigation rules may be ultimately adopted and cannot be determined at this time.

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, 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 it in pending and future right of way litigation. The Company believes that the plaintiff’s claims are without merit. In the fall of 2004, the trial court stayed the case until resolution of an underlying landowner litigation involving Southern Company and certain of its subsidiaries. On January 12, 2005, the Georgia Court of Appeals dismissed the telecommunications company’s appeal of the trial court’s order for lack of jurisdiction. An adverse outcome in this case could result in a substantial judgment; however, the final outcome of this matter cannot now be determined.

Retail Regulatory Matters

Fuel Cost Recovery

On October 25, 2004, the Georgia PSC approved the Company’s request for a fuel cost recovery rate increase. The approved increase will allow for the recovery of approximately $161 million in fuel costs, which includes an estimate of future fuel costs over the next 12 months and recovery of the existing under recovered fuel balance, over the next 24 months. The approved fuel rate increase also includes the recovery of approximately $3.5 million in costs associated with a coal transloader to be amortized over a 21-month period, which the Georgia PSC had denied in June 2004. The transloader allows foreign coal to be off-loaded from ships at the Company’s Plant Kraft dock and then transferred by rail to Plant McIntosh. The new rates became effective in November 2004. At December 31, 2004, the Company had $23.8 million included in under recovered regulatory clause revenues on the balance sheet.

2004 Retail Rate Case Filing

On November 30, 2004, the Company filed a traditional one-year rate case with the Georgia PSC requesting a $23.2 million, or 6.7 percent, increase in retail revenues, effective January 1, 2005. The requested increase is based on a future test year ending December 31, 2005 and a proposed retail return on common equity of 12.5 percent. As an alternative, the Company has also included in its request a three-year rate plan that is based on the same test year and proposed retail return on common equity.

     The increase in retail revenues is being requested to cover the Company’s investment in the new Plant McIntosh Combined Cycle Units 10 and 11; increasing operating and maintenance expenses; and continued investment in generation, transmission, and distribution facilities to support growth and ensure reliability. The increase also includes recognition on an annual basis of the $3.8 million of Plant Wansley purchased power expenses which were excluded by the Georgia PSC from the Company’s last rate case and subsequently were subject to deferral through a Georgia PSC accounting order issued in December 2002.

     The Company expects the Georgia PSC to issue a final order in this matter during May 2005. The final outcome of this matter cannot now be determined.

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2002 Retail Rate Case Orders

In May 2002, the Georgia PSC approved a $7.8 million base rate increase and an authorized return on equity of 12 percent as a result of the Company’s request to recover significant new expenses related to the Plant Wansley PPA which began in June 2002, as well as other operation and maintenance expense changes. In December 2002, at the Company’s request, the Georgia PSC 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 Georgia PSC 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 also 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 2004, the Company had amortized all of the deferred purchased power costs.

     Under the 2002 rate order, the Georgia PSC also ordered the Company to amortize approximately $9 million of accelerated depreciation and amortization previously recorded equally over three years as a credit to expense beginning June 1, 2002.

Plant McIntosh Construction Project

In December 2002, after a competitive bidding process, the Georgia PSC certified PPAs between Southern Power and Georgia Power and the Company for capacity from Plant McIntosh Combined Cycle Units 10 and 11, construction of which is scheduled to be completed in June 2005. In April 2003, Southern Power applied for FERC approval of these PPAs. In July 2003, the FERC accepted the PPAs to become effective June 1, 2005, subject to refund, and ordered that hearings be held. Intervenors opposed the FERC’s acceptance of the PPAs, alleging that they did not meet applicable standards for market-based rates between affiliates. To ensure the timely completion of the Plant McIntosh construction project and the availability of the units in the summer of 2005 for their retail customers, the Company and Georgia Power in May 2004 requested the Georgia PSC to direct them to acquire the Plant McIntosh construction project. The Georgia PSC issued such an order and the transfer occurred on May 24, 2004 at a total cost of approximately $415 million, including $14 million of transmission interconnection facilities. Subsequently, Southern Power filed a request to withdraw the PPAs and to terminate the ongoing FERC proceedings. In August 2004, the FERC issued a notice accepting the request to withdraw the PPAs and permitting such request to become effective by operation of law. However, the FERC made no determination on what additional steps may need to be taken with respect to testimony provided in the proceedings. The ultimate outcome of any additional FERC action cannot now be determined.

     As directed by the Georgia PSC order, Georgia Power and the Company in June 2004 filed an application to amend the resource certificate granted by the Georgia PSC in 2002. In connection with the Georgia Power 2004 retail rate case, the Georgia PSC approved the transfer of the Plant McIntosh construction project, at a total fair market value of approximately $385 million. This value reflects an approximate $16 million disallowance. Savannah Electric owns 16.129 percent of the project; thus, this disallowance amounted to approximately $3 million and reduced the Company’s net income by approximately $1.5 million. The Georgia PSC also certified a total completion cost of $547 million for the project. The amount of the disallowance will be adjusted accordingly based on the actual completion cost of the project. The Georgia PSC will determine the rate treatment of Plant McIntosh in connection with its decision on the Company’s 2004 retail rate case filing discussed above. The final 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, totaling 160 megawatts of capacity, are owned by the Company, and six units, totaling 480 megawatts of capacity, are owned by Georgia Power. The Company’s amount of investment in Plant McIntosh combustion turbines and related accumulated depreciation at December 31, 2004 were $52 million and $13 million, respectively. The Company’s proportionate share of its combustion turbine plant operating expenses is included in the corresponding operating expenses in the statements of income.

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     In addition, the Company and Georgia Power acquired the Plant McIntosh Combined Cycle Units 10 and 11 construction project in 2004. The units, which will have a total capacity of 1,240 megawatts, scheduled to begin operation in June 2005, will be jointly owned by the Company and Georgia Power. The Company’s investment in Plant McIntosh Units 10 and 11 at December 31, 2004 was $78.4 million.

5. INCOME TAXES

Southern Company and its subsidiaries file a consolidated federal income tax return and a combined State of Georgia income tax return. Under a joint consolidated income tax allocation agreement, as required by the PUHCA, each subsidiary’s current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more expense than would be paid if they filed a separate tax return. In accordance with Internal Revenue Service regulations, each company is jointly and severally liable for the tax liability.

     In 2004, in order to avoid the loss of certain federal income tax credits related to the production of synthetic fuel, Southern Company chose to defer certain deductions otherwise available to the subsidiaries. The cash flow benefit associated with the utilization of the tax credits was allocated to the subsidiary that otherwise would have claimed the available deductions on a separate company basis without the deferral. This allocation concurrently reduced the tax benefit of the credits allocated to those subsidiaries that generated the credits. As the deferred expenses are deducted, the benefit of the tax credits will be repaid to the subsidiaries that generated the tax credits. The Company has recorded $1.5 million payable to these subsidiaries in “Accumulated Deferred Income Taxes” on the accompanying December 31, 2004 balance sheet.

     The transfer of the Plant McIntosh construction project from Southern Power to the Company resulted in a deferred gain to Southern Power for federal income tax purposes. The Company will reimburse Southern Power for $1.0 million of this deferred tax liability as it is reflected in Southern Power’s future taxable income. The payable to Southern Power is included in Other Deferred Credits on the Company’s balance sheet at December 31, 2004.

     At December 31, 2004, tax-related regulatory assets and liabilities were $10.6 million and $8.7 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:

                         
    2004     2003     2002  
     
    (in thousands)
Total provision for income taxes
                       
Federal —
                       
Currently payable
  $ 246     $ 12,074     $ 16,248  
Deferred
    12,171       1,299       (5,660 )
 
 
    12,417       13,373       10,588  
 
State —
                       
Currently payable
    691       2,791       1,428  
Deferred
    1,270       (646 )     (568 )
 
 
    1,961       2,145       860  
 
Total
  $ 14,378     $ 15,518     $ 11,448  
 

     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:

                 
    2004     2003  
     
    (in thousands)
Deferred tax liabilities:
               
Accelerated depreciation
  $ 94,124     $ 88,332  
Property basis differences
    (845 )     (1,640 )
Other
    13,539       2,696  
 
Total
    106,818       89,388  
 
Deferred tax assets:
               
Pension and other benefits
    17,353       15,671  
Other
    15,703       14,284  
 
Total
    33,056       29,955  
 
Total deferred tax liabilities, net
    73,762       59,433  
Portion included in current assets, net
    16,317       24,419  
 
Accumulated deferred income taxes in the Balance Sheets
  $ 90,079     $ 83,852  
 

     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 2004, 2003, and 2002. At December 31, 2004, all investment tax credits available to reduce federal income taxes payable had been utilized.

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     A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:

                         
    2004     2003     2002  
   
Federal statutory tax rate
    35 %     35 %     35 %
State income tax, net of Federal income tax benefit
    3       4       2  
Other
    (2 )     1       (2 )
 
Effective income tax rate
    36 %     40 %     35 %
 

6. FINANCING

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:

                 
    2004     2003  
   
    (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
    1,010       910  
 
Total
  $ 1,010     $ 40,910  
 

     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 certifying property additions in 2003 and 2004. The 2005 requirement will be satisfied by certifying property additions. Sinking fund requirements and/or maturities through 2009 applicable to long-term debt are as follows: $1.0 million in 2005; $21.0 million in 2006; $0.9 million in 2007; $46.0 million in 2008; and $0.8 million in 2009.

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 2005, credit arrangements with banks totaled $80 million, of which $70 million expires at various times in 2005 and the remaining $10 million expires in 2007. Of the facilities that expire in 2005, $40 million contain two-year term out provisions and the $10 million facility that expires in 2007 contains a three-year term out provision. 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, $10 million was borrowed under the agreement in May 2004, and the full $30 million was repaid in December 2004.

     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 one-eighth 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 arrangements. 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

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in compliance with all such covenants. Borrowings under unused credit arrangements totaling $30 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 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, 2004, the Company had $12.6 million in commercial paper and $8.0 million in extendible commercial notes outstanding. During 2004, the peak amount of commercial paper outstanding was $29.1 million and the average amount outstanding was $8.4 million. The average annual interest rate on commercial paper was 1.51 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, 2004, the amount of variable rate obligations outstanding requiring liquidity support was $7.2 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 direction of the Georgia PSC. The Company also enters into hedges of forward electricity sales. There was no material ineffectiveness recorded in earnings in 2004 and 2003.

     At December 31, 2004, the fair value of derivative energy contracts was reflected in the financial statements as follows:

           
    Amounts  
   
 
  (in thousands)
Regulatory liabilities, net
  $ 1,471  
Other comprehensive income
    -  
Net income
    3  
 
Total fair value
  $ 1,474  
 
 

     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 has energy-related hedges in place up to and including 2007.

     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, 2004, the Company had $14.0 million notional amount of interest rate swaps outstanding with net fair value gains of $0.1 million as follows:

Cash Flow Hedges

                           
    Weighted Average             Fair    
    Fixed             Value    
    Rate     Notional     Gain/    
Maturity   Paid     Amount     (Loss)    
 
            (in millions)    
2007
    2.50%*   $ 14.0     $ 0.1    
 

    *Swap settles against the Bond Market Association floating rate index.

     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, approximately $0.1 million of pre-tax losses were reclassified from other comprehensive income to interest expense. For 2003, the amount reclassified was not material. For 2005, pre-tax losses of approximately $0.1 million are expected to be reclassified from other comprehensive income to interest

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expense. The Company has interest-related hedges in place up to and including 2007, and additionally has losses that are being amortized up to and including 2014.

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, 2004, 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 $52.4 million in 2005, $39.2 million in 2006, and $33.7 million in 2007. The construction program is subject to periodic review and revision, and actual construction costs may vary from the above estimates because of numerous factors. These factors include: changes in business conditions; acquisition of additional generating assets; revised load growth estimates; changes in environmental regulations; changes in FERC rules and transmission regulations; increasing costs of labor, equipment, and materials; and cost of capital. Units 10 and 11 at Plant McIntosh, being constructed and to be owned jointly with Georgia Power, are scheduled to be placed in service in June 2005. 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, 2004, significant purchase commitments were outstanding in connection with the construction program.

Long-Term Service Agreement

The Company and Georgia Power have entered into a Long-Term Service Agreement (LTSA) with General Electric (GE) for the purpose of securing maintenance support for the combustion turbines at the Plant McIntosh combined cycle facility. 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 this LTSA is 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 by the Company to GE under this agreement are currently estimated at $35 million over the remaining life of the agreement, which may range up to 30 years. However, the LTSA contains various cancellation provisions at the option of the Company and Georgia Power.

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. Coal commitments include forward contract purchases for nitrogen oxide and sulfur dioxide emission allowances. 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 time of delivery. Amounts included in the chart below represent estimates based on New York Mercantile Exchange future prices at December 31, 2004.

     Total estimated minimum long-term obligations at December 31, 2004 were as follows:

                 
Year   Natural
Gas
    Coal  
 
    (in thousands)  
2005
  $ 26,296     $ 50,301  
2006
    26,485       6,771  
2007
    15,655        
2008
    32,974        
2009
    30,811        
2010 and thereafter
    285,322        
 
Total commitments
  $ 417,543     $ 57,072  
 

     Additional commitments for fuel will be required to supply the Company’s future needs.

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     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, 2004 were as follows:

         
Year   Commitments  
 
 
  (in thousands)
2005
  $ 13,262  
2006
    13,271  
2007
    13,283  
2008
    13,295  
2009
    13,307  
2010 and thereafter
     
 
Total commitments
  $ 66,418  
 

Operating Leases

The Company has rental agreements with various terms and expiration dates. Rental expenses totaled $0.9 million for 2004, $0.9 million for 2003, and $0.6 million for 2002. Of these amounts, $0.8 million in 2004, $0.8 million in 2003, and $0.5 million in 2002 related to railcar leases and coal dozers and were recoverable through the Company’s fuel cost recovery clause.

     At December 31, 2004, estimated future minimum lease payments for noncancelable operating leases were as follows:

                         
Year   Railcars     Other     Total  
 
    (in thousands)
2005
  $ 429     $ 417     $ 846  
2006
    429       381       810  
2007
    429       379       808  
2008
    429       324       753  
2009
    429       219       648  
2010 and thereafter
    3,608             3,608  
 
Total minimum payments
  $ 5,753     $ 1,720     $ 7,473  
 

8. STOCK OPTION PLAN

Southern Company provides non-qualified stock options to a large segment of the Company’s employees ranging from line management to executives. As of December 31, 2004, 93 current and former employees of the Company participated in the stock option plan. The maximum number of shares of Southern Company common stock that may be issued under this plan may not exceed 55 million. The prices of options granted to date have been at the fair market value of the shares on the dates of grant. Options granted to date become exercisable pro rata over a maximum period of three years from the date of grant. Options outstanding will expire no later than 10 years after the date of grant, unless terminated earlier by the Southern Company Board of Directors in accordance with the stock option plan. Activity from 2002 to 2004 for the options granted to the Company’s employees under the stock option plan is summarized below.

                 
    Shares     Average  
    Subject     Option Price  
    To Option     Per Share  
 
Balance at December 31, 2001
    584,677     $ 17.12  
Options granted
    144,060       25.26  
Options canceled
    (948 )     17.52  
Options exercised
    (177,515 )     14.29  
 
Balance at December 31, 2002
    550,274       20.16  
Options granted
    125,397       27.98  
Options canceled
    (8,410 )     25.60  
Options exercised
    (137,580 )     17.46  
 
Balance at December 31, 2003
    529,681       22.62  
Options granted
    118,209       29.50  
Options canceled
    (3,708 )     28.21  
Options exercised
    (90,899 )     18.12  
 
Balance at December 31, 2004
    553,283     $ 24.80  
 

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Options exercisable:
       
At December 31, 2002
    210,436  
At December 31, 2003
    251,576  
At December 31, 2004
    318,250  

     The following table summarizes information about options outstanding at December 31, 2004:

                         
    Dollar Price  
    Range of Options  
    13-20     20-26     26-32  
 
Outstanding:
                       
Shares (in thousands)
    110       209       234  
Average remaining life (in years)
    5.7       6.8       8.6  
Average exercise price
  $ 17.77     $ 24.09     $ 28.73  
Exercisable:
                       
Shares (in thousands)
    110       168       40  
Average exercise price
  $ 17.77     $ 23.80     $ 28.00  
 

9. RESTATEMENT

These financial statements have been restated to reflect adjustments to the Company’s financial information previously reported on Form 10-K for the years ended December 31, 2003 and 2002. The restatement also affects periods prior to 2002. The restatements arose as a result of errors in the Company’s estimates of unbilled revenues in these prior periods. Unbilled revenues represent an estimate of the kilowatt-hour (KWH) sales of electricity delivered to customers, but not yet billed. Components of the unbilled revenue estimates include total KWH territorial supply, total KWH billed, total electricity lost in delivery (line losses), and customer usage. These components are affected by a number of factors including weather, generation patterns, power delivery volume, and other operational constraints.

     The errors in the Company’s estimates were identified through comparisons of the Company’s unbilled revenue account balance at December 31, 2004 to the billed KWH sales recorded in January 2005 made in connection with the Company’s 2004 audit. The Company analyzed the unbilled revenue calculations for the years 1999 through 2004 to determine the timing and source of the errors, which primarily related to the estimates of line losses. For years through 2002, line losses were understated and total unbilled revenues were overstated. However, in 2003, the Company revised its methodology of estimating line losses, which had the effect of overstating the line losses, and, thus, understating total unbilled revenues during 2003. Since the Company’s calculation of unbilled revenues utilized a net change methodology, the cumulative effect of each of these errors was carried forward. The effect of these errors increased (reduced) the Company’s earnings before income taxes by $1.1 million ($0.7 million after tax) and ($2.5) million (($1.6) million after tax) for the years ended December 31, 2003 and 2002, respectively. The cumulative impact related to years prior to 2002 was a decrease in retained earnings of $2.3 million at January 1, 2002.

     Management and the Company’s external auditors discussed these adjustments with the Audit Committee of Southern Company’s Board of Directors on February 24, 2005. The restated financial statements have been prepared by management and reflect all related adjustments known to management. Management has also revised its process of estimating unbilled revenues to utilize a gross change methodology that reverses each period’s estimate in total in the following period.

     These restatement adjustments affect the Company’s previously issued statements of income, comprehensive income, and common stockholder’s equity for the years ended December 31, 2003 and 2002 and the Company’s balance sheet at December 31, 2003.

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NOTES (continued)
Savannah Electric and Power Company 2004 Annual Report

A summary of the effects of these restatement adjustments is as follows (in thousands of dollars):

                                 
    Years Ended  
    December 31, 2003     December 31, 2002  
    As Originally     As     As Originally     As  
    Reported     Restated     Reported     Restated  
         
Retail sales revenues
  $ 297,745     $ 298,807     $ 285,771     $ 283,225  
Total operating revenues
    314,055       315,117       299,552       297,006  
Operating income
    50,457       51,519       50,814       48,268  
Earnings before income taxes
    37,915       38,977       35,313       32,767  
Income taxes
    15,108       15,518       12,433       11,448  
Net income
    22,807       23,459       22,880       21,319  
Comprehensive income
  21,847     22,499     21,636     20,075  
 
                 
    At December 31, 2003  
    As Originally     As  
    Reported     Restated  
     
Unbilled revenues receivable
  $ 11,288     $ 6,064  
Prepaid income taxes
    24,419       25,981  
Total current assets
    118,415       114,752  
Total assets
    709,921       706,259  
Accrued income taxes
    1,172       713  
Total current liabilities
    93,512       93,053  
Total liabilities
    523,629       523,170  
Retained earnings
    109,856       106,653  
Total common stockholder’s equity
    186,292       183,089  
Total capitalization
    408,785       405,582  
Total liabilities and stockholder’s equity
  709,921     706,259  
 

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NOTES (continued)
Savannah Electric and Power Company 2004 Annual Report

10. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

Summarized quarterly financial data for 2004 and 2003 are as follows:

                         
                Net  
                Income  
                after  
                Preferred  
    Operating     Operating     Stock  
Quarter Ended   Revenues     Income     Dividends  
 
    (in thousands)
March 2004 (1)
  $ 72,321     $ 8,032     $ 2,833  
June 2004 (1)
    91,149       13,971       6,784  
September 2004 (1)
    107,889       24,816       13,416  
December 2004
    85,601       6,284       1,199  
 
                       
March 2003 (1)
  $ 68,765     $ 8,906     $ 3,442  
June 2003 (1)
    78,748       14,040       6,605  
September 2003 (1)
    100,030       26,499       14,939  
December 2003 (1)
    67,574       2,074       (1,527 )
 

     The Company’s business is influenced by seasonal weather conditions and a seasonal rate structure, among other factors.

     
(1)
  The restatement adjustments described in Note 9 also affected the Company’s previously issued statements of income for the quarters ended March 31, June 30, and September 30, 2004 and 2003 and December 31, 2003. A summary of the effects of those restatement adjustments is as follows (in thousands of dollars):
                                                 
    Three Months Ended     Six Months Ended  
    March 31, 2004     June 30, 2004     June 30, 2004  
    As Originally     As     As Originally     As     As Originally     As  
    Reported     Restated     Reported     Restated     Reported     Restated  
             
Retail sales revenues
  $ 68,023     $ 67,509     $ 88,437     $ 87,516     $ 156,460     $ 155,025  
Total operating revenues
    72,835       72,321       92,070       91,149       164,905       163,470  
Operating income
    8,546       8,032       14,892       13,971       23,438       22,003  
Earnings before income taxes
    4,946       4,433       11,830       10,908       16,776       15,341  
Income taxes
    1,798       1,600       4,331       3,974       6,129       5,574  
Net income
    3,148       2,833       7,499       6,934       10,647       9,767  
Net income after dividends on preferred stock
    3,148       2,833       7,349       6,784       10,497       9,617  
Comprehensive income
  3,139     2,824     7,390     6,825     10,529     9,649  
 
                                 
    Three Months Ended     Nine Months Ended  
    September 30, 2004     September 30, 2004  
    As Originally     As     As Originally     As  
    Reported     Restated     Reported     Restated  
         
Retail sales revenues
  $ 102,312     $ 104,822     $ 258,772     $ 259,847  
Total operating revenues
    105,379       107,889       270,284       271,359  
Operating income
    22,306       24,816       45,744       46,819  
Earnings before income taxes
    19,813       22,323       36,589       37,664  
Income taxes
    7,262       8,232       13,391       13,806  
Net income
    12,551       14,091       23,198       23,858  
Net income after dividends on preferred stock
    11,876       13,416       22,373       23,033  
Comprehensive income
  11,902     13,442     22,431     23,091  
 

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    Three Months Ended     Six Months Ended  
    March 31, 2003     June 30, 2003     June 30, 2003  
    As Originally     As     As Originally     As     As Originally     As  
    Reported     Restated     Reported     Restated     Reported     Restated  
             
Retail sales revenues
  $ 63,546     $ 63,437     $ 75,468     $ 75,973     $ 139,014     $ 139,410  
Total operating revenues
    68,874       68,765       78,243       78,748       147,117       147,513  
Operating income
    9,015       8,906       13,535       14,040       22,550       22,946  
Earnings before income taxes
    5,500       5,391       10,016       10,520       15,516       15,911  
Income taxes
    1,991       1,949       3,720       3,915       5,711       5,864  
Net income
    3,509       3,442       6,296       6,605       9,805       10,047  
Net income after dividends on preferred stock
    3,509       3,442       6,296       6,605       9,805       10,047  
Comprehensive income
  3,509     3,442     6,296     6,605     9,805     10,047  
 
                                 
    Three Months Ended     Nine Months Ended  
    September 30, 2003     September 30, 2003  
    As Originally     As     As Originally     As  
    Reported     Restated     Reported     Restated  
         
Retail sales revenues
  $ 95,364     $ 96,279     $ 234,378     $ 235,689  
Total operating revenues
    99,115       100,030       246,232       247,543  
Operating income
    25,584       26,499       48,134       49,445  
Earnings before income taxes
    23,305       24,220       38,821       40,131  
Income taxes
    8,927       9,281       14,638       15,145  
Net income
    14,378       14,939       24,183       24,986  
Net income after dividends on preferred stock
    14,378       14,939       24,183       24,986  
Comprehensive income
  13,658     14,219     23,463     24,266  
 
                 
    Three Months Ended  
    December 31, 2003  
    As Originally     As  
    Reported     Restated  
     
Operating revenues
  $ 67,823     $ 67,574  
Operating income
    2,323       2,074  
Net income
    (1,376 )     (1,527 )

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SELECTED FINANCIAL AND OPERATING DATA 2000-2004
Savannah Electric and Power Company 2004 Annual Report

                                       
   
    2004   2003     2002     2001     2000  
 
Operating Revenues (in thousands)
  $ 356,960   $ 315,117  (1)   $ 297,006  (1)   $ 282,926  (1)   $ 292,903  (1)
Net Income after Dividends on Preferred Stock (in thousands)
  $ 24,232   $ 23,459  (1)   $ 21,319  (1)   $ 21,495  (1)   $ 21,243  (1)
Cash Dividends on Common Stock (in thousands)
  $ 23,200   $ 23,000     $ 22,700     $ 21,700     $ 24,300  
Return on Average Common Equity (percent)
    11.67     13.07  (1)     12.16  (1)     12.36  (1)     12.20  (1)
Total Assets (in thousands)
  $ 812,591   $ 706,259  (1)   $ 644,923  (1)   $ 617,282  (1)   $ 612,529  (1)
Gross Property Additions (in thousands)
  $ 126,133   $ 40,242     $ 32,481     $ 31,296     $ 27,290  
 
Capitalization (in thousands):
                                     
Common stock equity
  $ 232,156   $ 183,089  (1)   $ 175,949  (1)   $ 174,624  (1)   $ 173,268  (1)
Preferred stock
    43,938                        
Mandatorily redeemable preferred securities
              40,000       40,000       40,000  
Long-term debt
    237,769     222,493       168,052       160,709       116,902  
 
Total (excluding amounts due within one year)
  $ 513,863   $ 405,582     $ 384,001     $ 375,333     $ 330,170  
 
Capitalization Ratios (percent):
                                     
Common stock equity
    45.2     45.1  (1)     45.8  (1)     46.5  (1)     52.5  (1)
Preferred stock
    8.6                        
Mandatorily redeemable preferred securities
              10.4       10.7       12.1  
Long-term debt
    46.2     54.9       43.8       42.8       35.4  
 
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+  
Preferred Stock -
                                     
Moody’s
  Baa1   Baa1     Baa1     Baa1       a2  
Standard and Poor’s
  BBB+   BBB+     BBB+     BBB+     BBB+  
Unsecured Long-Term Debt -
                                     
Moody’s
    A2     A2       A2       A2        
Standard and Poor’s
    A     A       A       A        
 
Customers (year-end):
                                     
Residential
    124,789     122,128       120,131       117,199       115,646  
Commercial
    17,964     17,102       16,512       16,121       15,727  
Industrial
    89     90       81       76       75  
Other
    533     506       494       474       444  
 
Total
    143,375     139,826       137,218       133,870       131,892  
 
Employees (year-end):
    563     549       550       550       554  
 
     
(1)
  As Restated — See Note 9 to the financial statements.

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SELECTED FINANCIAL AND OPERATING DATA 2000-2004 (continued)
Savannah Electric and Power Company 2004 Annual Report

                                         
   
    2004     2003     2002     2001     2000  
 
Operating Revenues (in thousands):
                                       
Residential
  $ 164,889     $ 143,461  (1)   $ 137,767  (1)   $ 123,394  (1)   $ 128,288  (1)
Commercial
    120,907       106,433  (1)     103,293  (1)     100,484  (1)     101,196  (1)
Industrial
    44,600       38,767  (1)     32,434  (1)     34,852  (1)     40,269  (1)
Other
    11,370       10,146  (1)     9,731  (1)     9,516  (1)     10,054  (1)
 
Total retail
    341,766       298,807  (1)     283,225  (1)     268,246  (1)     279,807  (1)
Sales for resale — non-affiliates
    5,035       5,653       6,354       8,884       4,748  
Sales for resale — affiliates
    6,130       6,499       4,075       3,205       4,974  
 
Total revenues from sales of electricity
    352,931       310,959  (1)     293,654  (1)     280,335  (1)     289,529  (1)
Other revenues
    4,029       4,158       3,352       2,591       3,374  
 
Total
  $ 356,960     $ 315,117  (1)   $ 297,006  (1)   $ 282,926  (1)   $ 292,903  (1)
 
Kilowatt-Hour Sales (in thousands):
                                       
Residential
    1,899,462       1,753,885  (1)     1,755,967  (1)     1,648,102  (1)     1,640,292  (1)
Commercial
    1,539,536       1,461,191  (1)     1,454,674  (1)     1,379,583  (1)     1,346,416  (1)
Industrial
    840,572       860,840  (1)     791,422  (1)     784,688  (1)     785,894  (1)
Other
    142,732       137,158  (1)     137,913  (1)     133,210  (1)     133,534  (1)
 
Total retail
    4,422,302       4,213,074  (1)     4,139,976  (1)     3,945,583  (1)     3,906,136  (1)
Sales for resale — non-affiliates
    131,259       162,469       150,795       111,145       77,481  
Sales for resale — affiliates
    142,871       185,202       125,882       87,799       88,646  
 
Total
    4,696,432       4,560,745  (1)     4,416,653  (1)     4,144,527  (1)     4,072,263  (1)
 
Average Revenue Per Kilowatt-Hour (cents):
                                       
Residential
    8.68       8.18  (1)     7.85  (1)     7.49  (1)     7.82  (1)
Commercial
    7.85       7.28  (1)     7.10  (1)     7.28  (1)     7.52  (1)
Industrial
    5.31       4.50  (1)     4.10  (1)     4.44  (1)     5.12  (1)
Total retail
    7.73       7.09  (1)     6.84  (1)     6.80  (1)     7.16  (1)
Sales for resale
    4.07       3.50       3.77       6.08       5.85  
Total sales
    7.51       6.82  (1)     6.65  (1)     6.76  (1)     7.11  (1)
Residential Average Annual Kilowatt-Hour Use Per Customer
    15,388       14,493  (1)     14,771  (1)     14,150  (1)     14,324  (1)
Residential Average Annual Revenue Per Customer
    $1,336       $1,185  (1)     $1,159  (1)     $1,059  (1)     $1,120  (1)
Plant Nameplate Capacity Ratings (year-end) (megawatts)
    765       788       788       788       788  
Maximum Peak-Hour Demand (megawatts):
                                       
Winter
    805       882       738       758       724  
Summer
    949       904       921       846       878  
Annual Load Factor (percent)
    56.3       56.8       54.5       55.9       53.4  
Plant Availability Fossil-Steam (percent):
    77.1       83.3       81.4       81.2       78.5  
 
Source of Energy Supply (percent):
                                       
Coal
    41.2       44.7       44.4       50.5       51.6  
Oil and gas
    1.9       2.7       4.2       4.0       6.9  
Purchased power -
                                       
From non-affiliates
    5.4       3.1       3.1       5.3       7.7  
From affiliates
    51.5       49.5       48.3       40.2       33.8  
 
Total
    100.0       100.0       100.0       100.0       100.0  
 
     
(1)
  As Restated — See Note 9 to the financial statements.

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SOUTHERN POWER COMPANY

 
 
 
FINANCIAL SECTION
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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, 2004 and 2003, 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, 2004. 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 the standards of the Public Company Accounting Oversight Board (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 consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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-330 to II-343) present fairly, in all material respects, the financial position of Southern Power Company at December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP
Atlanta, Georgia
February 28, 2005

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION
Southern Power Company 2004 Annual Report

OVERVIEW

Business Activities

Southern Power Company (Company) constructs, owns and manages Southern Company’s competitive generation assets and sells electricity at market-based rates in the Super-Southeast wholesale market. The Company focused on executing its regional strategy in 2004 by signing several wholesale contracts with major utilities, as well as electric cooperatives and municipal suppliers, in the Southeast. The Company’s typical wholesale contract is now more than 11 years in duration, which reduces remarketing risk until the middle of the next decade. However, the Company continues to face challenges related to market power issues at the federal regulatory level, specifically the ability to charge market-based rates.

Key Performance Indicators

To evaluate operating results and to ensure the Company’s ability to meet its contractual commitments to customers, the Company focuses on two key performance indicators. These indicators consist of plant availability and peak season equivalent forced outage rate (EFOR). Plant availability shows the percentage of time during the year that the Company’s generating units are available to be called upon to generate (the higher the better), where as the EFOR more narrowly defines the hours during peak demand times when the Company’s generating units are not available due to forced outages (the lower the better). The Company’s actual performance in 2004 significantly surpassed targets in these key performance areas.

Earnings

The Company’s 2004 earnings were $112 million, a $44 million decrease over 2003. The 2004 decrease is primarily attributed to a one-time $50 million gain recognized in May 2003 upon the termination of Dynegy, Inc.’s (Dynegy) obligations under power purchase agreements (PPAs). This one-time item was partially offset by the effect of a full year’s operation of Plant Stanton A, which went into service in October 2003, and Plant Harris Units 1 and 2 and Plant Franklin Unit 2, which all went into service in June 2003. As of December 31, 2004, the Company had approximately 4,775 megawatts in commercial operation.

     The Company’s 2003 earnings were $155 million, a $101 million increase over 2002. The 2003 increase is attributed to new wholesale capacity and energy contracts, primarily PPAs relating to units placed in service during 2003 (Plant Franklin Unit 2, Plant Harris Units 1 and 2 and Plant Stanton A), and to the Dynegy PPA termination gain of $50 million.

RESULTS OF OPERATIONS

A condensed income statement is as follows:

                                 
            Increase (Decrease)  
    Amount     From Prior Year  
    2004     2004     2003     2002  
    (in thousands)  
Operating revenues
  $ 701,311     $ 19,531     $ 383,012     $ 269,467  
 
Fuel
    127,103       11,847       17,291       94,186  
Purchased power
    188,456       3,155       131,638       48,937  
Other operation and maintenance
    75,195       12,954       33,890       21,726  
Depreciation and amortization
    51,161       12,149       20,693       15,028  
Taxes other than income taxes
    11,273       4,608       2,390       3,882  
 
Total operating expenses
    453,188       44,713       205,902       183,759  
 
Operating income
    248,123       (25,182 )     177,110       85,708  
Other income, net
    2,408       4,002       2,988       (5,240 )
Less —
                               
Interest expense and other, net
    66,088       34,380       22,822       8,459  
Income taxes
    72,935       (12,286 )     56,764       25,946  
Cumulative effect of accounting change
            (367 )     367          
 
Net Income
  $ 111,508     $ (43,641 )   $ 100,879     $ 46,063  
 

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Southern Power Company 2004 Annual Report

Revenues

Operating revenues in 2004 were $701.3 million, a $19.5 million (2.9%) increase from 2003. The increase was primarily due to new PPAs with non-affiliates as result of a full year’s operation of Plant Stanton A (placed in service October 2003) and PPAs with affiliates as a result of a full year’s operation of Plant Harris Units 1 and 2 and Plant Franklin 2, each placed in service in June 2003.

     Operating revenues in 2003 were $681.8 million, a $383.0 million (128.2%) increase from 2002. In 2003, operating revenues were positively impacted by new wholesale capacity and energy from the four units placed in service during 2003. Included in this increase was a $9.9 million increase in service and fee revenues from various electric membership cooperative (EMC) contracts.

     Operating revenues in 2002 were $298.8 million, a $269.5 million (919.7%) increase from 2001. In 2002, operating revenues increased due to commercial operation of Plant Wansley Units 6 and 7 and Plant Franklin Unit 1 in June 2002, PPAs with Georgia Power and Savannah Electric, requirements agreements with 11 EMCs in June 2002, and a full year of revenue related to the PPA from Plant Dahlberg which the Company acquired in August 2001.

     Capacity revenues for 2004 were $322.8 million, or 46% of total revenues. Capacity revenues for 2003 were $201.6 million, or 33.4% of total revenues, excluding $80 million related to the Dynegy PPA termination. Capacity revenues for 2002 were $123.9 million, or 41.5% of total revenues. Capacity revenues are an integral component of the PPAs with both affiliate and non-affiliate customers and represent the greatest contribution to net income. Energy revenues under PPAs are generally sold at variable cost and do not have a material impact on net income.

     Revenues from sales to affiliated companies that are not covered by PPAs are made in accordance with the affiliated interchange agreement, as approved by the Federal Energy Regulatory Commission (FERC), and will vary depending on demand and the availability and cost of generating resources at each company that participates in the centralized operation and dispatch of the Southern Company fleet of generating plants (Southern Pool). These transactions do not have a significant impact on earnings since the energy is generally sold at variable cost.

Expenses

The increase in fuel expense in 2004 of $11.8 million or 10.3% is primarily due to increased gas transportation expenses associated with Plant Harris Unit 2 prior to its commitment with Georgia Power. In 2004, although the volume of gas purchased decreased, fuel expense increased as a result of plants placed in service in 2003, where prior to completion, fuel expense was capitalized during unit testing. In addition, the average cost of natural gas per decatherm increased 8.3% from 2003 to 2004. The volumes of gas purchased in 2004 decreased as a result of lower generation requirements generally due to milder weather.

     In 2003, fuel expense increased $17.3 million or 17.7% primarily due to the operation of Plant Wansley Units 6 and 7 and Plant Franklin Unit 1 for a full year, as well as the June 2003 commercial operation of Plant Franklin Unit 2 and Plant Harris Units 1 and 2. Opportunity sales made from Plant Franklin Unit 2 and Plant Harris Unit 2 prior to their commitment under affiliate PPAs also contributed to the increase in fuel expense. In addition, the average cost of natural gas per decatherm increased 24% from 2002 to 2003. The increase in fuel expense in 2002 of $94.2 million was primarily due to the June 2002 commercial operation of Plant Wansley Units 6 and 7 and Plant Franklin Unit 1 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 significant upward trend in the cost of natural gas and volatility in these markets is expected to continue. Higher natural gas prices in the United States are the result of slightly lower gas supplies despite increased drilling activity. Natural gas supply interruptions, such as those caused by the 2004 hurricanes, resulted in an immediate market response; however, the impact of this price volatility may be reduced by imports of natural gas and liquefied natural gas. Fuel expenses incurred under the Company’s PPAs are generally the responsibility of the counterparties, and do not significantly affect net income. Under the PPAs, either the Company incurs the fuel expense and concurrently recovers the cost through energy revenues or the counterparty purchases the fuel directly.

     Purchased power increased $3.2 million in 2004, consisting of a $15.4 million increase for non-affiliates and a $12.2 million decrease for affiliates. Purchased

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Southern Power Company 2004 Annual Report

power from non-affiliates and affiliates increased by $26.7 million and $104.9 million, respectively, in 2003 and by $33.3 million and $15.6 million, respectively, in 2002. All year-over-year variances in total purchased power expenses were to meet the Company’s contractual sales commitments. The allocation of purchased power expenses between affiliate and non-affiliate will vary depending on demand and the availability and cost of generating resources available throughout the Southern Company electric system. 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 2004, non-affiliated purchased power increased and affiliated purchased power decreased as a result of the availability of lower cost energy from contracts with Georgia EMCs and North Carolina municipalities in addition to other market sources. 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.

     Other operations and maintenance, depreciation and amortization expenses and taxes other than income taxes all increased significantly during the period from 2002 through 2004. All of these year-to-year increases are a result of new generating units going into service in 2002 (Plant Wansley Units 6 and 7 and Plant Franklin Unit 1) and in 2003 (Plant Franklin Unit 2, Plant Harris Units 1 and 2, and Plant Stanton A).

     Interest expense increased by $34.4 million in 2004 due to a lower percentage of interest costs being capitalized as projects reached completion. Plant McIntosh Units 10 and 11 were transferred to Georgia Power and Savannah Electric during 2004 and construction was suspended on Plant Franklin Unit 3, effectively ceasing all capitalized interest. For additional information see FUTURE EARNINGS POTENTIAL – “FERC Matters – Plant McIntosh Construction Project” herein and Note 2 to the Financial Statements under “Plant Franklin Unit 3 Construction Project” and “Plant McIntosh Construction Project.” Interest expense in 2003 increased by $22.8 million from the amount recorded in 2002. This increase is primarily attributed to a lower amount of interest costs being capitalized as construction projects reached completion and an increase in the amount of long-term debt outstanding. Interest expense in 2002 increased $8.4 million over 2001 primarily attributed to increased debt associated with the Company’s ongoing construction program.

     Changes in other income, net in 2004, 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 5 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 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, especially regulatory matters, including those related to affiliate contracts, sales, creditworthiness of customers, total generating capacity available in the Southeast and the successful remarketing of capacity as current contracts expire.

     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, Inc. (SCS).

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Southern Power Company 2004 Annual Report

Power Sales Agreements

The Company is working to maintain and expand its share of the wholesale market in the Southeastern power markets. Although there is currently an oversupply situation in the Southeast relative to generating capacity, there are still short term opportunities and requests for proposals in certain areas.

     On August 12, 2004, the Company entered into two PPAs with Florida Power & Light (FP&L). Under the agreements, the Company will provide FP&L with a total of 790 megawatts of capacity annually from Plant Harris Unit 1 and Plant Franklin Unit 1 for the period from June 2010 through December 2015. Additionally, FP&L will make payments for firm gas transportation. The Florida Public Service Commission (PSC) approved these contracts on January 24, 2005; however, they are still contingent upon certain events. A similar agreement with Progress Energy Florida was signed on November 29, 2004 for 350 megawatts from Franklin Unit 1 for the period June 2010 through December 2015. Progress Energy Florida has transmission responsibility. The Progress Energy Florida PPA is contingent upon certain events including approval of the Florida PSC. The final outcome of this matter cannot be determined. These PPAs provide for fixed capacity payments and variable energy payments based on actual energy delivered.

     Also in 2004, the Company executed multiple agreements expanding its relationship with an existing requirements customer. For the years 2005-2009, the Company will sell approximately 130 megawatts of additional wholesale capacity from existing resources to Flint Energies, a cooperative located in Reynolds, Georgia.

     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, sales under PPAs with Georgia Power for the remaining 200 megawatts of uncontracted capacity at Plant Franklin Unit 2 and for Plant Harris Unit 2 began. Sales under PPAs for the other units became effective upon commercial operation. As a result, non-affiliate sales from un-contracted capacity has declined.

     At December 31, 2004, the Company has entered into long-term power sales agreements for a portion of its generating capacity as follows:

                 
    Capacity     Contract  
Project   (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  
 
 
               
Non-Affiliated
               
Stanton A
    396       11/03-11/13  
 
GA. EMC Full Requirements (1)
    62-434       2002-2009  
 
Piedmont Full Req.
    135-181       2006-2010  
 
Franklin Unit 1 (2)
    540       6/10-12/15  
 
Harris Unit 1 (3)
    600       6/10-12/15  
 


(1)   Option in 2009 to convert from full requirements to fixed capacity sale
 
(2)   FP&L and Progress Energy new PPAs
 
(3)   FP&L new PPA

     Although under some of the Company’s PPAs, capacity and energy is sold to the Southern Company’s five retail operating companies, the Company’s generating facilities are not in the retail operating companies’ regulated rate bases, and the Company is not able to seek recovery from their 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 counterparties 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

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Southern Power Company 2004 Annual Report

event that Standard & Poor’s or Moody’s downgrades the credit ratings of such counterparty to below investment grade or 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 costs will be recovered through capacity 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 operation and maintenance costs relating to GE equipment. See Note 6 to the financial statements under “Long-Term Service Agreements” for additional information.

FERC Matters

Market-Based Rate Authority

The Company has authorization from the FERC to sell power to nonaffiliates at market-based prices. Southern Power 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, the retail operating companies, and Southern Power, and found Southern Company and others to be “pivotal suppliers” in their retail service territories 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. In April 2004, the FERC issued an order that abandoned the SMA test and adopted a new interim analysis for measuring generation market power. This new interim approach requires utilities to submit a pivotal supplier screen and a wholesale market share screen. If the applicant does not pass both screens, there will be a rebuttable presumption regarding generation market power. The FERC’s order also sets forth procedures for rebutting these presumptions and addresses mitigation measures for those entities that are found to have market power. In the absence of specific mitigation measures, the order includes several cost-based mitigation measures that would apply by default. The FERC also initiated a new rulemaking proceeding that, among other things, will adopt a final methodology for assessing generation market power.

     In July 2004, the FERC denied Southern Company’s request for rehearing, along with a number of others, and reaffirmed the interim tests that it adopted in April 2004. In August 2004, Southern Company passed the pivotal supplier screen for all markets and the wholesale market share screen for all markets except the Southern Company retail service territory. Southern Company also submitted other analyses to demonstrate that it lacks generation market power. On December 17, 2004, the FERC initiated a proceeding to assess Southern Company’s generation dominance within its retail service territory. The ability to charge market-based rates in other markets is not at issue. As directed by the FERC order, on February 15, 2005 Southern Company submitted additional information related to generation dominance in the Southern Company retail service territory. As a result of the proceeding, any new market-based rate transactions in the Southern Company retail service territory entered into after February 27, 2005 will be subject to refund to the level of the default cost-based rates, pending the outcome of the proceeding. Southern Company, along with other utilities, has also filed an appeal of the FERC’s April 2004 and July 2004 orders with the U.S. Court of Appeals for the District of Columbia Circuit. The FERC has asked the court to dismiss the appeal on the grounds that it is premature.

     In the event that the FERC’s default mitigation measures are ultimately applied, the Company may be required to charge cost-based rates for certain wholesale sales within the Southern Company retail service territory, which may be lower than negotiated market-based rates. The final outcome of this matter will depend on the form in which the final methodology for assessing generation market power and mitigation rules may be ultimately adopted and cannot be determined at this time.

Plant McIntosh Construction Project

In December 2002 after a competitive bidding process, the Georgia PSC certified PPAs between the Company and Georgia Power and Savannah Electric for capacity from Plant McIntosh Units 10 and 11, construction of which is scheduled to be completed in June 2005. In April 2003, Southern Power applied for FERC approval of these PPAs. In July 2003, the FERC accepted the PPAs to become effective June 1, 2005, subject to refund, and ordered that hearings be held. Intervenors opposed the FERC’s acceptance of the PPAs, alleging that they did not meet the applicable standards for market-based rates between affiliates. To ensure the timely completion of the Plant McIntosh construction project and the availability of the units in the summer of 2005 for their retail

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Southern Power Company 2004 Annual Report

customers, in May 2004, Savannah Electric and Georgia Power requested the Georgia PSC to direct them to acquire the Plant McIntosh construction project. The Georgia PSC issued such an order and the transfer occurred on May 24, 2004 at a total cost of approximately $415 million, including $14 million of transmission interconnection facilities. Subsequently, Southern Power filed a request to withdraw the PPAs and to terminate the ongoing FERC proceedings. In August 2004, the FERC issued a notice accepting the request to withdraw the PPAs and permitting such request to become effective by operation of law. However, the FERC made no determination on what additional steps may need to be taken with respect to testimony provided in the proceedings. The ultimate outcome of any additional FERC action cannot now be determined.

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. Because each of the Company’s units are newer gas-fired generating facilities, costs associated with environmental compliance for these facilities have been less significant than for similarly situated coal-fired generating facilities or older gas-fired generating facilities. 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, however, increase the cost of siting and operating any type of future electric generating facility. The impact of such statutes and regulations on the Company as a result of generating facilities that may be acquired or constructed in the future cannot be predicted at this time.

     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, and regulation of other environmental media. Among the various environmental matters being planned or considered for regulation by the federal Environmental Protection Agency and/or relevant state agencies are: additional regulation of areas designated as non-attainment for ozone and particulate matter under applicable federal air quality standards (including areas in Georgia and Alabama where the Company has facilities); the reduction of nitrogen oxide and particulate matter emissions to reduce regional haze and visibility impairment in sensitive areas; reductions in sulfur dioxide and nitrogen oxide emissions to reduce interstate transport of such pollutants; the reduction of so-called “greenhouse gases” (such as carbon dioxide) to address concerns over global climate change; hazardous waste disposal requirements and requirements for cooling water intake structures. The impact of any new standards or requirements will depend on the development and/or implementation of applicable regulations, and cannot be determined 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. Major bills to amend the Clean Air Act to impose more stringent emissions limitations have also been 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 environmental and health concerns could also significantly affect the Company and many areas of its operations. While all of the Company’s PPAs generally contain provisions that permit charging the counterparty 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.

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Southern Power Company 2004 Annual Report

Construction Projects

In October 2004, a partnership between Southern Company and the Orlando Utilities Commission (OUC) was selected by the U.S. Department of Energy (DOE) to build and operate a 285 megawatt coal-gasification facility. The facility will be located at OUC’s Stanton Energy Center near Orlando, Florida, site of the existing gas-fired 630 megawatt Plant Stanton A, which is co-owned by the Company, OUC, and others. The Company will own the Southern Company portion of the project. The project will demonstrate a coal gasification technology that has been under development, in partnership with the DOE, by Southern Company. The project is scheduled to begin commercial operation in 2011, with a projected total cost of $557 million. The DOE is expected to contribute approximately $235 million of the cost.

     In August 2004, the Company completed limited construction activities on Plant Franklin Unit 3 to preserve the long-term viability of the project and suspended further construction. Final completion is not anticipated until the 2008-2011 period. See Note 2 to the financial statements under “Plant Franklin Unit 3 Construction Project” for more information. The final outcome of these matters cannot now be determined.

Other Matters

On October 22, 2004, President Bush signed the American Jobs Creation Act of 2004 (Jobs Act) into law. The Jobs Act includes a provision that allows a generation tax deduction for utilities. The Company is currently assessing the impact of the Jobs Act on its taxable income. However, the Company currently does not expect the Jobs Act to have a material impact on its financial statements.

     From time to time, the Company is involved in various other matters being litigated and regulatory matters that could affect future earnings. See Note 2 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. Southern Company 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” herein and Notes 1 and 5 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:

•   Assessing whether a sales contract meets the definition of a lease

•   Assessing whether a sales contract meets the definition of a derivative

•   Assessing whether a sales contract meets the definition of a capacity contract

•   Assessing the probability at inception and throughout the term of the individual contract that the contract will result in physical delivery

•   Ensuring that the contract quantities do not exceed available generating capacity

•   Identifying the hedging instrument, the hedged transaction, and the nature of the risk being hedged

•   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

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Southern Power Company 2004 Annual Report

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, 2004.

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, 2004, there were no unrealized gains (losses) 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 through net income. Net unrealized gains on such contracts totaled approximately $0.3 million for the year ended December 31, 2004.

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:

•   Future demand for electricity based on projections of economic growth and estimates of available generating capacity

•   Future power and natural gas prices, which have been quite volatile in recent years

•   Future operating costs.

     To date, the Company’s evaluations of its assets have not required any impairment to be recorded. See Note 2 to the financial statements under “Plant Franklin Unit 3 Construction Project” 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.

FINANCIAL CONDITION AND LIQUIDITY

Overview

The major change in the Company’s financial condition during 2004 was the sale of the Plant McIntosh Units 10 and 11 combined cycle construction project to Georgia Power and Savannah Electric at a final book cost of $415 million, including $14 million in transmission interconnection costs. See FUTURE EARNINGS POTENTIAL - “FERC Matters - Plant McIntosh Construction Project” herein for additional information. As a result of the sale, the Company repaid its note payable to Southern Company of $89 million, returned

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Southern Power Company 2004 Annual Report

$225 million to Southern Company ($113 million from capital surplus and $112 million from retained earnings) and repaid $114 million in commercial paper borrowings. In September 2003, the Securities and Exchange Commission (SEC) had approved, under the Public Utility Holding Company Act of 1935, as amended (PUHCA), the Company’s payment of dividends in an amount up to $190 million to Southern Company from capital surplus. The Company also declared and paid $95 million in additional dividends to Southern Company.

Sources of Capital

The Company may use external funds, equity capital from Southern Company or internally generated cash from operations to finance any new projects and ongoing capital requirements. The Company expects to generate external funds from the issuance of unsecured senior debt and commercial paper or utilization of credit arrangements from banks.

     Currently, Southern Company provides limited credit support to the Company. See Note 5 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 PUHCA, most loans between affiliated companies must be approved in advance by the SEC.

     At December 31, 2004, the Company had approximately $25.2 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, 2004, $325 million of unused committed credit arrangements with banks. These credit arrangements are 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, 2004, there was no commercial paper outstanding. See Note 5 to the financial statements under “Commercial Paper” for additional information.

     The issuance of securities by the Company is subject to regulatory approval by the SEC under PUHCA. Additionally, with respect to the public offering of securities, the Company must file registration statements with the SEC under the Securities Act of 1933, as amended. The amounts of securities authorized by the SEC under the PUHCA are continuously monitored and appropriate filings are made to ensure flexibility in the capital markets.

Financing Activities

During 2004, the Company issued no new long-term debt. The Company repurchased $50 million of its 4.875% Senior Notes due July 15, 2015 in December 2004. See the Statements of Cash Flows and Note 5 to the financial statements under “Long-Term Debt” for additional information.

Credit Rating Risk

The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- or Baa3, or below. Generally, collateral may be provided with a Southern Company guaranty, letter of credit or cash. These contracts are primarily for physical electricity purchases and sales. At December 31, 2004, the maximum potential collateral requirements at a BBB- or Baa3 rating were approximately $33 million. The maximum potential collateral requirements at a rating below BBB- or Baa3 were approximately $77 million. The Company is also party to certain derivative agreements that could require collateral and/or accelerated payment in the event of a credit rating change to below investment grade. These agreements are primarily for natural gas price and interest rate risk management activities. At December 31, 2004, the Company had no material exposure related to these agreements.

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

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Power Company 2004 Annual Report

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 counterparties, 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.

     The fair value of changes in derivative energy contracts and year-end valuations were as follows at December 31:

                 
    Changes in Fair  
    Value  
    2004     2003  
    (in thousands)  
Contracts beginning of year
  $ 665     $ 3,864  
Contracts realized or settled
    (469 )     (4,416 )
New contracts at inception
           
Current period changes (a)
    (187 )     1,217  
 
Contracts end of year
  $ 9     $ 665  
 


(a)   Current period changes also include the changes in fair value of new contracts entered into during the period.

     At December 31, 2004, the source of the valuation prices were as follows:

                         
Source of 2004 Year-End Valuation Prices  
    Total     Maturity  
    Fair Value     2005     2006-2007  
            (in thousands)  
 
Actively quoted
  $ 2     $ 2        
External sources
    7       7          
Models and other methods
                 
 
Contracts end of year
  $ 9     $ 9        
 

     Unrealized pre-tax gains and losses on electric contracts used to hedge anticipated sales, 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, 2004, the fair value of all derivative energy contracts was included in income.

     Approximately $0.3 million, $(1.9) million and $(4.9) million of unrealized pre-tax gains (losses) were recognized in income in 2004, 2003, and 2002, 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 Standard & Poor’s and Moody’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 5 to the financial statements under “Financial Instruments.”

     At December 31, 2004, 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 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 5 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 $57.0 million for 2005, $147.2 million for 2006, and $718.2 million for 2007. These amounts include estimates for potential plant acquisitions and/or new construction of $31.2 million for 2005, $108.2 million for 2006, and $683.3 million for 2007. Currently, there are no plants under construction. 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.

     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, 5, and 6 to the financial statements for additional information.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Power Company 2004 Annual Report

                                         
            2006-     2008-     After        
Contractual Obligations   2005     2007     2009     2009     Total  
    (in millions)
Long-term debt(a)
                                       
Principal
  $ 0.2     $ 1.5     $     $ 1,100.0     $ 1,101.7  
Interest
    61.6       123.1       123.1       261.3       569.1  
Operating leases
    0.4       0.8       0.7       9.1       11.0  
Purchase commitments(b)
                                       
Capital(c)
    57.0       865.4                       922.4  
Natural gas(d)
    18.9       38.3       37.2       327.1       421.5  
Long-term service agreements
    23.4       48.9       66.9       618.0       757.2  
 
Total
  $ 161.5     $ 1,078.0     $ 227.9     $ 2,315.5     $ 3,782.9  
 


(a)   All amounts are reflected based on final maturity dates. The Company plans 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 $75.2 million, $62.2 million, and $28.4 million, respectively.
 
(c)   The Company forecasts capital expenditures over a three-year period. Amounts represent current estimates of total expenditures.
 
(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 Exchange future prices at December 31, 2004.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Power Company 2004 Annual Report

Cautionary Statement Regarding Forward-Looking Statements

The Company’s 2004 Annual Report contains forward-looking statements in addition to historical information. Forward-looking information includes, among other things, statements concerning environmental regulations and expenditures and estimated construction and other expenditures. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “projects,” “predicts,” “potential,” or “continue” or the negative of these terms or other comparable terminology. The Company cautions that there are various important factors that could cause actual results to differ materially from those indicated in the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:

•   the impact of recent and future federal and state regulatory change, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry and also changes in environmental, tax and other laws and regulations to which the Company is subject, as well as changes in application of existing laws and regulations;
 
•   current and future litigation, regulatory investigations, proceedings or inquiries;

•   the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates;

•   variations in the demand for electricity, including those related to weather, the general economy and population, and business growth (and declines);

•   available sources and costs of fuels;

•   ability to control costs;

•   advances in technology;

•   state and federal rate regulations;

•   internal restructuring or other restructuring options that may be pursued;

•   potential business strategies, including acquisitions or dispositions of assets, which cannot be assured to be completed or beneficial to the Company;

•   the ability of counterparties of the Company to make payments as and when due;

•   the ability to obtain new short- and long-term contracts with neighboring utilities;

•   the direct or indirect effect on the Company’s business resulting from the terrorist incidents and the threat of terrorist incidents;

•   interest rate fluctuations and financial market conditions and the results of financing efforts, including the Company’s credit ratings;

•   the ability of the Company to obtain additional generating capacity at competitive prices;

•   catastrophic events such as fires, earthquakes, explosions, flood, hurricanes or similar occurrences;

•   the direct or indirect effects on the Company’s business resulting from the August 2003 power outage in the Northeast;

•   the effect of accounting pronouncements issued periodically by standard-setting bodies; and

•   other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed by the Company from time to time with the SEC.

The Company expressly disclaims any obligation to update any forward-looking statements.

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STATEMENTS OF INCOME
For the Years Ended December 31, 2004, 2003, and 2002
Southern Power Company 2004 Annual Report

                         
   
    2004     2003     2002  
    (in thousands)  
Operating Revenues:
                       
Sales for resale —
                       
Non-affiliates
  $ 266,463     $ 278,559     $ 114,919  
Affiliates
    425,065       312,586       183,111  
Contract termination
          80,000        
Other revenues
    9,783       10,635       738  
 
Total operating revenues
    701,311       681,780       298,768  
 
Operating Expenses:
                       
Fuel
    127,103       115,256       97,965  
Purchased power —
                       
Non-affiliates
    76,652       61,234       34,499  
Affiliates
    111,804       124,067       19,164  
Other operations
    58,111       50,852       23,800  
Maintenance
    17,084       11,389       4,551  
Depreciation and amortization
    51,161       39,012       18,319  
Taxes other than income taxes
    11,273       6,665       4,275  
 
Total operating expenses
    453,188       408,475       202,573  
 
Operating Income
    248,123       273,305       96,195  
Other Income and (Expense):
                       
Interest expense, net of amounts capitalized
    (66,088 )     (31,708 )     (8,886 )
Other income (expense), net
    2,408       (1,594 )     (4,582 )
 
Total other income and (expense)
    (63,680 )     (33,302 )     (13,468 )
 
Earnings Before Income Taxes
    184,443       240,003       82,727  
Income taxes
    72,935       85,221       28,457  
 
Earnings Before Cumulative Effect of Accounting Change
    111,508       154,782       54,270  
Cumulative effect of accounting change— less income taxes of $231
          367        
 
Net Income
  $ 111,508     $ 155,149     $ 54,270  
 

The accompanying notes are an integral part of these financial statements.

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STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2004, 2003, and 2002
Southern Power Company 2004 Annual Report

                         
   
    2004     2003     2002  
    (in thousands)  
Operating Activities:
                       
Net income
  $ 111,508     $ 155,149     $ 54,270  
Adjustments to reconcile net income to net cash provided from operating activities —
                       
Depreciation and amortization
    65,838       47,267       18,319  
Deferred income taxes and investment tax credits, net
    23,510       22,521       2,739  
Deferred revenues
    10,064       9,997       13,071  
Tax benefit of stock options
    415       130       499  
Hedge settlements
          (93,298 )     (16,884 )
Other, net
    9,957       (25,787 )     (1,618 )
Changes in certain current assets and liabilities —
                       
Receivables, net
    (14,009 )     (7,008 )     (12,433 )
Fossil fuel stock
    2,894       5,232       (7,606 )
Materials and supplies
    (1,715 )     (1,570 )     (822 )
Other current assets
    4,144       (9,675 )     (3,913 )
Accounts payable
    (13,844 )     32,694       8,628  
Accrued taxes
    32,330       (6,939 )     7,834  
Accrued interest
    (1,386 )     9,299       20,713  
Other current liabilities
    (306 )     236        
 
Net cash provided from operating activities
    229,400       138,248       82,797  
 
Investing Activities:
                       
Gross property additions
    (115,606 )     (344,362 )     (824,687 )
Purchase of property from affiliates
                (389,990 )
Sale of property to affiliates
    414,582              
Change in construction payables, net
    (14,349 )     (16,931 )     3,229  
Other
    (10,043 )           (669 )
 
Net cash provided from (used for) investing activities
    274,584       (361,293 )     (1,212,117 )
 
Financing Activities:
                       
Increase (decrease) in notes payable, net — affiliated
          (20,488 )     209,538  
Increase (decrease) in notes payable, net
    (114,349 )     114,347       1,638  
Proceeds —
                       
Senior notes
          575,000       575,000  
Other long-term debt
                87,873  
Capital contributions from parent company
    2,808       5,952       278,634  
Redemptions —
                       
Senior notes
    (50,000 )            
Other long-term debt
          (379,640 )      
Capital distributions to parent company
    (113,000 )     (77,000 )      
Payment of common stock dividends
    (207,000 )            
Other
          (11,802 )     (7,600 )
 
Net cash provided from (used for) financing activities
    (481,541 )     206,369       1,145,083  
 
Net Change in Cash and Cash Equivalents
    22,443       (16,676 )     15,763  
Cash and Cash Equivalents at Beginning of Period
    2,798       19,474       3,711  
 
Cash and Cash Equivalents at End of Period
  $ 25,241     $ 2,798     $ 19,474  
 
Supplemental Cash Flow Information:
                       
Cash paid during the period for —
                       
Interest (net of $17,368, $36,736 and $35,311 capitalized, respectively)
  $ 52,146     $ 105,765     $ 16,884  
Income taxes (net of refunds)
    13,313       77,993       25,626  
 

The accompanying notes are an integral part of these financial statements.

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BALANCE SHEETS
At December 31, 2004 and 2003
Southern Power Company 2004 Annual Report

                 
   
Assets   2004     2003  
    (in thousands)  
Current Assets:
               
Cash and cash equivalents
  $ 25,241     $ 2,798  
Receivables —
               
Customer accounts receivable
    12,865       10,772  
Other accounts receivable
    893       270  
Accumulated provision for uncollectible accounts
    (350 )     (350 )
Affiliated companies
    25,423       14,130  
Fossil fuel stock, at average cost
    2,904       5,798  
Materials and supplies, at average cost
    9,839       8,123  
Prepaid income taxes
    4,619       11,222  
Prepaid expenses
    8,085       2,528  
Other
    112       1,174  
 
Total current assets
    89,631       56,465  
 
Property, Plant, and Equipment:
               
In service
    1,821,434       1,831,139  
Less accumulated provision for depreciation
    111,200       60,005  
 
 
    1,710,234       1,771,134  
Construction work in progress
    200,903       504,097  
 
Total property, plant, and equipment
    1,911,137       2,275,231  
 
Deferred Charges and Other Assets:
               
Unamortized debt issuance expense
    14,078       18,315  
Accumulated deferred income taxes
          21,911  
Prepaid long-term service agreements
    34,800       21,728  
Other—
               
Affiliated
    6,455       12,790  
Other
    10,912       2,845  
 
Total deferred charges and other assets
    66,245       77,589  
 
Total Assets
  $ 2,067,013     $ 2,409,285  
 

The accompanying notes are an integral part of these financial statements.

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BALANCE SHEETS
At December 31, 2004 and 2003
Southern Power Company 2004 Annual Report

                 
   
Liabilities and Stockholder’s Equity   2004     2003  
   
    (in thousands)  
Current Liabilities:
               
Securities due within one year
  $ 200     $ 200  
Notes payable
          114,347  
Accounts payable —
               
Affiliated
    19,265       51,442  
Other
    11,024       6,591  
Accrued taxes — Other than income
    4,104       1,289  
Accrued interest
    28,626       30,012  
Other
    83       489  
 
Total current liabilities
    63,302       204,370  
 
Long-Term Debt:
               
Senior notes —
               
6.25% due 2012
    575,000       575,000  
4.875% due 2015
    525,000       575,000  
Other long-term debt
    1,485       1,685  
Unamortized debt premium (discount), net
    (2,050 )     (2,573 )
 
Long-term debt
    1,099,435       1,149,112  
 
Deferred Credits and Other Liabilities:
               
Accumulated deferred income taxes
    40,212        
Deferred capacity revenues —
               
Affiliated
    39,118       28,799  
Other
          256  
Other —
               
Affiliated
    13,333       15,061  
Other
    2       211  
 
Total deferred credits and other liabilities
    92,665       44,327  
 
Total Liabilities
    1,255,402       1,397,809  
 
Common Stockholder’s Equity:
               
Common stock, par value $0.01 per share —
           
Authorized - 1,000,000 shares
               
Outstanding - 1,000 shares
               
Paid-in capital
    740,535       850,312  
Retained earnings
    122,134       217,626  
Accumulated other comprehensive income (loss)
    (51,058 )     (56,462 )
 
Total common stockholder’s equity
    811,611       1,011,476  
 
Total Liabilities and Stockholder’s Equity
  $ 2,067,013     $ 2,409,285  
 
Commitments and Contingent Matters (See notes)
               
 

The accompanying notes are an integral part of these financial statements.

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STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
For the Years Ended December 31, 2004, 2003, and 2002
Southern Power Company 2004 Annual Report

                                         
   
                            Other        
    Common     Paid-In     Retained     Comprehensive        
    Stock     Capital     Earnings     Income (loss)     Total  
   
    (in thousands)  
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  
Net income
                111,508             111,508  
Capital distributions to parent company
          (113,000 )                 (113,000 )
Capital contributions from parent company
          3,223                   3,223  
Other comprehensive income (loss)
                      5,404       5,404  
Cash dividends on common stock
                (207,000 )           (207,000 )
 
Balance at December 31, 2004
  $     $ 740,535     $ 122,134     $ (51,058 )   $ 811,611  
 

The accompanying notes are an integral part of these financial statements.

STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2004, 2003, and 2002
Southern Power Company 2004 Annual Report

                         
 
    2004     2003       2002
 
    (in thousands)  
Net income
  $ 111,508     $ 155,149     $ 54,270  
 
Other comprehensive income (loss):
                       
Changes in fair value of qualifying hedges, net of tax of $(520), $(7,872), and $(34,030), respectively
    (920 )     (12,788 )     (54,360 )
Less: Reclassification adjustment for amounts included in net income, net of tax of $3,964, $1,868 and $355, respectively
    6,324       3,429       568  
 
Total other comprehensive income (loss)
    5,404       (9,359 )     (53,792 )
 
Comprehensive Income
  $ 116,912     $ 145,790     $ 478  
 

The accompanying notes are an integral part of these financial statements.

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NOTES TO FINANCIAL STATEMENTS
Southern Power Company 2004 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 Communications Services (SouthernLINC Wireless), 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. SouthernLINC Wireless 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 energy related businesses. 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 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 the Company’s interest in Plant Stanton Unit A. See Note 3 for further information. All intercompany accounts and transactions have been eliminated in consolidation.

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 $46.7 million in 2004, $47.5 million in 2003, and $29.5 million during 2002. Approximately $40.3 million in 2004, $32.8 million in 2003, and $16.2 million in 2002, 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 operations and maintenance expense in the accompanying statements of income. For the periods ended December 31, 2004, 2003, and 2002, these services totaled approximately $6.6 million, $6.3 million, and $5.3 million, respectively.

     Effective June 2004, the Company began billing an additional 200 megawatts capacity for Franklin Unit 2 and an additional 600 megawatts of capacity for Plant Harris

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Unit 2 under existing PPAs with Georgia Power. Total billings for all PPAs in force with affiliates for 2004 totaled $383.0 million, including $10.3 million in affiliated deferred capacity revenues recorded on the balance sheets at December 31, 2004. Billings under these agreements totaled $282.2 million in 2003, including $28.4 million in affiliated deferred capacity recorded on the balance sheets at December 31, 2003. For 2002, comparable billings under these agreements totaled $164 million, including $13 million of affiliated deferred capacity revenues.

     The retail operating companies, the Company, 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 5 for information related to various types of financing support provided by Southern Company.

Revenues

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, 2004, Georgia Power accounted for 40.25% of revenues, with Alabama Power and Savannah Electric accounting for 8.4% and 4.5% of revenues, respectively. 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), with Alabama Power and Savannah Electric accounting for 5.5% and 5.0%, respectively. 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.

Fuel Costs

Fuel costs are expensed as the fuel is consumed.

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. Manufacturer’s tax credits of $11.8 million and $5.8 million were recorded in 2003 and 2002, respectively. There were no credits recorded in 2004.

Depreciation

Depreciation of the original cost of assets is computed under the straight-line method based on the assets’ estimated useful lives determined by the Company. The primary assets in property, plant and equipment are power plants, all of which have an estimated useful life of 35 years, except Plant Dahlberg which has an estimated useful life of 40 years. These lives reflect a composite of the significant components (called retirement units) that make up the plants. When property subject to composite depreciation is retired or otherwise disposed of in the normal course of business, its cost is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation is removed from the accounts and a gain or loss is recognized.

Asset Retirement Obligations and Other Costs of Removal

Effective January 1, 2003, the Company adopted Financial Accounting Standards Board (FASB) Statement No. 143, Accounting for Asset Retirement

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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 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, 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.

     As of December 31, 2004, 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 $17.4 million in 2004, $36.7 million in 2003, and $35.3 million in 2002 was capitalized in connection with the development and construction of power plants. The cost to replace significant items of property defined as retirement units is capitalized. The cost of maintenance, repairs and replacement of minor items of property is charged to maintenance expense as incurred.

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 $ 3.2 million at December 31, 2004 and $2.2 million at December 31, 2003.

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 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 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

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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, 2004 were as follows:

                 
    Carrying     Fair  
    Amount     Value  
    (in millions)  
Long-term debt:
               
At December 31, 2004
  $ 1,099     $ 1,114  
At December 31, 2003
  $ 1,149     $ 1,172  
 

     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. CONTINGENCIES AND REGULATORY MATTERS

General Litigation Matters

From time to time, 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.

FERC Matters

Market-Based Rate Authority

The Company has authorization from the Federal Energy Regulatory Commission (FERC) to sell power to nonaffiliates at market-based prices. 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, the retail operating companies, and Southern Power, and found Southern Company and others to be “pivotal suppliers” in their retail service territories 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. In April 2004, the FERC issued an order that abandoned the SMA test and adopted a new interim analysis for measuring generation market power. This new interim approach requires utilities to submit a pivotal supplier screen and a wholesale market share screen. If the applicant does not pass both screens, there will be a rebuttable presumption regarding generation market power. The FERC’s order also sets forth procedures for rebutting these presumptions and addresses mitigation measures for those entities that are found to have market power. In the absence of specific mitigation measures, the order includes several cost-based mitigation measures that would apply by default. The FERC also initiated a new rulemaking proceeding that, among other things, will adopt a final methodology for assessing generation market power.

     In July 2004, the FERC denied Southern Company’s request for rehearing, along with a number of others, and reaffirmed the interim tests that it adopted in April 2004. In August 2004, Southern Company submitted a filing to the FERC that included results showing that Southern Company passed the pivotal supplier screen for all markets and the wholesale market share screen for all markets except the Southern Company retail service territory. Southern Company also submitted other analyses to demonstrate that it lacks generation market power. On December 17, 2004, the FERC initiated a proceeding to assess Southern Company’s generation dominance within its retail service territory. The ability to

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charge market-based rates in other markets is not at issue. As directed by the FERC order, on February 15, 2005 Southern Company submitted additional information related to generation dominance in the Southern Company retail service territory. Any new market-based rate transactions in the Southern Company retail service territory entered into after February 27, 2005 will be subject to refund to the level of the default cost-based rates, pending the outcome of the proceeding. Southern Company, along with other utilities, has also filed an appeal of the FERC’s April and July 2004 orders with the U.S. Court of Appeals for the District of Columbia Circuit. The FERC has asked the court to dismiss the appeal on the grounds that it is premature.

     In the event that the FERC’s default mitigation measures are ultimately applied, the Company may be required to charge cost-based rates for certain wholesale sales within the Southern Company retail service territory, which may be lower than negotiated market-based rates. The final outcome of this matter will depend on the form in which the final methodology for assessing generation market power and mitigation rules may be ultimately adopted and cannot be determined at this time.

Plant Franklin Unit 3 Construction Project

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 has completed 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, 2004, the Company’s investment in Unit 3 of Plant Franklin was $171.6 million. The final outcome of this matter cannot now be determined.

Plant McIntosh Construction Project

In December 2002 after a competitive bidding process, the Georgia Public Service Commission (PSC) certified power purchase agreements (PPAs) between the Company and Georgia Power and Savannah Electric for capacity from Plant McIntosh Units 10 and 11, construction of which is scheduled to be completed in June 2005. In April 2003, the Company applied for FERC approval of these PPAs. In July 2003, the FERC accepted the PPAs to become effective June 1, 2005, subject to refund, and ordered that hearings be held. Intervenors opposed the FERC’s acceptance of the PPAs, alleging that they did not meet the applicable standards for market-based rates between affiliates. To ensure the timely completion of the Plant McIntosh construction project and the availability of the units in the summer of 2005 for their retail customers, in May 2004, Savannah Electric and Georgia Power requested the Georgia PSC to direct them to acquire the Plant McIntosh construction project. The Georgia PSC issued such an order and the transfer occurred on May 24, 2004 at a total cost of approximately $415 million, including $14 million in transmission interconnection facilities. Subsequently, the Company filed a request to withdraw the PPAs and to terminate the ongoing FERC proceedings. In August 2004, the FERC issued a notice accepting the request to withdraw the PPAs and permitting such request to become effective by operation of law. However, the FERC made no determination on what additional steps may need to be taken with respect to testimony provided in the proceedings. The ultimate outcome of any additional FERC action cannot now be determined.

3. JOINT OWNERSHIP AGREEMENTS

The Company, through its wholly owned subsidiary SCF, is a 65% owner of Plant Stanton A, a combined-cycle project with 630 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 whereby SCS is responsible for the operation and maintenance of Plant Stanton A. As of December 31, 2004, $155.7 million was recorded in plant in service with associated accumulated depreciation of $5.5 million. The Company’s proportionate share of Plant Stanton A’s operating expense is included in the corresponding operating expenses in the Statements of Income.

     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 Plant Stanton A. As of December 31, 2004, the Company’s current exposure under these guarantees is $32.5 million under the PPAs and the ownership agreement and $9.4 million under alternative power supply agreements.

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4. INCOME TAXES

Southern Company and its subsidiaries file a consolidated federal income tax return and a combined State of Georgia income tax return. Under a joint consolidated income tax allocation agreement, as required by the PUHCA, each subsidiary’s current and deferred tax expense is computed on a stand-alone basis, and no subsidiary is allocated more expense than would be paid if they filed a separate income tax return. 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:

                         
    2004     2003     2002  
   
    (in thousands)  
Total provision for income taxes:
                       
Federal:
                       
Current
  $ 40,492     $ 64,090     $ 26,900  
Deferred
    19,939       19,354       2,338  
 
 
    60,431       83,444       29,238  
 
State:
                       
Current
    8,934       10,459       4,622  
Deferred
    3,570       3,318       401  
State manufacturer’s Tax credits
          (11,769 )     (5,804 )
 
 
    12,504       2,008       (781 )
 
Total
  $ 72,935     $ 85,452     $ 28,457  
 

     The Company recorded a reduction in 2003 and 2002 tax expense of approximately $11.8 million and $5.8 million, respectively, under the flow-through method of accounting for the State of Georgia manufacturer’s tax credits. There were no credits recorded in 2004.

     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:

                 
    2004     2003  
   
    (in thousands)  
Deferred tax liabilities:
               
Accelerated depreciation
  $ (101,840 )   $ (44,602 )
Book/tax basis difference on asset transfer
    (6,455 )      
 
Total
    (108,295 )     (44,602 )
 
Deferred tax assets:
               
Book/tax basis differences on asset transfers
    13,333       15,061  
Levelized capacity revenues
    16,218       11,052  
Other comprehensive loss on interest rate swaps
    35,988       40,003  
Other
    2,544       397  
 
Total
    68,083       66,513  
 
Accumulated deferred income taxes in the balance sheets
  $ (40,212 )   $ 21,911  
 

     Deferred tax liabilities were primarily the result of property related timing differences and derivative hedging instruments. The transfer of the Plant McIntosh construction project to Georgia Power and Savannah Electric resulted in a deferred gain for federal income tax purposes. Georgia Power and Savannah Electric will reimburse the Company for the related $6.4 million deferred tax liability as it is reflected in the Company’s future taxable income. These receivables from Georgia Power and Savannah Electric are included in Other Affiliated Deferred Debits on the balance sheet at December 31, 2004. See Note 2 under “FERC Matters - Plant McIntosh Construction Project” for further information.

     Deferred tax assets consist primarily of timing differences related to the recognition of capacity revenues, and the tax impact related to the deferred loss on interest rate swaps reflected in Other Comprehensive Income. The transfer of Plants Dahlberg, Wansley, and Franklin to the Company from Georgia Power in 2001 also resulted in a deferred gain for federal income tax purposes. The Company will reimburse Georgia Power for the remaining balance of the related deferred tax asset of $13.3 million as it is reflected in Georgia Power’s future taxable income. This payable to Georgia Power is included in Other Affiliated Deferred Credits on the balance sheet at December 31, 2004.

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     A reconciliation of the federal statutory tax rate to the effective income tax rate is as follows:

                         
    2004     2003     2002  
 
Federal statutory rate
    35.0 %     35.0 %     35.0 %
State income tax, net of federal deduction
    4.4       3.7       3.9  
Other Permanent Differences
    0.1                  
State manufacturer’s tax credits, net of federal effect
          (3.2 )     (4.5 )
 
Effective income tax rate
    39.5 %     35.5 %     34.4 %
 
                       
 

5. FINANCING

Parent Company Transactions

Southern Company is currently authorized by the SEC under the PUHCA to fund the development of the Company 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, 2004, equity contributions from Southern Company to the Company totaled $741 million.

     Southern Company has committed to fund at least 35 percent 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.

Bank Credit Arrangements

The Company has a $325 million unsecured syndicated revolving credit facility (Facility) expiring in April 2006. 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, 2004, the Company had no outstanding borrowings under the Facility. Borrowings under the Facility would bear interest at the Company’s option at a rate 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 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, 2004, 2003, and 2002, the Company paid approximately $2.1 million, $2.0 million, and $1.1 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, 2004. 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 and in December 2004, the Company repurchased $50 million of these notes. In June 2002, the Company issued $575 million of 6.25% senior notes, due July 15, 2012.

Commercial Paper

The Company has the ability to borrow under a commercial paper program. During 2004, the peak amount outstanding for commercial paper was $114.5 million and the average amount outstanding was $49.6 million. The average annual interest rate on commercial paper was 1.14% in 2004. There was no commercial paper outstanding as of December 31, 2004.

     The Company’s commercial paper program is supported by the Facility. The Facility was structured to accommodate commercial paper, and the conditions that the Company must meet to reserve against the Facility for

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a project-specific commercial paper issue are the same as those for a regular draw on the Facility. These conditions 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, 2004, 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 associated with senior notes for losses of $16.9 million. These losses have been deferred in other comprehensive income and will be amortized to interest expense over the life of the senior notes.

     For the years 2004, 2003, and 2002, approximately $10.4 million, $5.5 million, and $0.7 million, respectively, of pre-tax losses were reclassified from other comprehensive income to interest expense. During 2005, approximately $11.2 million of pre-tax losses are expected to be reclassified from other comprehensive income to interest expense. The Company has interest-related hedges in place up to and including 2013.

     For the years 2004, 2003 and 2002, approximately $0.3 million, $0.2 million and $(0.2) million, respectively, of pre-tax gains (losses) were reclassified from other comprehensive income to depreciation and amortization. Additionally for the year 2004, approximately $0.2 million of pre-tax losses were reclassified to fuel expense. For 2005, approximately $0.3 million of pre-tax gains are expected to be reclassified from other comprehensive income to earnings. The Company has energy-related hedges in place through 2005. Additionally, there are deferred realized net hedging gains relating to capitalized costs and revenues during the construction of specific plants that will be reclassified from other comprehensive income to depreciation and amortization over the remaining life of the respective plants, which is approximately 33 years.

6. COMMITMENTS

Construction Program

The Company currently estimates property additions to be $57.0 million, $147.2 million and $718.2 million in 2005, 2006, and 2007, respectively. There are currently no plants actively under construction. See Note 2 under “Plant Franklin Unit 3 Construction Project” for additional information.

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 $757.2 million over the remaining term of the agreements, which may range up to 30 years per unit. However, the LTSAs contain various cancellation provisions at the Company’s option.

     Payments made to GE prior to the performance of any planned inspections are recorded as a long term prepayment in Deferred Charges and Other Assets on the balance sheets. Inspection costs are capitalized or charged to expense based on the nature of the work performed.

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Fuel Commitments

SCS, as agent for the retail operating companies and the Company, 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 Exchange future prices at December 31, 2004.

         
    Fuel  
    Purchases  
Year   (in thousands)  
2005
  $ 18,875  
2006
    19,257  
2007
    18,999  
2008
    18,589  
2009
    18,589  
2010 and beyond
    327,167  
 
Total
  $ 421,476  
 

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, the Company 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, the Company and Southern Company GAS may be jointly and severally liable. The creditworthiness of the Company 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 the Company and Southern Company GAS as a contracting party under these agreements.

7. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

Summarized quarterly financial information for 2004 and 2003 is as follows:

                         
   
    Operating     Operating        
Quarter Ended   Revenues     Income     Net Income  
   
    (in millions)  
March 2004
  $ 175,605     $ 56,415     $ 27,185  
June 2004
    182,749       50,562       22,417  
September 2004
    188,941       79,260       37,322  
December 2004
    154,016       61,886       24,584  
 
                       
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  

     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 2004. 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.

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SELECTED FINANCIAL AND OPERATING DATA 2001-2004
Southern Power Company 2004 Annual Report

                                 
 
    2004     2003     2002     2001  
 
Operating Revenues (in thousands) :
                               
Sales for resale — non-affiliates
  $ 266,463     $ 278,559     $ 114,919     $ 26,390  
Sales for resale — affiliates
    425,065       312,586       183,111       2,906  
 
Total revenues from sales of electricity
    691,528       591,145       298,030       29,296  
Other revenues
    9,783       90,635       738       5  
 
Total
  $ 701,311     $ 681,780     $ 298,768     $ 29,301  
 
Net Income (in thousands)
  $ 111,508     $ 155,149     $ 54,270     $ 8,207  
Cash Dividends on Common Stock (in thousands)
  $ 207,000     $     $     $  
Return on Average Common Equity (percent)
    12.23       17.65       8.94       3.51  
Total Assets (in thousands)
  $ 2,067,013     $ 2,409,285     $ 2,085,976     $ 822,857  
Gross Property Additions (in thousands)
  $ 115,606     $ 344,362     $ 1,214,677     $ 765,511  
 
Capitalization (in thousands) :
                               
Common stock equity
  $ 811,611     $ 1,011,476     $ 746,604     $ 466,993  
Long-term debt
    1,099,435       1,149,112       955,879       293,205  
 
Total (excluding amounts due within one year)
  $ 1,911,046     $ 2,160,588     $ 1,702,483     $ 760,198  
 
Capitalization Ratios (percent) :
                               
Common stock equity
    42.5       46.8       43.9       61.4  
Long-term debt
    57.5       53.2       56.1       38.6  
 
Total (excluding amounts due within one year)
    100.0       100.0       100.0       100.0  
 
Security Ratings:
                               
Unsecured Long-Term Debt -
                       
Moody’s
  Baa1     Baa1     Baa1        
Standard and Poor’s
  BBB+     BBB+     BBB+        
Fitch
  BBB+     BBB+     BBB+        
 
Kilowatt-Hour Sales (in thousands) :
                               
Sales for resale — non-affiliates
    5,369,261       6,057,053       1,240,290       164,926  
Sales for resale — affiliates
    6,583,017       5,430,973       3,607,107       69,307  
 
Total
    11,952,278       11,488,026       4,847,397       234,233  
 
Average Revenue Per Kilowatt-Hour (cents) :
    5.79       5.15       6.15       12.51  
Plant Nameplate Capacity Ratings (year-end) (megawatts)
    4,775       4,775       2,408       800  
Maximum Peak-Hour Demand (megawatts):
                               
Winter
    2,098       2,077       949        
Summer
    2,740       2,439       1,426        
Annual Load Factor (percent)
    54.4       54.9       51.1        
Plant Availability (percent) :
    97.9       96.8       95.1       83.7  
Source of Energy Supply (percent) :
                               
Gas
    61.9       53.4       77.4       100.0  
Purchased power -
                               
From non-affiliates
    24.7       30.5       5.9        
From affiliates
    13.4       16.1       16.7        
 
Total
    100.0       100.0       100.0       100.0  
 

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PART III

Items 10, 11, 12 (except for “Equity Compensation Plan Information” which is included herein), 13 and 14 for Southern Company are incorporated by reference in Southern Company’s definitive Proxy Statement relating to the 2005 Annual Meeting of Stockholders. Specifically, reference is made to “Nominees for Election as Directors” and “Section 16(a) Beneficial Ownership Reporting Compliance” 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 2005 Annual Meetings of Shareholders. Specifically, reference is made to “Nominees for Election as Directors” and “Section 16(a) Beneficial Ownership Reporting Compliance” 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.

     Items 10, 11, 12 and 13 for Southern Power are omitted pursuant to General Instruction I(2)(c) of Form 10-K.

Item 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The ages of directors and executive officers set forth below are as of December 31, 2004.

SAVANNAH ELECTRIC

Identification of directors of Savannah Electric.

Anthony R. James
President and Chief Executive Officer
Age 54
Served as Director since 5-3-01

Gus H. Bell, III (1)
Age 67
Served as Director since 7-20-99

Archie H. Davis (1)
Age 63
Served as Director since 2-18-97

Walter D. Gnann (1)
Age 69
Served as Director since 5-17-83

Robert B. Miller, III (1)
Age 59
Served as Director since 5-17-83

Arnold M. Tenenbaum (1)
Age 68
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 5, 2004) 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 54
Served as Executive Officer since 7-27-00

W. Miles Greer
Vice President
Age 61
Served as Executive Officer since 11-20-85

Kirby R. Willis
Vice President, Treasurer, Chief Financial Officer
and Assistant Corporate Secretary
Age 53
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 August 5, 2004 for the ensuing year.

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     There are no arrangements or understandings between any of the individuals listed above and any other person pursuant to which he was or is to be selected as an officer, other than any arrangements or understandings with officers of Savannah 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. Advisory Director of SunTrust Bank of Savannah.

Gus H. Bell, III - President and Chief Executive Officer of Hussey, Gay, Bell and DeYoung, A Bell Company (specializing in environmental, transportation, industrial, structural, architectural and civil engineering), Savannah, Georgia since 1966. Advisory Director of SunTrust Bank of Savannah.

Archie H. Davis - President Emeritus of the Savannah Bancorp, Inc. since April 2003; Director of Savannah Bancorp, Inc., Savannah, Georgia since 1990; and Director of The Savannah Bank N.A. since 1990. Previously served as President and Chief Executive Officer and Director of Savannah Bancorp, Inc., Savannah, Georgia from 1990 to 2003; Chief Executive Officer of The Savannah Bank, N.A. from 2002 to 2003; and President and Chief Executive Officer of The Savannah Bank, N.A. from 1990 to 2002.

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 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.

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.

All of Savannah Electric’s directors, named executive officers and comptroller and corporate secretary, Nancy Frankenhauser, failed to file on a timely basis a Form 3 as required by Section 16(a) of the Securities Act of 1934, as amended.

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 free of charge 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 and Committee Charters

Southern Company has adopted corporate governance guidelines and committee charters. The corporate governance guidelines and the charters of Southern Company’s Audit Committee, Governance Committee and Compensation and Management Succession Committee can be found on Southern Company’s website located at http://www.southerncompany.com. The corporate governance guidelines and charters are also available free of charge in print to any shareholder upon request.

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Item 11. EXECUTIVE COMPENSATION

Savannah Electric Summary Compensation Table. The following table sets forth information concerning any Chief Executive Officer and the three most highly compensated executive officers serving during 2004.

                                                                 
            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
                                                               
President, Chief
    2004       260,755       214,741       3,403             31,435       158,804       13,881  
Executive Officer,
    2003       248,342       183,462       3,168             32,015       164,732       11,956  
Director
    2002       235,748       189,044       13,109             35,354       136,462       12,235  
 
                                                               
W. Miles Greer
    2004       203,900       111,487       57             12,240       87,556       23,507  
Vice President
    2003       198,238       97,376       1,716             12,744       111,890       24,702  
 
    2002       191,400       101,796       107             14,278       115,884       20,261  
 
                                                               
Kirby R. Willis
                                                               
Vice President, Chief Financial
    2004       187,827       82,202       748             11,281       61,834       15,602  
Officer, Treasurer,
    2003       182,109       89,491       2,207             11,712       68,470       14,634  
Assistant Corporate Secretary
    2002       175,476       93,329       891             13,090       61,913       13,283  
 
                                                               
Sandra R. Miller4
    2004       155,804       118,936       893             9,349       37,813       8,049  
Vice President
    2003       146,072       108,696       5,135             9,432       32,304       12,424  
 
    2002       138,074       104,769       1,720             10,317       18,824       7,016  


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 Southern Company’s Omnibus Incentive Compensation Plan (“Omnibus Incentive Compensation Plan”) for the four-year performance periods ended December 31, 2002, 2003 and 2004, 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, 2002, 2003 and 2004, all named executives earned a payout of $1.355, $1.385 and $1.22 per option, respectively.

3 Contributions in 2004 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
  $ 9,099     $ 740     $ 4,042  
W. Miles Greer
    8,258       740       14,509  
Kirby R. Willis
    7,184       651       7,767  
Sandra R. Miller
    4,907       740       2,402  

In 2003, these amounts included additional incentive compensation of $3,000 and $5,000 for Mr. Greer and Ms. Miller, respectively.

4 In October 2004, Ms. Miller became an officer of Southern Company GAS and resigned as an officer of Savannah Electric.

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STOCK OPTION GRANTS IN 2004

Savannah Electric Stock Option Grants Table. The following table sets forth all stock option grants to the named executive officers during the year ending December 31, 2004.

                                         
    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 5     Fiscal Year 6     ($/Sh)5     Date 5     Present Value7  
Anthony R. James
  31,435     26.6     29.50     2/13/2014     $103,421  
W. Miles Greer
  12,240     10.4     29.50     9/1/2013       40,270  
Kirby R. Willis
  11,281       9.5     29.50     2/13/2014       37,114  
Sandra R. Miller
    9,349       7.9     29.50     2/13/2014        30,758  


5 Under the terms of the Omnibus Incentive Compensation Plan, stock option grants were made on February 13, 2004 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.

6 A total of 118,209 stock options were granted in 2004 to Savannah Electric’s employees.

7 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
 
19.65%
    3.08 %     4.75 %   5 years
 

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AGGREGATED STOCK OPTION EXERCISES IN 2004 AND YEAR-END OPTION VALUES

Savannah Electric Aggregated Stock Option Exercises Table. The following table sets forth information concerning options exercised during the year ending December 31, 2004 by the named executive officers and the value of unexercised options held by them as of December 31, 2004.

                                                 
                    Number of Securities Underlying     Value of Unexercised  
                    Unexercised Options at Fiscal     In-the-Money Options  
                    Year-End (#)     At Year-End ($)8  
    Shares                                
    Acquired     Value                          
Name   on Exercise (#)     Realized ($)9     Exercisable     Unexercisable     Exercisable     Unexercisable  
 
Anthony R. James
    20,208       320,841       65,604       64,563       661,417       342,060  
W. Miles Greer
    21,260       332,714       46,272       25,495       519,778       135,624  
Kirby R. Willis
    10,034       124,796       27,232       23,452       272,475       124,683  
Sandra R. Miller
      1,679         25,737       11,918       19,076       99,759       100,856  


8 This column represents the excess of the fair market value of Southern Company’s common stock of $33.52 per share, as of December 31, 2004, 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, 2004.

9 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.

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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 Company’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 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 Table on page III-3.

                                                 
    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, 2004, the applicable compensation levels and years of accredited service for Savannah Electric’s executive officers are presented in the following tables:

Savannah Electric

                 
    Compensation     Accredited  
Name   Level     Years of Service  
Anthony R. James
  $408,954     25  
W. Miles Greer 10
     272,781     28  
Kirby R. Willis 11
     243,898     30  
Sandra R. Miller
     238,247     24  

     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).


10   The number of accredited years of service includes seven years and six months and eight years credited to Mr. Greer under the Southern Company Pension Plan and the Supplemental Executive Retirement Plan, respectively.
 
11   The number of accredited years of service includes five years and five months granted to Mr. Willis for time served at a non-affiliated electric utility.

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     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 2004 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 of Savannah Electric.

Standard Arrangements. The following table presents compensation to be paid to Savannah Electric’s directors 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
  $12,000
Stock Retainer Fee
  85 shares per quarter
Meeting Fee
  $1,200 for each Board meeting attended and
  $1,000 for each Committee meeting attended

     Other Arrangements. No director received other compensation for services as a director during the year ending December 31, 2004 in addition to or in lieu of that specified by the standard arrangements specified above.

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Employment Contracts and Termination of Employment and Change in Control Arrangements.

Savannah Electric has adopted Southern Company’s Change in Control Program, which is applicable to certain of its officers, and has entered into an individual change in control agreement with its president and chief executive officer. If an executive is involuntarily terminated, other than for cause, within two years following a change in control of Savannah Electric or Southern Company, the program provides for:

•   lump sum payment of two or three times annual compensation,
 
•   up to five years’ coverage under group health and life insurance plans,
 
•   immediate vesting of all stock options, stock appreciation rights and restricted stock previously granted,
 
•   payment of any accrued long-term and short-term bonuses and dividend equivalents and
 
•   payment of any excise tax liability incurred as a result of payments made under any individual agreements.

A change in control of Southern Company is defined under the agreements as:

•   acquisition of at least 20 percent of the Southern Company’s stock,
 
•   a change in the majority of the members of the Southern Company’s board of directors,
 
•   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
 
•   a sale of substantially all the assets of Southern Company.

A change in control of Savannah Electric is defined under the agreements as:

•   acquisition of at least 50 percent of Savannah Electric’s stock,
 
•   a merger or other business combination unless Southern Company controls the surviving entity or
 
•   a sale of substantially all the assets of Savannah Electric.

Southern Company also has amended its short- and long-term incentive plan to provide for pro-rata payments at not less than target-level performance if a change in control occurs and the plan is not continued or replaced with comparable plans.

Mr. W. Miles Greer and Savannah Electric entered into agreements that will 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.

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Item 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Savannah Electric

Security Ownership of Certain Beneficial Owners. Southern Company is the beneficial owner of 100% of the outstanding common stock of Savannah Electric.

                 
 
        Amount and    
    Name and Address   Nature of   Percent
    of Beneficial   Beneficial   of
Title of Class   Owner   Ownership   Class
 
Common Stock
  The Southern Company   10,844,635       100%
  270 Peachtree Street, N.W.            
  Atlanta, Georgia 30303            

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, 2004. 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, 2004.

                     
                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)
Gus H. Bell, III
  Southern Company Common     649        
Archie H. Davis
  Southern Company Common     1,065        
Walter D. Gnann
  Southern Company Common     3,312        
Robert B. Miller, III
  Southern Company Common     1,318        
Arnold M. Tenenbaum
  Southern Company Common     1,641        
W. Miles Greer
  Southern Company Common     65,518       59,359  
Anthony R. James
  Southern Company Common     111,388       98,539  
Sandra R. Miller
  Southern Company Common     23,231       21,618  
Kirby R. Willis
  Southern Company Common     44,634       39,260  
 
                   
The directors, nominees and
executive officers as a group
  Southern Company Common     252,756       218,776  


(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 and Savannah Electric know of no arrangements which may at a subsequent date result in any change in control.

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Equity Compensation Plan Information

The following table provides information as of December 31, 2004 concerning shares of Southern Company common stock authorized for issuance under Southern Company’s existing non-qualified equity compensation plans.

                         
    Number of securities     Weighted-average     Number of securities remaining  
    to be issued upon     exercise price of     available for future issuance  
    exercise of     outstanding     under equity compensation  
    outstanding options,     options, warrants     plans (excluding securities  
    warrants and rights     and rights     reflected in column (a))  
Plan category   (a)     (b)     (c)  
 
Equity compensation plans approved by security holders
    34,535,283       $24.27       34,528,148(1)  
 
 
                       
Equity compensation plans not approved by security holders
    N/A       N/A       N/A  
 

(1)   Includes securities available for future issuance under the Omnibus Incentive Compensation Plan (32,583,523) and the Outside Directors Stock Plan (1,944,625).

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

SAVANNAH ELECTRIC

Transactions with management and others.

Mr. Archie Davis is currently President Emeritus and a Director of Savannah Bancorp, Inc. and a Director of The Savannah Bank, N.A., Savannah, Georgia. Mr. Tenenbaum is Chairman of the Board of Directors for the holding company of First Chatham Bank. During 2004, 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.

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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 2004 and 2003:

                 
    2004     2003  
    (in thousands)  
Savannah Electric
               
Audit Fees (1)
  $ 774     $ 250  
Audit-Related Fees (2)
          101  
Tax Fees
           
All Other Fees
           
 
           
 
  $ 774     $ 351  
 
           
Southern Power
               
Audit Fees (3)
  $ 648     $ 535  
Audit-Related Fees (2)
          290  
Tax Fees
           
All Other Fees
           
 
           
 
  $ 648     $ 825  
 
           

(1)   Includes services performed in connection with financing transactions.
 
(2)   Includes internal control review services and accounting consultations.
 
(3)   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 fiscal years 2004 and 2003 (described in the footnotes to the table above) and related fees were approved in advance by the Southern Company Audit Committee.

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PART IV

Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

Item 15.  EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)   The following documents are filed as a part of this report on this Form 10-K:

  (1)   Financial Statements:
 
      Report of Independent Registered Public Accounting Firm on Internal Control over Financial Statements for Southern Company and Subsidiary Companies is listed under Item 8 herein.
 
      Reports of Independent Registered Public Accounting Firm 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.
 
  (2)   Financial Statement Schedules:
 
      Reports of Independent Registered Public Accounting Firm 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-10, IV-11, IV-12, IV-13, IV-14 and IV-15.
 
      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.
 
  (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.

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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:   David M. Ratcliffe
Chairman, President and Chief Executive Officer
 
       
  By:   /s/  Wayne Boston
(Wayne Boston, Attorney-in-fact)
 
       
  Date:   February 28, 2005

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
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:
   
  Dorrit J. Bern   Donald M. James    
  Francis S. Blake   Zack T. Pate    
  Thomas F. Chapman   J. Neal Purcell    
  Bruce S. Gordon   Gerald J. St. Pe’    
         
  By:   /s/  Wayne Boston
(Wayne Boston, Attorney-in-fact)
 
       
  Date:   February 28, 2005

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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:   /s/  Wayne Boston
(Wayne Boston, Attorney-in-fact)
 
       
  Date:   February 28, 2005

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)
 
   
  Art P. Beattie
Executive Vice President, Chief Financial Officer and Treasurer
(Principal Financial and Accounting Officer)
             
    Directors:
   
  Whit Armstrong   Malcolm Portera    
  David J. Cooper, Sr.   Robert D. Powers    
  R. Kent Henslee   David M. Ratcliffe    
  John D. Johns   C. Dowd Ritter    
  Carl E. Jones, Jr.   James H. Sanford    
  Patricia M. King   John Cox Webb, IV    
  James K. Lowder   James W. Wright    
  Wallace D. Malone, Jr.        
         
  By:   /s/  Wayne Boston
(Wayne Boston, Attorney-in-fact)
 
       
  Date:   February 28, 2005

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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:   Michael D. Garrett
President and Chief Executive Officer
 
       
  By:   /s/  Wayne Boston
(Wayne Boston, Attorney-in-fact)
 
       
  Date:   February 28, 2005

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

     
  Michael D. Garrett
President, Chief Executive Officer and Director
(Principal Executive Officer)
 
   
  C. B. Harreld
Executive Vice President, Chief Financial Officer,
Treasurer and Assistant Secretary
(Principal Financial Officer)
 
   
  W. Ron Hinson
Vice President, Comptroller and Chief Accounting Officer
(Principal Accounting Officer)
             
    Directors:
   
  Juanita Powell Baranco   D. Gary Thompson    
  Robert L. Brown, Jr.   Richard W. Ussery    
  Ronald D. Brown   William Jerry Vereen    
  Anna R. Cablik   E. Jenner Wood, III    
  David M. Ratcliffe        
         
  By:   /s/  Wayne Boston
(Wayne Boston, Attorney-in-fact)
 
       
  Date:   February 28, 2005

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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:   /s/ Wayne Boston
(Wayne Boston, Attorney-in-fact)
 
       
  Date:   February 28, 2005

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:   /s/ Wayne Boston
(Wayne Boston, Attorney-in-fact)
 
       
  Date:   February 28, 2005

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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:   /s/ Wayne Boston
(Wayne Boston, Attorney-in-fact)
 
       
  Date:   February 28, 2005

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   Philip J. Terrell    
  Warren A. Hood, Jr.   Gene Warr    
  George A. Schloegel        
         
  By:   /s/ Wayne Boston
(Wayne Boston, Attorney-in-fact)
 
       
  Date:   February 28, 2005

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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:   /s/ Wayne Boston
(Wayne Boston, Attorney-in-fact)
 
       
  Date:   February 28, 2005

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, Chief Financial
Officer and Assistant Corporate Secretary
(Principal Financial and Accounting Officer)
             
    Directors:
   
  Gus H. Bell, III   Robert B. Miller, III    
  Archie H. Davis   Arnold M. Tenenbaum    
  Walter D. Gnann        
         
  By:   /s/ Wayne Boston
(Wayne Boston, Attorney-in-fact)
 
       
  Date:   February 28, 2005

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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:   /s/ Wayne Boston
(Wayne Boston, Attorney-in-fact)
 
       
  Date:   February 28, 2005

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   David M. Ratcliffe    
  W. Dean Hudson        
         
  By:   /s/ Wayne Boston
(Wayne Boston, Attorney-in-fact)
 
       
  Date:   February 28, 2005

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(DELOITTE LOGO)

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of
Southern Company

     We have audited the consolidated financial statements of Southern Company and Subsidiary Companies (the “Company”) as of December 31, 2004 and 2003, and for each of the three years in the period ended December 31, 2004, management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004, and the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004, and have issued our reports thereon dated February 28, 2005 (which report on the consolidated financial statements expresses an unqualified opinion and includes an explanatory paragraph concerning the adoption of a new accounting principle in 2003); such consolidated financial statements and reports are included elsewhere in this Form 10-K. Our audits also included the consolidated financial statement schedules of the Company (page S-2) listed in the accompanying index at Item 15. These consolidated financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion based on our audits. In our opinion, such consolidated financial statement schedules, when considered in relation to the 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
February 28, 2005

    Member of
Deloitte Touche Tohmatsu

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(DELOITTE LOGO)

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Alabama Power Company:

We have audited the financial statements of Alabama Power Company as of December 31, 2004 and 2003, and for each of the three years in the period ended December 31, 2004, and have issued our report thereon dated February 28, 2005 (which report expresses an unqualified opinion and includes an explanatory paragraph concerning the adoption of a new accounting principle in 2003); such financial statements and report are included elsewhere in this Form 10-K. Our audits also included the 2004 and 2003 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. In our opinion, the 2004 and 2003 financial statement schedules, when considered in relation to the 2004 and 2003 basic financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.

/s/ Deloitte & Touche LLP

Birmingham, Alabama
February 28, 2005

    Member of
Deloitte Touche Tohmatsu

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(DELOITTE LOGO)

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Georgia Power Company:

We have audited the financial statements of Georgia Power Company as of December 31, 2004 and 2003, and for each of the three years in the period ended December 31, 2004, and have issued our report thereon dated February 28, 2005 (which report expresses an unqualified opinion and includes an explanatory paragraph concerning the adoption of a new accounting principle in 2003); such financial statements and report are included elsewhere in this Form 10-K. Our audits also included the 2004 and 2003 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. In our opinion, the 2004 and 2003 financial statement schedules, when considered in relation to the 2004 and 2003 basic financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.

/s/ Deloitte & Touche LLP

Atlanta, Georgia
February 28, 2005

    Member of
Deloitte Touche Tohmatsu

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(DELOITTE LOGO)

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Gulf Power Company:

We have audited the financial statements of Gulf Power Company as of December 31, 2004 and 2003, and for each of the three years in the period ended December 31, 2004, and have issued our report thereon dated February 28, 2005 (which report expresses an unqualified opinion and includes an explanatory paragraph concerning the adoption of a new accounting principle in 2003); such financial statements and report are included elsewhere in this Form 10-K. Our audits also included the 2004 and 2003 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. In our opinion, the 2004 and 2003 financial statement schedules, when considered in relation to the 2004 and 2003 basic financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.

/s/ Deloitte & Touche LLP

Atlanta, Georgia
February 28, 2005

    Member of
Deloitte Touche Tohmatsu

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(DELOITTE LOGO)

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Mississippi Power Company:

We have audited the financial statements of Mississippi Power Company as of December 31, 2004 and 2003, and for each of the three years in the period ended December 31, 2004, and have issued our report thereon dated February 28, 2005 (which report expresses an unqualified opinion and includes an explanatory paragraph concerning the adoption of a new accounting principle in 2003); such financial statements and report are included elsewhere in this Form 10-K. Our audits also included the 2004 and 2003 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. In our opinion, the 2004 and 2003 financial statement schedules, when considered in relation to the 2004 and 2003 basic financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.

/s/ Deloitte & Touche LLP

Atlanta, Georgia
February 28, 2005

    Member of
Deloitte Touche Tohmatsu

IV-13


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(DELOITTE LOGO)

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Savannah Electric and Power Company:

We have audited the financial statements of Savannah Electric and Power Company as of December 31, 2004 and 2003, and for each of the three years in the period ended December 31, 2004, and have issued our report thereon dated February 28, 2005 (which report expresses an unqualified opinion and includes an explanatory paragraph concerning the adoption of a new accounting principle in 2003 and an explanatory paragraph related to the restatement described in Note 9); such financial statements and report are included elsewhere in this Form 10-K. Our audits also included the 2004 and 2003 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. In our opinion, the 2004 and 2003 financial statement schedules, when considered in relation to the 2004 and 2003 basic financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.

/s/ Deloitte & Touche LLP

Atlanta, Georgia
February 28, 2005

    Member of
Deloitte Touche Tohmatsu

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(DELOITTE LOGO)

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Southern Power Company:

We have audited the financial statements of Southern Power Company as of December 31, 2004 and 2003, and for each of the three years in the period ended December 31, 2004, and have issued our report thereon dated February 28, 2005 (which report expresses an unqualified opinion and includes an explanatory paragraph concerning the adoption of a new accounting principle in 2003); such financial statements and report are included elsewhere in this Form 10-K. Our audits also included the 2004 and 2003 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, the 2004 and 2003 financial statement schedules, when considered in relation to the 2004 and 2003 basic financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.

/s/ Deloitte & Touche LLP

Atlanta, Georgia
February 28, 2005

    Member of
Deloitte Touche Tohmatsu

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INDEX TO FINANCIAL STATEMENT SCHEDULES

         
Schedule   Page  
II Valuation and Qualifying Accounts and Reserves 2004, 2003 and 2002
       
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.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2004, 2003 AND 2002

(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
                                       
2004
  $30,331     $ 58,738     $         2     $ 42,971 (b)   $46,100  
2003
      26,648       56,376       14,901       67,594 (b)     30,331  
2002
      24,525       40,313       5,961 (a)     44,151 (b)     26,648  


(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.

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ALABAMA POWER COMPANY
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2004, 2003 AND 2002

(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
                                       
2004
  $4,756     $ 10,346     $—     $9,698 (Note)   $5,404  
2003
      4,827       13,444         —     13,515 (Note)     4,756  
2002
      5,237       10,804         —     11,214 (Note)     4,827  


Note:   Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off.

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GEORGIA POWER COMPANY
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2004, 2003 AND 2002

(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
                                       
2004
  $5,350     $20,461     $—     $18,711 (Note)   $7,100  
2003
    5,825       15,577       —     16,052 (Note)     5,350  
2002
    8,895       14,117       —     17,187 (Note)     5,825  


Note:   Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off.

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GULF POWER COMPANY
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2004, 2003 AND 2002

(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
                                       
2004
  $  947     $2,851     $—     $ 1,654 (Note)   $2,144  
2003
      889       2,122       —       2,064 (Note)        947  
2002
    1,342       1,620       —       2,073 (Note)        889  


Note:   Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off.

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MISSISSIPPI POWER COMPANY
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2004, 2003 AND 2002

(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
                                       
2004
  $897   $1,338   $—   $ 1,461 (Note)   $774  
2003
    718         1,947       135       1,903 (Note)     897  
2002
    856         2,045       7       2,190 (Note)     718  


Note:   Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off.

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SAVANNAH ELECTRIC AND POWER COMPANY
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2004, 2003 AND 2002

(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
                                       
2004
  $817   $ 930     $—   $869 (Note)     $878  
2003
    902     828        —       913 (Note)     817  
2002
    642   1,137        —       877 (Note)     902  


Note:   Represents write-off of accounts receivable considered to be uncollectible, less recoveries of amounts previously written off.

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SOUTHERN POWER COMPANY
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2004, 2003 AND 2002

(Stated in Thousands of Dollars)

                                         
            Additions                
    Balance at           Charged to           Balance at
    Beginning   Charged to   Other           End
Description   of Period   Income   Accounts   Deductions   of Period
 
Provision for uncollectible accounts
                                       
2004
  $ 350     $     $     $     $ 350  
2003
    350                         350  
2002
          350                   350  

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EXHIBIT INDEX

      The following exhibits indicated by an asterisk (*) preceding the exhibit number are filed herewith. The balance of the exhibits has 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.)
 
   
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-

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  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 August 20, 2003, and as presently in effect. (Designated in Georgia Power’s Form 10-Q for the quarter ended March 31, 2004, File No. 1-6468, as Exhibit 3(c)1.)
 
   
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 April 2, 2004. (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, in Mississippi Power’s Form 10-K for the year ended December 31, 2000, File No. 0-6849, as Exhibit 3(e)2 and in Mississippi Power’s Form 8-K dated March 3, 2004, File No. 0-6849, as Exhibit 4.6.)
 
   
(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.)

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Savannah Electric
 
   
(f)1-
  Charter of Savannah Electric and amendments thereto through June 10, 2004. (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) in Savannah Electric’s Form 10-K for the year ended December 31, 1998, as Exhibit 3(f)2 and in Form 8-K dated May 27, 2004, File No. 1-5072, as Exhibits 4.6 and 4.7.)
 
   
(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-
  By-laws 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 Bank of New York Trust Company, N.A., as Successor 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 Bank of New York Trust Company, N.A., as Successor 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.)
 
   
(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.)

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(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, N.A. (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.)
 
   
(b) 2 -
  Subordinated Note Indenture dated as of January 1, 1997, between Alabama Power and JPMorgan Chase Bank, N.A. (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.)

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(b) 3 -
  Senior Note Indenture dated as of December 1, 1997, between Alabama Power and JPMorgan Chase Bank, N.A. (formerly The Chase Manhattan Bank), as Trustee, and indentures supplemental thereto through November 16, 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, in Form 8-K dated February 10, 2004, File No. 1-3164, as Exhibit 4.2 in Form 8-K dated April 7, 2004, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated August 19, 2004, File No. 1-3164, as Exhibit 4.2 and in Form 8-K dated November 9, 2004, File No. 1-3164, as Exhibit 4.2.)
 
   
(b) 4 -
  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.)
 
   
(b) 5 -
  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) 6 -
  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) 7 -
  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 June 1, 1997, between Georgia Power and JPMorgan Chase Bank, N.A. (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

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  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) 2 -
  Senior Note Indenture dated as of January 1, 1998, between Georgia Power and JPMorgan Chase Bank, N.A. (formerly The Chase Manhattan Bank), as Trustee, and indentures supplemental thereto through January 20, 2005. (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, in Form 8-K dated February 12, 2004, File No. 1-6468, as Exhibit 4.1, in Form 8-K dated August 11, 2004, File No. 1-6468, as Exhibits 4.1 and 4.2 and in Form 8-K dated January 13, 2005, File No. 1-6468, as Exhibit 4.1.)
 
   
(c) 3 -
  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) 4 -
  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) 5 -
  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) 6 -
  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) 7 -
  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) 8 -
  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.)

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Gulf Power
 
   
(d) 1 -
  Indenture dated as of September 1, 1941, between Gulf Power and JPMorgan Chase Bank, N.A. (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.)
 
   
(d) 2 -
  Subordinated Note Indenture dated as of January 1, 1997, between Gulf Power and JPMorgan Chase Bank, N.A. (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, N.A. (formerly The Chase Manhattan Bank), as Trustee, and indentures supplemental thereto through September 22, 2004. (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, in Form 8-K dated September 5, 2003, File No. 0-2429, as Exhibit 4.1, in Form 8-K dated April 6, 2004, File No. 0-2429, as Exhibit 4.1 and in Form 8-K dated September 13, 2004, 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.)

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Table of Contents

     
(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 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 March 9, 2004. (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, in Form 8-K dated April 24, 2003, File No. 001-11229, as Exhibit 4.2 and in Form 8-K dated March 3, 2004, File No. 0-6849, 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.)

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Table of Contents

     
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 9, 2004. (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, in Form 8-K dated December 10, 2003, File No. 1-5072, as Exhibits 4.1 and 4.2 and in Form 8-K dated December 2, 2004, File No. 1-5072, as Exhibit 4.1.)
 
   
   (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 -
  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).)

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Table of Contents

     
  # (a) 2 -
  Deferred Compensation Plan for 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) 3 -
  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) 4 -
  Southern Company Deferred Compensation Plan as amended and restated January 1, 2004. (Designated in Southern Company’s Form 10-Q for the quarter ended June 30, 2004, File No. 1-3526, as Exhibit 10(a)1.)
 
   
  # (a) 5 -
  Outside Directors Stock Plan for The Southern Company and its Subsidiaries, effective May 26, 2004. (Designated in Southern Company’s Form 10-Q for the quarter ended June 30, 2004, File No. 1-3526, as Exhibit 10(a)2.)
 
   
  # (a) 6 -
  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) 7 -
  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) 8 -
  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) 9 -
  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) 10 -
  Amended and Restated Change in Control Agreement between Southern Company, Southern Nuclear and William G. Hairston, III, effective June 1, 2004. (Designated in Southern Company’s Form 10-Q for the quarter ended June 30, 2004, File No. 1-3526, as Exhibit 10(a)7.)
 
   
  # (a) 11 -
  Employment Agreement between Southern Nuclear and William G. Hairston, III, dated December 22, 2004. (Designated in Southern Company’s Form 8-K dated December 22, 2004, File No. 1-3526, as Exhibit 10.1.)
 
   
  # (a) 12 -
  Release and Restrictive Covenant Agreement between Southern Nuclear and William G. Hairston, III, dated December 22, 2004. (Designated in Southern Company’s Form 8-K dated December 22, 2004, File No. 1-3526, as Exhibit 10.2.)
 
   
# * (a) 13 -
  Amended and Restated Change in Control Agreement between Southern Company, SCS and G. Edison Holland, Jr.

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Table of Contents

     
# (a) 14 -
  Amended and Restated Change in Control Agreement between Southern Company, Alabama Power and Charles D. McCrary, effective June 1, 2004. (Designated in Southern Company’s Form 10-Q for the quarter ended June 30, 2004, File No. 1-3526, as Exhibit 10(a)5.)
 
   
# (a) 15 -
  Amended and Restated Change in Control Agreement between Southern Company, SCS and David M. Ratcliffe, effective June 1, 2004. (Designated in Southern Company’s Form 10-Q for the quarter ended June 30, 2004, File No. 1-3526, as Exhibit 10(a)3.)
 
   
# (a) 16 -
  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) 17 -
  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) 18 -
  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) 19 -
  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) 20 -
  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) 21 -
  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) 22 -
  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.)

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Table of Contents

     
  # (a) 23 -
  Amended and Restated Change in Control Agreement between Southern Company, SCS and Thomas A. Fanning, effective June 1, 2004. (Designated in Southern Company’s Form 10-Q for the quarter ended June 30, 2004, File No. 1-3526, as Exhibit 10(a)4.)
 
   
  # (a) 24 -
  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) 25 -
  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.)
 
   
  # (a) 26 -
  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) 27 -
  Amended and Restated Change in Control Agreement between Southern Company, Georgia Power and Michael D. Garrett, effective June 1, 2004. (Designated in Southern Company’s Form 10-Q for the quarter ended June 30, 2004, File No. 1-3526, as Exhibit 10(a)6.)
 
   
  # (a) 28 -
  Form Award Agreement setting forth terms of nonqualified stock option grants, made under the Southern Company Omnibus Incentive Compensation Plan as Amended and Restated effective May 23, 2001, to employees of The Southern Company and its subsidiaries. (Designated in Southern Company’s Form 10-Q for the quarter ended September 30, 2004, File No. 1-3526, as Exhibit 10(a)1.)
 
   
# * (a) 29 -
  Base Salaries of Named Executive Officers.
 
   
# * (a) 30 -
  Summary of Non-Employee Director Compensation Arrangements.
 
   
Alabama Power
 
   
      (b) 1 -
  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.)
 
   
   # (b) 2 -
  Southern Company Omnibus Incentive Compensation Plan, Amended and Restated effective May 23, 2001. See Exhibit 10(a)1 herein.
 
   
   # (b) 3 -
  Southern Company Deferred Compensation Plan as amended and restated January 1, 2004. See Exhibit 10(a)4 herein.
 
   
   # (b) 4 -
  The Southern Company Outside Directors Pension Plan. See Exhibit 10(a)3 herein.

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Table of Contents

     
# (b) 5 -
  Outside Directors Stock Plan for The Southern Company and its Subsidiaries, effective May 26, 2004. See Exhibit 10(a)5 herein.
 
   
# (b) 6 -
  The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective May 1, 2000. See Exhibit 10(a)6 herein.
 
   
# (b) 7 -
  The Southern Company Supplemental Benefit Plan, Amended and Restated effective May 1, 2000 and First Amendment thereto. See Exhibit 10(a)7 herein.
 
   
# (b) 8 -
  Southern Company Executive Change in Control Severance Plan, Amended and Restated effective May 1, 2003. See Exhibit 10(a)26 herein.
 
   
# (b) 9 -
  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) 10 -
  Southern Company Amended and Restated Change in Control Benefit Plan Determination Policy, effective May 9, 2002. See Exhibit 10(a)16 herein.
 
   
# (b) 11 -
  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)20 herein.
 
   
# (b) 12 -
  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)21 herein.
 
   
# (b) 13 -
  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)22 herein.
 
   
# (b) 14 -
  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.)
 
   
# (b) 15 -
  Southern Company Senior Executive Change in Control Severance Plan effective May 1, 2003. See Exhibit 10(a)25 herein.
 
   
# (b) 16 -
  Amended and Restated Change in Control Agreement between Southern Company, Alabama Power and Charles D. McCrary. See Exhibit 10(a)17 herein.
 
   
# (b) 17 -
  Amended and Restated Change in Control Agreement between Southern Company, Alabama Power and C. Alan Martin, effective June 1, 2004. (Designated in Southern Company’s Form 10-Q for the quarter ended June 30, 2004, File No. 1-3526, as Exhibit 10(b)4.)

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Table of Contents

     
#    (b) 18 -
  Form Award Agreement setting forth terms of nonqualified stock option grants, made under the Southern Company Omnibus Incentive Compensation Plan as Amended and Restated effective May 23, 2001, to employees of The Southern Company and its subsidiaries. See Exhibit 10(a)28 herein.
 
   
# * (b) 19 -
  Base Salaries of Named Executive Officers.
 
   
# * (b) 20 -
  Summary of Non-Employee Director Compensation Arrangements.
 
   
Georgia Power
 
   
(c) 1 -
  Interchange contract dated February 17, 2000, between Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric, Southern Power and SCS. See Exhibit 10(b)1 herein.
 
   
(c) 2 -
  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).)
 
   
(c) 3 -
  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).)
 
   
(c) 4 -
  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).)
 
   
# (c) 5 -
  Southern Company Omnibus Incentive Compensation Plan, Amended and Restated effective May 23, 2001. See Exhibit 10(a)1 herein.
 
   
# (c) 6 -
  Southern Company Deferred Compensation Plan as amended and restated effective January 1, 2004. See Exhibit 10(a)4 herein.
 
   
# (c) 7 -
  The Southern Company Outside Directors Pension Plan. See Exhibit 10(a)3 herein.
 
   
# (c) 8 -
  Outside Directors Stock Plan for The Southern Company and its Subsidiaries, effective May 26, 2004. See Exhibit 10(a)5 herein.
 
   
# (c) 9 -
  The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective May 1, 2000. See Exhibit 10(a)6 herein.
 
   
# (c) 10 -
  The Southern Company Supplemental Benefit Plan, Amended and Restated effective May 1, 2000 and First Amendment thereto. See Exhibit 10(a)7 herein.
 
   
# (c) 11 -
  Southern Company Executive Change in Control Severance Plan, Amended and Restated effective May 1, 2003. See Exhibit 10(a)26 herein.

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Table of Contents

     
# (c) 12 -
  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) 13 -
  Southern Company Amended and Restated Change in Control Benefit Plan Determination Policy, effective May 9, 2002. See Exhibit 10(a)16 herein.
 
   
# (c) 14 -
  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)20 herein.
 
   
# (c) 15 -
  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)21 herein.
 
   
# (c) 16 -
  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)22 herein.
 
   
# (c) 17 -
  Southern Company Senior Executive Change in Control Severance Plan effective May 1, 2003. See Exhibit 10(a)25 herein.
 
   
# (c) 18 -
  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.)
 
   
# (c) 19 -
  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.)
 
   
# (c) 20 -
  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.)
 
   
# (c) 21 -
  Amended and Restated Change in Control Agreement between Southern Company, Georgia Power and Michael D. Garrett. See Exhibit 10(a)27 herein.
 
   
# (c) 22 -
  Form Award Agreement setting forth terms of nonqualified stock option grants, made under the Southern Company Omnibus Incentive Compensation Plan as Amended and Restated effective May 23, 2001, to employees of The Southern Company and its subsidiaries. See Exhibit 10(a)28 herein.
 
   
# * (c) 23 -
  Base Salaries of Named Executive Officers.

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Table of Contents

       
# *
(c) 24 -
  Summary of Non-Employee Director Compensation Arrangements.
 
     
Gulf Power
 
   
 
(d) 1 -
  Interchange contract dated February 17, 2000, between Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric, Southern Power and SCS. See Exhibit 10(b)1 herein.
 
     
 
(d) 2 -
  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).)
 
     
 
(d) 3 -
  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).)
 
     
 
(d) 4 -
  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).)
 
     
#
(d) 5 -
  Southern Company Omnibus Incentive Compensation Plan, Amended and Restated effective May 23, 2001. See Exhibit 10(a)1 herein.
 
     
#
(d) 6 -
  Southern Company Deferred Compensation Plan as amended and restated January 1, 2004. See Exhibit 10(a)4 herein.
 
     
#
(d) 7 -
  The Southern Company Outside Directors Pension Plan. See Exhibit 10(a)3 herein.
 
   
#
(d) 8 -
  Outside Directors Stock Plan for The Southern Company and its Subsidiaries, effective May 26, 2004. See Exhibit 10(a)9 herein.
 
     
#
(d) 9 -
  The Southern Company Supplemental Benefit Plan, Amended and Restated effective May 1, 2000 and First Amendment thereto. See Exhibit 10(a)7 herein.
 
     
#
(d) 10 -
  Southern Company Executive Change in Control Severance Plan, Amended and Restated effective May 1, 2003. See Exhibit 10(a)25 herein.
 
     
#
(d) 11 -
  The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective May 1, 2000. See Exhibit 10(a)6 herein.
 
   
#
(d) 12 -
  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.)

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Table of Contents

     
# (d) 13 -
  Southern Company Amended and Restated Change in Control Benefit Plan Determination Policy, effective May 9, 2002. See Exhibit 10(a)16 herein.
 
   
# (d) 14 -
  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)20 herein.
 
   
# (d) 15 -
  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)21 herein.
 
   
# (d) 16 -
  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)22 herein.
 
   
# (d) 17 -
  Southern Company Senior Executive Change in Control Severance Plan effective May 1, 2003. See Exhibit 10(a)25 herein.
 
   
# (d) 18 -
  Form Award Agreement setting forth terms of nonqualified stock option grants, made under the Southern Company Omnibus Incentive Compensation Plan as Amended and Restated effective May 23, 2001, to employees of The Southern Company and its subsidiaries. See Exhibit 10(a)28 herein.
 
   
# * (d) 19 -
  Base Salaries of Named Executive Officers.
 
   
# * (d) 20 -
  Summary of Non-Employee Director Compensation Arrangements.
 
   
Mississippi Power
 
   
       (e) 1 -
  Interchange contract dated February 17, 2000, between Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric, Southern Power and SCS. See Exhibit 10(b)1 herein.
 
   
       (e) 2 -
  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).)
 
   
    # (e) 3 -
  Southern Company Omnibus Incentive Compensation Plan, Amended and Restated effective May 23, 2001. See Exhibit 10(a)1 herein.

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Table of Contents

     
# (e) 4 -
  Southern Company Deferred Compensation Plan as amended and restated January 1, 2004. See Exhibit 10(a)4 herein.
 
   
# (e) 5 -
  The Southern Company Outside Directors Pension Plan. See Exhibit 10(a)3 herein.
 
   
# (e) 6 -
  Outside Directors Stock Plan for The Southern Company and its Subsidiaries, effective May 26, 2004. See Exhibit 10(a)5 herein.
 
   
# (e) 7 -
  The Southern Company Supplemental Benefit Plan, Amended and Restated effective May 1, 2000 and First Amendment thereto. See Exhibit 10(a)7 herein.
 
   
# (e) 8 -
  Southern Company Executive Change in Control Severance Plan, Amended and Restated effective May 1, 2003. See Exhibit 10(a)26 herein.
 
   
# (e) 9 -
  The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective May 1, 2000. See Exhibit 10(a)6 herein.
 
   
# (e) 10 -
  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) 11 -
  Southern Company Amended and Restated Change in Control Benefit Plan Determination Policy, effective May 9, 2002. See Exhibit 10(a)16 herein.
 
   
# (e) 12 -
  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)20 herein.
 
   
# (e) 13 -
  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)21 herein.
 
   
# (e) 14 -
  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)22 herein.
 
   
# (e) 15 -
  Southern Company Senior Executive Change in Control Severance Plan effective May 1, 2003. See Exhibit 10(a)25 herein.
 
   
# (e) 16 -
  Form Award Agreement setting forth terms of nonqualified stock option grants, made under the Southern Company Omnibus Incentive Compensation Plan as Amended and Restated effective May 23, 2001, to employees of The Southern Company and its subsidiaries. See Exhibit 10(a)28 herein.

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Table of Contents

     
#    (e) 17 -
  Separation Agreement between Mississippi Power and Don E. Mason dated July 26, 2004. (Designated in Mississippi Power’s Form 10-Q for the quarter ended September 30, 2004, File No. 0-6849 as Exhibit 10(e)(2).)
 
   
#    (e) 18 -
  Consulting Agreement dated January 3, 2005 between the Company and Don E. Mason. (Designated in Form 8-K dated January 3, 2005, File No. 0-6849, as Exhibit 10.1.)
 
   
# * (e) 19 -
  Base Salaries of Named Executive Officers.
 
   
# * (e) 20 -
  Summary of Non-Employee Director Compensation Arrangements.
 
   
Savannah Electric
 
   
      (f) 1 -
  Interchange contract dated February 17, 2000, between Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric, Southern Power and SCS. See Exhibit 10(b)1 herein.
 
   
   # (f) 2 -
  Southern Company Omnibus Incentive Compensation Plan, Amended and Restated effective May 23, 2001. See Exhibit 10(a)1 herein.
 
   
   # (f) 3 -
  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) 4 -
  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) 5 -
  The Southern Company Outside Directors Pension Plan. See Exhibit 10(a)3 herein.
 
   
   # (f) 6 -
  1997 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) 7 -
  Outside Directors Stock Plan for The Southern Company and its Subsidiaries, effective May 26, 2004. See Exhibit 10(a)5 herein.
 
   
   # (f) 8 -
  The Southern Company Supplemental Benefit Plan, Amended and Restated effective May 1, 2000 and First Amendment thereto. See Exhibit 10(a)7 herein.
 
   
   # (f) 9 -
  Southern Company Executive Change in Control Severance Plan, Amended and Restated effective May 1, 2003. See Exhibit 10(a)26 herein.
 
   
   # (f) 10 -
  Southern Company Deferred Compensation Plan, as amended and restated January 1, 2004. See Exhibit 10(a)4 herein.

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Table of Contents

     
# (f) 11 -
  The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective May 1, 2000. See Exhibit 10(a)6 herein.
 
   
# (f) 12 -
  Southern Company Amended and Restated Change in Control Benefit Plan Determination Policy, effective May 9, 2002. See Exhibit 10(a)16 herein.
 
   
# (f) 13 -
  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) 14 -
  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) 15 -
  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)20 herein.
 
   
# (f) 16 -
  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)21 herein.
 
   
# (f) 17 -
  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)22 herein.
 
   
# (f) 18 -
  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.)
 
   
# (f) 19 -
  Southern Company Senior Executive Change in Control Severance Plan effective May 1, 2003. See Exhibit 10(a)25 herein.
 
   
# (f) 20 -
  Savannah Electric and Power Company Change in Control Plan Benefit Determination Policy, effective October 26, 2000. (Designated in Savannah Electric’s Form 10-K for the year ended December 31, 2003, File No. 1-5072, as Exhibit 10(f)34.)
 
   
# (f) 21 -
  Form Award Agreement setting forth terms of nonqualified stock option grants, made under the Southern Company Omnibus Incentive Compensation Plan as Amended and Restated effective May 23, 2001, to employees of The Southern Company and its subsidiaries. See Exhibit 10(a)28 herein.
 
   
# * (f) 22 -
  Base Salaries of Named Executive Officers.
 
   
# * (f) 23 -
  Summary of Non-Employee Director Compensation Arrangements.

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Table of Contents

     
Southern Power
 
   
(g) 1 -
  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).)
 
   
(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(b)1 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. (Designated in Southern Company’s Form 10-Q for the quarter ended March 31, 2003, File No. 1-3526, as Exhibit 10(a)1.)
 
   
(g) 4 -
  Amended and Restated Operating Agreement between Southern Power and Alabama Power effective December 1, 2002. (Designated in Southern Company’s Form 10-K for the year ended December 31, 2003, File No. 1-3526, as Exhibit 10(a)61.)
 
   
(g) 5 -
  Amended and Restated Operating Agreement between Southern Power and Georgia Power effective December 1, 2002. (Designated in Southern Company’s Form 10-K for the year ended December 31, 2003, File No. 1-3526, as Exhibit 10(a)62.)
 
   
(g) 6 -
  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.)
 
   
(g) 7 -
  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.)
 
   
(g) 8 -
  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.)
 
   
(g) 9 -
  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.)

(14)   Code of Ethics
     
Southern Company
 
   
(a) -
  The Southern Company Code of Ethics. (Designated in Southern Company’s Form 10-K for the year ended December 31, 2003, File No. 1-3526, as Exhibit 14(a).)
 
   
Alabama Power
 
   
(b) -
  The Southern Company Code of Ethics. See Exhibit 14(a) herein.

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Table of Contents

     
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.
 
   
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.

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Table of Contents

(23)   Consents of Experts and Counsel
     
Southern Company
 
   
* (a) 1 -
  Consent of Deloitte & Touche LLP.
 
   
Alabama Power
 
   
* (b) 1 -
  Consent of Deloitte & Touche LLP.
 
   
Georgia Power
 
   
* (c) 1 -
  Consent of Deloitte & Touche LLP.
 
   
Gulf Power
 
   
* (d) 1 -
  Consent of Deloitte & Touche LLP.
 
   
Mississippi Power
 
   
* (e) 1 -
  Consent of Deloitte & Touche LLP.
 
   
Savannah Electric
 
   
* (f) 1 -
  Consent of Deloitte & Touche LLP.

(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.

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Table of Contents

     
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.
 
   
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.

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Table of Contents

     
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.

(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-25